10-K 1 cog-12312014x10k.htm 10-K COG-12.31.2014-10K


 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2014
Commission file number 1-10447
CABOT OIL & GAS CORPORATION
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
 
04-3072771
(I.R.S. Employer
Identification Number)
Three Memorial City Plaza, 840 Gessner Road, Suite 1400, Houston, Texas 77024
(Address of principal executive offices including ZIP code)

(281) 589-4600
(Registrant's telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
Common Stock, par value $.10 per share
 
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý    No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o    No ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý    No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K ý.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer
ý
Accelerated filer
o
 
Non-accelerated filer
(Do not check if a
smaller reporting company)
o
Smaller reporting company
o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o    No ý
The aggregate market value of Common Stock, par value $.10 per share ("Common Stock"), held by non-affiliates as of the last business day of registrant's most recently completed second fiscal quarter (based upon the closing sales price on the New York Stock Exchange on June 30, 2014) was approximately $14.2 billion.
As of February 13, 2015, there were 413,170,529 shares of Common Stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held April 23, 2015 are incorporated by reference into Part III of this report.
 



TABLE OF CONTENTS
 
 
PAGE
 
 
 
 
 
 
 
 
 

2


FORWARD-LOOKING INFORMATION
The statements regarding future financial and operating performance and results, strategic pursuits and goals, market prices, future hedging activities, and other statements that are not historical facts contained in this report are forward-looking statements. The words "expect," "project," "estimate," "believe," "anticipate," "intend," "budget," "plan," "forecast," "predict," "may," "should," "could," "will" and similar expressions are also intended to identify forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including geographic basis differentials) of natural gas and crude oil, results of future drilling and marketing activity, future production and costs, legislative and regulatory initiatives, electronic, cyber or physical security breaches and other factors detailed herein and in our other Securities and Exchange Commission filings. See "Risk Factors" in Item 1A for additional information about these risks and uncertainties. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated.
GLOSSARY OF CERTAIN OIL AND GAS TERMS
The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry and included within this Annual Report on Form 10-K:
Abbreviations
Bbl.    One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
Bcf.    One billion cubic feet of natural gas.
Bcfe.    One billion cubic feet of natural gas equivalent.
Btu.    One British thermal unit.
Dth.    One million British thermal units.
Mbbls.    One thousand barrels of oil or other liquid hydrocarbons.
Mcf.    One thousand cubic feet of natural gas.
Mcfe.    One thousand cubic feet of natural gas equivalent.
MMbbls.    One million barrels of oil or other liquid hydrocarbons.
Mmbtu.    One million British thermal units.
Mmcf.    One million cubic feet of natural gas.
Mmcfe.    One million cubic feet of natural gas equivalent.
NGL.    Natural gas liquids.
NYMEX.    New York Mercantile Exchange.
Definitions
Conventional play.    A term used in the oil and gas industry to refer to an area believed to be capable of producing crude oil and natural gas occurring in discrete accumulations in structural and stratigraphic traps utilizing conventional recovery methods.
Developed reserves.    Developed reserves are reserves that can be expected to be recovered: (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Development well.    A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
Differential.    An adjustment to the price of oil or gas from an established spot market price to reflect differences in the quality and/or location of oil or gas.

3


Dry hole.    Exploratory or development well that does not produce oil or gas in commercial quantities.
Exploitation activities.    The process of the recovery of fluids from reservoirs and drilling and development of oil and gas reserves.
Exploratory well.    A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, or a service well.
Extension well.    An extension well is a well drilled to extend the limits of a known reservoir.
Field.    An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local geological barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.
Oil.    Crude oil and condensate.
Operator.    The individual or company responsible for the exploration, development and/or production of an oil or gas well or lease.
Play.    A geographic area with potential oil and gas reserves.
Possible reserves.    Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
Probable reserves.    Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely not to be recovered.
Production costs.    Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities, which become part of the cost of oil and gas produced.
Proved properties.    Properties with proved reserves.
Proved reserves.    Proved reserves are those quantities, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions and operating methods prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Recompletion.    An operation whereby a completion in one zone is abandoned in order to attempt a completion in a different zone within the existing wellbore.
Reliable technology.    A grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonable certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
Reserves.    Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

4


Reservoir.    A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Resources.    Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.
Royalty interest.    An interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowners' royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
Shale.    Fine-grained sedimentary rock composed mostly of consolidated clay or mud.
Standardized measure.    The present value, discounted at 10% per year, of estimated future net revenues from the production of proved reserves, computed by applying sales prices used in estimating proved oil and gas reserves to the year-end quantities of those reserves in effect as of the dates of such estimates and held constant throughout the productive life of the reserves (except for consideration of future price changes to the extent provided by contractual arrangements in existence at year-end), and deducting the estimated future costs to be incurred in developing, producing and abandoning the proved reserves (computed based on year-end costs and assuming continuation of existing economic conditions). Future income taxes are calculated by applying the appropriate year-end statutory federal and state income tax rate with consideration of future tax rates already legislated, to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to proved oil and gas reserves.
Unconventional play.    A term used in the oil and gas industry to refer to a play in which the targeted reservoirs generally fall into one of three categories: (1) tight sands, (2) coal beds or (3) shales. The reservoirs tend to cover large areas and lack the readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These reservoirs generally require fracture stimulation treatments or other special recovery processes in order to achieve economic flow rates.
Undeveloped reserves.    Undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
Unproved properties.    Properties with no proved reserves.
Working interest.    An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

5


PART I
ITEMS 1 and 2. BUSINESS AND PROPERTIES
Cabot Oil & Gas Corporation is an independent oil and gas company engaged in the development, exploitation and exploration of oil and gas properties. Our assets are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs. We operate in one segment, natural gas and oil development, exploitation, exploration and production, in the continental United States. We have regional offices located in Houston, Texas and Pittsburgh, Pennsylvania.
STRATEGY
Our objective is to enhance shareholder value over the long-term through consistent growth in cash flows, earnings, production and reserves. We believe this is attainable through a combination of disciplined management and our core asset base that offers a strategic advantage for continued growth. Key components of our business strategy include:
Disciplined Capital Spending Focused on Organic Projects.    We allocate our capital program based on projects that we expect will enable us to maximize our production and reserve growth at attractive returns. Our capital program is based on the expectation of being fully funded through operating cash flows, with any shortfalls funded by borrowings under our revolving credit facility. While we consider various growth opportunities, including strategic acquisitions, our primary focus is organic growth through drilling our core areas of operation where we believe we can exploit our extensive inventory of low-cost, repeatable drilling opportunities.
Low Cost Structure.    Our operations are focused on select unconventional plays with significant resource potential that allow us to add and produce reserves at a low cost. We have developed sizable, contiguous acreage positions in these core operating areas and believe the concentration of our assets allows us to further reduce costs through economies of scale. We continue to optimize drilling and completion efficiencies through the use of multi-well pad drilling in our core operating areas, resulting in additional cost savings. Furthermore, since we operate in a limited number of geographic areas, we believe we can leverage our technical expertise in these areas to achieve further cost reductions through operational efficiencies. We also operate a majority of our properties, which allows us to more effectively manage all elements of our cost structure.
Conservative Financial Position and Financial Flexibility.    We believe the prudent management of our balance sheet and the active management of commodity price risk allows us the financial flexibility to continue to provide consistent production and reserve growth over time, even in periods of depressed commodity prices. We utilize derivative contracts to manage commodity price risk and to provide a level of cash flow predictability. In the event we experience a lower than anticipated commodity price environment, we believe that we have the flexibility to supplement the funding of our capital program with borrowings under our revolving credit facility and select asset sales.
Expand our Unconventional Resource Initiatives.    We will continue to evaluate opportunities that generate value and contribute to our growth initiatives, including new exploration concepts and ideas that, if successful, can match the size, scope and rate of returns of our existing core assets. We will also consider the use of joint venture arrangements to achieve these objectives.
2015 OUTLOOK
In 2015, we plan to spend approximately $900.0 million on capital and exploration activities. We plan to drill approximately 125 gross wells (or 115.0 net), focusing our capital program in the Marcellus Shale in northeast Pennsylvania and the Eagle Ford Shale in south Texas. We expect to allocate approximately 59% of our 2015 capital program to the Marcellus Shale, approximately 39% to our oil-focused play in the Eagle Ford Shale and the remaining 2% to other emerging plays and non-drilling expenditures. Due to the weak commodity price environment, our overall capital and exploration spending in 2015 is expected to be lower than our expenditures in 2014.
Incremental to our capital and exploration expenditures program, we also expect to contribute approximately $69.8 million to our equity method investments to fund costs associated with the development and construction of two natural gas pipelines in northeast Pennsylvania. See Note 4 of the Notes to the Consolidated Financial Statements for further details regarding our equity method investments in Constitution Pipeline Company, LLC (Constitution) and Meade Pipeline Co LLC (Meade).

6


DESCRIPTION OF PROPERTIES
Our exploration, development and production operations are primarily concentrated in two unconventional plays—the Marcellus Shale in northeast Pennsylvania and the Eagle Ford Shale in south Texas. We also have operations in various other unconventional and conventional plays throughout the continental United States.
Marcellus Shale
Our Marcellus Shale properties represent our largest operating and growth area in terms of reserves, production and capital investment. Our properties are principally located in Susquehanna County and to a lesser extent Wyoming County, Pennsylvania. We currently hold approximately 200,000 net acres in the dry gas window of the play. Our 2014 net production in the Marcellus Shale was 479.8 Bcfe, representing approximately 90% of our total equivalent production for the year. As of December 31, 2014, we had a total of 469.0 net wells in the Marcellus Shale, the majority of which are operated by us.
During 2014, we invested $979.5 million in the Marcellus Shale and drilled 114.4 net horizontal wells and turned in line 97.0 net wells. As of December 31, 2014, we had 47.3 net wells that were either in the completion stage or waiting on completion or connection to a pipeline. We exited 2014 with six drilling rigs operating in the play and plan to exit 2015 with three rigs operating.
Eagle Ford Shale
Our properties in the Eagle Ford Shale are principally located in Atascosa, Frio and La Salle Counties, Texas, where we hold approximately 89,000 net acres in the oil window of the play. In 2014, our net crude oil/condensate/NGL and natural gas production from the Eagle Ford Shale was 3,799 Mbbl and 1.5 Bcf, respectively, or 24.3 Bcfe, representing approximately 5% of our full year total equivalent production. As of December 31, 2014, we had a total of 167.2 net wells in the Eagle Ford.
During 2014, we invested $542.4 million (excluding acquisitions) in the Eagle Ford Shale and drilled or participated in drilling 61.2 net wells. We also expanded our position in the play with the acquisition of certain proved and unproved properties for cash consideration of approximately $214.7 million. We exited 2014 with four drilling rigs operating in the play and plan to exit 2015 with one rig operating.
Other Oil and Gas Properties
In addition to our core unconventional resource plays, we also operate or participate in other conventional and unconventional plays throughout the continental United States, including the Utica Shale in Pennsylvania; the Cotton Valley, Haynesville, Bossier, and James Lime formations in east Texas; and the Devonian Shale, Big Lime, Weir and Berea in West Virginia.
Other Properties
Ancillary to our exploration, development and production operations, we operate a number of gas gathering and transmission pipeline systems, made up of approximately 3,100 miles of pipeline with interconnects to three interstate transmission systems and four local distribution companies and numerous end users as of the end of 2014. The majority of our pipeline infrastructure is located in West Virginia and is regulated by the Federal Energy Regulatory Commission (FERC) for interstate transportation service and the West Virginia Public Service Commission (WVPSC) for intrastate transportation service. As such, the transportation rates and terms of service of our pipeline subsidiary, Cranberry Pipeline Corporation, are subject to the rules and regulations of the FERC and the WVPSC. Our natural gas gathering and transmission pipeline systems in West Virginia enable us to connect new wells quickly and to transport natural gas from the wellhead directly to interstate pipelines, local distribution companies and industrial end users. Control of our gathering and transmission pipeline systems also enables us to purchase, transport and sell natural gas produced by third parties. In addition, we can engage in development drilling without relying upon third parties to transport our natural gas and incur only the incremental costs of pipeline and compressor additions to our system.
We also have two natural gas storage fields located in West Virginia with a combined working capacity of approximately 4 Bcf. We use these storage fields to take advantage of the seasonal variations in the demand for natural gas typically associated with winter natural gas sales, while maintaining production at a nearly constant rate throughout the year. The pipeline systems and storage fields are fully integrated with our operations in West Virginia.

7


ACQUISITIONS
In December 2014, we completed the acquisition of certain proved and unproved oil and gas properties located in the Eagle Ford Shale in south Texas for approximately $30.5 million, subject to post closing adjustments. Total cash consideration paid as of the closing date was approximately $29.6 million, which reflects the impact of customary purchase price adjustments and acquisition costs.
In October 2014, we purchased certain proved and unproved oil and gas properties located in the Eagle Ford Shale in south Texas for approximately $210.0 million. Total cash consideration paid as of the closing date was approximately $185.2 million, which reflects the impact of customary purchase price adjustments, an adjustment for consents that the seller was unable to obtain for certain leaseholds prior to closing and acquisition costs.
DIVESTITURES
In October 2014, we sold certain proved and unproved oil and gas properties in east Texas to a third party for approximately $44.3 million and recognized a $19.9 million gain on sale of assets.
In December 2013, we sold certain proved and unproved oil and gas properties located in the Oklahoma and Texas panhandles to Chaparral Energy, L.L.C. for approximately $160.0 million and recognized a $19.4 million gain on sale of assets. We also sold certain proved and unproved oil and gas properties located in Oklahoma, Texas and Kansas to a third party for approximately $123.4 million and recognized a $17.5 million loss on sale of assets.
In 2013, we sold various other proved and unproved oil and gas properties for approximately $44.3 million and recognized an aggregate net gain of $19.5 million.
In December 2012, we sold certain proved oil and gas properties located in south Texas to a private company for $29.9 million and recognized an $18.2 million loss on sale of assets.
In June 2012, we sold a 35% non-operated working interest associated with certain of our Pearsall Shale undeveloped leaseholds in south Texas to a wholly-owned subsidiary of Osaka Gas Co., Ltd. for $125.0 million and recognized a $67.0 million gain on sale of assets.
In 2012, we sold various other unproved oil and gas properties and other assets for approximately $14.4 million and recognized an aggregate net gain of $1.8 million.
In 2011, we sold certain proved and unproved oil and gas properties and other assets for approximately $405.5 million and recognized an aggregate net gain of $63.4 million.
In 2010, we various other proved and unproved oil and gas properties and other assets for approximately $182.2 million and recognized an aggregate net gain of $65.6 million.
MARKETING
Substantially all of our natural gas is sold at market sensitive prices under both long-term and short-term sales contracts. The principal markets for our natural gas are in the northeastern United States and the industrialized Gulf Coast area. In the northeastern United States, we sell natural gas to industrial customers, local distribution companies and gas marketers both on and off our pipeline and gathering system. In the Gulf Coast area, we sell natural gas to intrastate pipelines, natural gas processors and marketing companies. Properties in the Gulf Coast area are connected to various processing plants in Texas and Louisiana with multiple interstate and intrastate deliveries, affording us access to multiple markets.
We also incur transportation and gathering expenses to move our natural gas production from the wellhead to our principal markets in the United States. The majority of our natural gas production is transported on third-party gathering systems and interstate pipelines where we have long-term contractual capacity arrangements or through the use of purchaser-owned capacity under both long-term and short-term sales contracts.
To date, we have not experienced significant difficulty in transporting or marketing our natural gas production as it becomes available; however, there is no assurance that we will always be able to transport and market all of our production or obtain favorable prices.

8


RISK MANAGEMENT
From time to time, we use certain derivative financial instruments to manage price risk associated with our natural gas and crude oil production. While there are many different types of derivatives available, we generally utilize collar and swap agreements to attempt to manage price risk more effectively. The collar arrangements are a combination of put and call options used to establish floor and ceiling prices for a fixed volume of natural gas or crude oil production during a certain time period. They provide for payments to counterparties if the index price exceeds the ceiling and payments from the counterparties if the index price falls below the floor. The swap agreements call for payments to, or receipts from, counterparties based on whether the index price for the period is greater or less than the fixed price established for the particular period under the swap agreement.
During 2014, natural gas collars with floor prices ranging from $3.60 to $4.37 per Mcf and ceiling prices ranging from $4.22 to $4.80 per Mcf covered 336.8 Bcf, or 66%, of our natural gas production at an average price of $4.37 per Mcf. Natural gas swaps covered 102.2 Bcf, or 20%, of our natural gas production at an average price of $4.06 per Mcf. Crude oil swaps covered 612 Mbbl, or 17%, of our crude oil production at an average price $97.00 per Bbl.
As of December 31, 2014, we had the following outstanding commodity derivatives:
 
 
 
 
 
 
 
Collars
 
Swaps
 
 
 
 
 
 
 
Floor
 
Ceiling
 
 
Type of Contract
 
Volume
 
Contract Period
 
Range
 
Weighted-
Average
 
Range
 
Weighted-
Average
 
Weighted-
Average
Natural gas
 
70.9

Bcf
 
Jan. 2015 - Dec. 2015
 
$3.86 - $3.91
 
$
3.87

 
$4.27 - $4.43
 
$
4.35

 
 

Natural gas
 
70.9

Bcf
 
Jan. 2015 - Dec. 2015
 
 
 
 

 
 
 
 

 
$
3.92

Natural gas
 
5.2

Bcf
 
Jan. 2015 - Mar. 2015
 
 
 
 
 
 
 
 
 
$
4.62

Natural gas
 
10.4

Bcf
 
Apr. 2015 - Oct. 2015
 
 
 
 
 
 
 
 
 
$
3.86

In the above table, natural gas prices are stated per Mcf.
We will continue to evaluate the benefit of using derivatives in the future. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Quantitative and Qualitative Disclosures about Market Risk" for further discussion related to our use of derivatives.

9


RESERVES
The following table presents our estimated proved reserves for the periods indicated:
 
December 31,
 
2014
 
2013
 
2012
Natural Gas (Bcf)
 

 
 

 
 

Proved developed reserves
4,339

 
3,147

 
2,216

Proved undeveloped reserves(1)
2,743

 
2,148

 
1,480

 
7,082

 
5,295

 
3,696

Crude Oil & NGLs (Mbbl)(2)
 

 
 

 
 

Proved developed reserves
27,221

 
13,652

 
12,828

Proved undeveloped reserves(1)
25,915

 
12,886

 
11,546

 
53,136

 
26,538

 
24,374

 
 
 
 
 
 
Natural gas equivalent (Bcfe)(3)
7,401

 
5,454

 
3,842

Reserve life index (in years)(4)
13.9

 
13.2

 
14.4

_______________________________________________________________________________
(1)
Proved undeveloped reserves for 2014, 2013 and 2012 include reserves drilled but awaiting completion of 501.1 Bcfe, 239.1 Bcfe and 153.3 Bcfe, respectively.
(2)
NGL reserves were less than 1.0% of our total proved equivalent reserves for 2014, 2013 and 2012, and 13.5%, 12.3% and 8.7% of our proved crude oil and NGL reserves for 2014, 2013 and 2012, respectively.
(3)
Natural gas equivalents are determined using a ratio of 6 Mcf of natural gas to 1 Bbl of crude oil, condensate or NGLs.
(4)
Reserve life index is equal to year-end proved reserves divided by annual production for the years ended December 31, 2014, 2013 and 2012, respectively.
Our proved reserves totaled approximately 7,401 Bcfe at December 31, 2014, of which 96% were natural gas. This reserve level was up by 36% from 5,454 Bcfe at December 31, 2013. In 2014, we added 1,910.6 Bcfe of proved reserves through extensions, discoveries and other additions, primarily due to the positive results from our drilling program in the Dimock field in northeast Pennsylvania. We also had a net upward revision of 493.0 Bcfe, which was primarily due to an upward performance revision of 492.1 Bcfe, primarily in the Dimock field in northeast Pennsylvania and an upward revision of 0.9 Bcfe associated with commodity pricing. In 2014, we produced 531.8 Bcfe and purchased 77.0 Bcfe associated with the acquisitions of oil and gas properties in south Texas.
Our reserves are sensitive to natural gas and crude oil prices and their effect on the economic productive life of producing properties. Our reserves are based on 12-month average crude oil and natural gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month during the year. Increases in commodity prices may result in a longer economic productive life of a property or result in more economically viable proved undeveloped reserves to be recognized. Decreases in prices may result in negative impacts of this nature.
For additional information regarding estimates of proved reserves, the audit of such estimates by Miller and Lents, Ltd. (Miller and Lents) and other information about our reserves, including the risks inherent in our estimates of proved reserves, see the Supplemental Oil and Gas Information to the Consolidated Financial Statements included in Item 8 and “Risk Factors-Our proved 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.
Technologies Used In Reserves Estimates
We utilize various traditional methods to estimate our crude oil and natural gas reserves, including decline curve extrapolations, material balance calculations, volumetric calculations and analogies, and in some cases a combination of these methods. In addition, at times we may use seismic interpretations to confirm continuity of a formation in combination with traditional technologies; however, the seismic interpretations are not used in the volumetric computation.

10


Internal Control
Our Vice President, Engineering and Technology is the technical person responsible for our internal reserves estimation process and provides oversight of our corporate reservoir engineering department, which consists of three engineers, and the annual audit of our year-end reserves by our independent third party engineers. He has a Bachelor of Science degree in Chemical Engineering, specializing in petroleum engineering, and over 32 years of industry experience with positions of increasing responsibility in operations, engineering and evaluations. He has worked in the area of reserves and reservoir engineering for 23 years and is a member of the Society of Petroleum Engineers.
Our reserves estimation process is coordinated by our corporate reservoir engineering department. Reserve information, including models and other technical data, are stored on secured databases on our network. Certain non-technical inputs used in the reserves estimation process, including commodity prices, production and development costs and ownership percentages, are obtained by other departments and are subject to testing as part of our annual internal control process. We also engage Miller and Lents, independent petroleum engineers, to perform an independent audit of our estimated proved reserves. Upon completion of the process, the estimated reserves are presented to senior management, including the Chairman, President and Chief Executive Officer and Executive Vice President and Chief Financial Officer for approval.
Miller and Lents made independent estimates for 100% of our proved reserves estimates and concluded, in their judgment, we have an effective system for gathering data and documenting information required to estimate our proved reserves and project our future revenues. Further, Miller and Lents has concluded (1) the reserves estimation methods employed by us were appropriate, and our classification of such reserves was appropriate to the relevant SEC reserve definitions, (2) our reserves estimation processes were comprehensive and of sufficient depth, (3) the data upon which we relied were adequate and of sufficient quality, and (4) the results of our estimates and projections are, in the aggregate, reasonable. A copy of the audit letter by Miller and Lents dated February 2, 2015, has been filed as an exhibit to this Form 10-K.
Qualifications of Third Party Engineers
The technical person primarily responsible for the audit of our reserves estimates at Miller and Lents meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Miller and Lents is an independent firm of petroleum engineers, geologists, geophysicists, and petro physicists; they do not own an interest in our properties and are not employed on a contingent fee basis.
Proved Undeveloped Reserves
At December 31, 2014 we had 2,898.3 Bcfe of proved undeveloped (PUD) reserves associated with future development costs of $2.2 billion, which represents an increase of 672.5 Bcfe compared to December 31, 2013. As of December 31, 2014, all proved undeveloped reserves are expected to be developed within five years of initial disclosure of these reserves.
The following table is a reconciliation of the change in our PUD reserves (Bcfe):
 
Year Ended 
 December 31, 2014
Balance at beginning of period
2,225.8

Transfers to proved developed
(656.0
)
Additions
1,031.9

Revision of prior estimates
230.2

Purchases of reserves in place
66.4

Balance at end of period
2,898.3

Changes in PUD reserves that occurred during the year were due to:
transfer of 656.0 Bcfe from PUD to proved developed reserves based on total capital expenditures of $670.0 million during 2014;
new PUD reserve additions of 1,031.9 Bcfe primarily in the Dimock field in northeast Pennsylvania;
positive PUD reserve revisions of 230.2 Bcfe resulting from positive performance revisions of 222.3 Bcfe, primarily in the Dimock field in northeast Pennsylvania and positive price revisions of 7.9 Bcfe; and

11


purchases of reserves in place of 66.4 Bcfe related to oil and gas properties acquired in the Eagle Ford Shale.
PRODUCTION, SALES PRICE AND PRODUCTION COSTS
The following table presents historical information about our production volumes for natural gas and oil (including NGLs), average natural gas and crude oil sales prices, and average production costs per equivalent, including our Dimock field located in northeast Pennsylvania, which contains more than 15% of our total proved reserves.
 
Year Ended December 31,
 
2014
 
2013
 
2012
Production Volumes
 

 
 

 
 

Natural gas (Bcf)
 

 
 

 
 

Dimock field
479.8

 
356.5

 
209.3

Total
508.0

 
394.2

 
253.2

Oil (Mbbl)(1)
 

 
 

 
 

Total
3,961

 
3,221

 
2,407

Equivalents (Bcfe)
 

 
 

 
 

Dimock field
479.8

 
356.5

 
209.3

Total
531.8

 
413.6

 
267.7

Natural Gas Average Sales Price ($/Mcf)
 

 
 

 
 

Dimock field
$
3.42

 
$
3.48

 
$
2.82

Total (excluding realized impact of derivative settlements)
$
3.41

 
$
3.43

 
$
2.79

Total (including realized impact of derivative settlements)
$
3.28

 
$
3.56

 
$
3.67

Oil Average Sales Price ($/Bbl)
 

 
 

 
 

Total (excluding realized impact of derivative settlements)
$
87.65

 
$
99.65

 
$
96.65

Total (including realized impact of derivative settlements)
$
88.50

 
$
101.13

 
$
101.65

Average Production Costs ($/Mcfe)
 

 
 

 
 

Dimock field
$
0.07

 
$
0.06

 
$
0.08

Total
$
0.22

 
$
0.27

 
$
0.37

_______________________________________________________________________________
(1)
Includes NGLs which represent less than 1% of our equivalent production for all years presented and 9.4%, 10.5%, and 6.9% of our oil production for the years ended December 31, 2014, 2013 and 2012, respectively.
ACREAGE
Our interest in both developed and undeveloped properties is primarily in the form of leasehold interests held under customary mineral leases. These leases provide us the right, in general, to develop oil and/or natural gas on the properties. Their primary terms range in length from approximately three to 10 years. These properties are held for longer periods if production is established.
The following table summarizes our gross and net developed and undeveloped leasehold and mineral fee acreage at December 31, 2014.
 
Developed
 
Undeveloped
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Leasehold acreage
933,418
 
816,343
 
604,724
 
501,691
 
1,538,142
 
1,318,034
Mineral fee acreage
133,623
 
112,570
 
61,744
 
52,242
 
195,367
 
164,812
Total
1,067,041
 
928,913
 
666,468
 
553,933
 
1,733,509
 
1,482,846

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Total Net Undeveloped Acreage Expiration
In the event that production is not established or we take no action to extend or renew the terms of our leases, our net undeveloped acreage that will expire over the next three years as of December 31, 2014 is 91,697, 68,012 and 87,350 for the years ending December 31, 2015, 2016 and 2017, respectively.
We expect to retain substantially all of our expiring acreage either through drilling activities, renewal of the expiring leases or through the exercise of extension options. As of December 31, 2014, approximately 34% of our expiring acreage disclosed above is located in our core areas of operation where we currently expect to continue development activities and/or extend the lease terms.
WELL SUMMARY
The following table presents our ownership in productive natural gas and crude oil wells at December 31, 2014. This summary includes natural gas and crude oil wells in which we have a working interest.
 
Gross
 
Net
Natural Gas
4,294

 
3,868.0

Crude Oil
262

 
205.9

Total(1)
4,556

 
4,073.9

_______________________________________________________________________________
(1)
Total percentage of gross operated wells is 90.8%.
DRILLING ACTIVITY
We drilled wells or participated in the drilling of wells as indicated in the table below.
 
Year Ended December 31,
 
2014
 
2013
 
2012
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Development Wells
 

 
 

 
 

 
 

 
 

 
 

Productive
199

 
175.5

 
169

 
145.4

 
149

 
102.7

Dry

 

 
2

 
1.3

 

 

Extension Wells
 
 
 
 
 
 
 
 
 
 
 
Productive

 

 

 

 
8

 
7.0

Dry

 

 

 

 

 

Exploratory Wells
 
 
 
 
 
 
 
 
 
 
 
Productive

 

 
9

 
6.8

 
9

 
6.3

Dry
1

 
1.0

 
1

 

 
4

 
1.8

Total
200

 
176.5

 
181

 
153.5

 
170

 
117.8

 
 
 
 
 
 
 
 
 
 
 
 
Acquired Wells
26

 
23.7

 

 

 

 

At December 31, 2014, 17 gross (14.8 net) wells were in the process of being drilled.
OTHER BUSINESS MATTERS
Title to Properties
We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. Individual properties may be subject to burdens such as royalty, overriding royalty, carried, net profits, working and other outstanding interests customary in the industry. In addition, interests may be subject to obligations or duties under applicable laws or burdens such as production payments, ordinary course liens incidental to operating agreements and for current taxes or development obligations under oil and gas leases. As is customary in the industry in the case of undeveloped properties, preliminary investigations of record title are made at the time of lease acquisition. Complete investigations are made

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prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.
Competition
Competition in our primary producing areas is intense. Price, contract terms and quality of service, including pipeline connection times and distribution efficiencies, affect competition. We believe that our extensive acreage position and our access to gathering and pipeline infrastructure in Pennsylvania, along with our expected activity level and the related services and equipment that we have secured for the upcoming years, enhance our competitive position over other producers who do not have similar systems or services in place. We also actively compete against other companies with substantial financial and other resources.
Major Customers
During the years ended December 31, 2014, 2013 and 2012, two customers accounted for approximately 14% and 10%, four customers accounted for approximately 21%, 16%, 14% and 11% and three customers accounted for approximately 18%, 12% and 10%, respectively, of our total sales. We do not believe that the loss of any of these customers would have a material adverse effect on us because alternative customers are readily available.
Seasonality
Demand for natural gas has historically been seasonal, with peak demand and typically higher prices occurring during the colder winter months.
Regulation of Oil and Natural Gas Exploration and Production
Exploration and production operations are subject to various types of regulation at the federal, state and local levels. This regulation includes requiring permits to drill wells, maintaining bonding requirements to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties on which wells are drilled, and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells that may be drilled in a given field and the unitization or pooling of oil and natural gas properties. Some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibiting the venting or flaring of natural gas and imposing certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of oil and natural gas we can produce from our wells, and to limit the number of wells or the locations where we can drill. Because these statutes, rules and regulations undergo constant review and often are amended, expanded and reinterpreted, we are unable to predict the future cost or impact of regulatory compliance. The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects its profitability. We do not believe, however, we are affected differently by these regulations than others in the industry.
Natural Gas Marketing, Gathering and Transportation
Federal legislation and regulatory controls have historically affected the price of the natural gas we produce and the manner in which our production is transported and marketed. Under the Natural Gas Act of 1938 (NGA), the Natural Gas Policy Act of 1978 (NGPA), and the regulations promulgated under those statutes, the FERC regulates the interstate sale for resale of natural gas and the transportation of natural gas in interstate commerce, although facilities used in the production or gathering of natural gas in interstate commerce are generally exempted from FERC jurisdiction. Effective beginning in January 1993, the Natural Gas Wellhead Decontrol Act deregulated natural gas prices for all “first sales” of natural gas, which definition covers all sales of our own production. In addition, as part of the broad industry restructuring initiatives described below, the FERC granted to all producers such as us a “blanket certificate of public convenience and necessity” authorizing the sale of natural gas for resale without further FERC approvals. As a result of this policy, all of our produced natural gas is sold at market prices, subject to the terms of any private contracts that may be in effect. In addition, under the provisions of the Energy Policy Act of 2005 (2005 Act), the NGA was amended to prohibit any forms of market manipulation in connection with the purchase or sale of natural gas. Pursuant to the 2005 Act, the FERC established regulations intended to increase natural gas pricing transparency by, among other things, requiring market participants to report their gas sales transactions annually to the FERC. The 2005 Act also significantly increased the penalties for violations of the NGA and the FERC’s regulations up to $1,000,000 per day per violation. In 2010, the FERC issued Penalty Guidelines for the determination of civil penalties and procedure under its enforcement program.

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Some of our pipelines are subject to regulation by the FERC. We own an intrastate natural gas pipeline through our wholly‑owned subsidiary, Cranberry Pipeline Corporation, that provides interstate transportation and storage services pursuant to Section 311 of the NGPA, as well as intrastate transportation and storage services that are regulated by the West Virginia Public Service Commission. For qualified intrastate pipelines, FERC allows interstate transportation service “on behalf of” interstate pipelines or local distribution companies served by interstate pipelines without subjecting the intrastate pipeline to the more comprehensive NGA jurisdiction of the FERC. We provide Section 311 service in accordance with a publicly available Statement of Operating Conditions filed with FERC under rates that are subject to approval by the FERC. On December 26, 2012, we filed with the FERC a petition for rate approval of our existing interstate transportation rates and a proposed decrease of our storage rates. By Letter Order issued May 15, 2013, the FERC approved the rate petition.
In 2012 we executed a precedent agreement with Constitution, at the time a wholly owned subsidiary of Williams Partners L.P., for 500,000 Dth per day of pipeline capacity and acquired a 25% equity interest in a pipeline to be constructed in the states of New York and Pennsylvania. On June 12, 2013, the project sponsors filed an application with FERC requesting a certificate of public convenience and necessity to construct and operate the 124‑mile pipeline project that, once completed, will provide 650,000 Dth per day of pipeline capacity. On December 2, 2014, the FERC issued a certificate of public convenience and necessity, authorizing the construction and operation of the pipeline project. While FERC has issued the certificate, the project scope or timeline for construction and eventual in-service date may still be impacted by the public regulatory permitting process. If placed into service, the project pipeline will be an interstate pipeline subject to full regulation by FERC under the NGA.
Additionally, in 2014 we executed a precedent agreement with Transcontinental Gas Pipe Line Company, LLC (Transco) for 850,000 Dth per day of pipeline capacity and acquired a 20% equity interest in Meade, which was formed to construct a pipeline with Transco from Susquehanna County, Pennsylvania to an interconnect with Transco's mainline in Lancaster County, Pennsylvania. The proposed pipeline will be an interstate pipeline subject to full regulation by the FERC under the NGA. Transco currently plans to file an application for a certificate of public convenience and necessity with the FERC during second quarter 2015; however, the timing of that filing is subject to Transco’s timely completion of the FERC pre-filing process and, therefore, could change.
Our production and gathering facilities are not subject to jurisdiction of the FERC; however, our natural gas sales prices nevertheless continue to be affected by intrastate and interstate gas transportation regulation because the cost of transporting the natural gas once sold to the consuming market is a factor in the prices we receive. Beginning with Order No. 436 in 1985 and continuing through Order No. 636 in 1992 and Order No. 637 in 2000, the FERC has adopted a series of rulemakings that have significantly altered the transportation and marketing of natural gas. These changes were intended by the FERC to foster competition by, among other things, requiring interstate pipeline companies to separate their wholesale gas marketing business from their gas transportation business, and by increasing the transparency of pricing for pipeline services. The FERC has also established regulations governing the relationship of pipelines with their marketing affiliates, which essentially require that designated employees function independently of each other, and that certain information not be shared. The FERC has also implemented standards relating to the use of electronic data exchange by the pipelines to make transportation information available on a timely basis and to enable transactions to occur on a purely electronic basis.
In light of these statutory and regulatory changes, most pipelines have divested their natural gas sales functions to marketing affiliates, which operate separately from the transporter and in direct competition with all other merchants. Most pipelines have also implemented the large‑scale divestiture of their natural gas gathering facilities to affiliated or non‑affiliated companies. Interstate pipelines are required to provide unbundled, open and nondiscriminatory transportation and transportation‑related services to producers, gas marketing companies, local distribution companies, industrial end users and other customers seeking such services. As a result of FERC requiring natural gas pipeline companies to separate marketing and transportation services, sellers and buyers of natural gas have gained direct access to pipeline transportation services, and are better able to conduct business with a larger number of counterparties. We believe these changes generally have improved our access to markets while, at the same time, substantially increasing competition in the natural gas marketplace. We cannot predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on our activities. Similarly, we cannot predict what proposals, if any, that affect the oil and natural gas industry might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on us. Further, we cannot predict whether the recent trend toward federal deregulation of the natural gas industry will continue or what effect future policies will have on our sale of gas.
We use derivative financial instruments such as collar and swap agreements to attempt to more effectively manage price risk due to the impact of changes in commodity prices on our operating results and cash flows. Following enactment of the Dodd‑Frank Wall Street Reform and Consumer Protection Act (Dodd‑Frank Act) in July 2010, the Commodity Futures Trading Commission (CFTC) has promulgated regulations to implement statutory requirements for swap transactions, including certain options. The CFTC regulations are intended to implement a regulated market in which most swaps are

15


executed on registered exchanges or swap execution facilities and cleared through central counterparties. In addition, all swap market participants are subject to new reporting and recordkeeping requirements related to their swap transactions. We believe that our use of swaps to hedge against commodity exposure qualifies us as an end‑user, exempting us from the requirement to centrally clear our swaps. Nevertheless, the changes to the swap market as a result of Dodd‑Frank implementation could significantly increase the cost of entering into new swaps or maintaining existing swaps, materially alter the terms of new or existing swap transactions and/or reduce the availability of new or existing swaps. If we reduce our use of swaps as a result of the Dodd‑Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.
Federal Regulation of Petroleum
Our sales of crude oil and NGLs are not regulated and are made at market prices. However, the price received from the sale of these products is affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines, which are regulated by the FERC under the Interstate Commerce Act (ICA). FERC requires that pipelines regulated under the ICA file tariffs setting forth the rates and terms and conditions of service, and that such service not be unduly discriminatory or preferential.
Effective January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which annual adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may increase or decrease the cost of transporting crude oil and NGLs by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. In December 2010, to implement this required five‑year re‑determination, the FERC established an upward adjustment in the index to track oil pipeline cost changes and determined that the Producer Price Index for Finished Goods plus 2.65% should be the oil pricing index for the five‑year period beginning July 1, 2011. The result of indexing is a “ceiling rate” for each rate, which is the maximum at which the pipeline may set its interstate transportation rates. A pipeline may also file cost‑of‑service based rates if rate indexing will be insufficient to allow the pipeline to recover its costs. Rates are subject to challenge by protest when they are filed or changed. For indexed rates, complaints alleging that the rates are unjust and unreasonable may only be pursued if the complainant can show that a substantial change has occurred since the enactment of Energy Policy Act of 1992 in either the economic circumstances of the pipeline or in the nature of the services provided, that were a basis for the rate. There is no such limitation on complaints alleging that the pipeline’s rates or terms and conditions of service are unduly discriminatory or preferential. We are unable to predict with certainty the effect upon us of these periodic reviews by the FERC of the pipeline index.
Pipeline Safety Regulation
Certain of our pipeline systems and storage fields in West Virginia are regulated for safety compliance by the U.S. Department of Transportation (DOT) and the West Virginia Public Service Commission. In 2002, Congress enacted the Pipeline Safety Improvement Act of 2002 (2002 Act), which contains a number of provisions intended to increase pipeline operating safety. The DOT’s final regulations implementing the act became effective February 2004. Among other provisions, the regulations require that pipeline operators implement a pipeline integrity management program that must at a minimum include an inspection of gas transmission and non‑rural gathering pipeline facilities in certain locations within ten years, and at least every seven years thereafter. On March 15, 2006, the DOT revised these regulations to define more clearly the categories of gathering facilities subject to DOT regulation, establish new safety rules for certain gathering lines in rural areas, revise the current regulations applicable to safety and inspection of gathering lines in non‑ rural areas, and adopt new compliance deadlines. The initial baseline assessments under our integrity management program for our pipeline system in West Virginia were completed in January 2013. Pipeline integrity was confirmed at each of the targeted assessment sites. A new seven‑year reassessment cycle began during 2013.
In December 2006, Congress enacted the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (PIPES Act), which reauthorized the programs adopted under the 2002 Act, proposed enhancements for state programs to reduce excavation damage to pipelines, established increased federal enforcement of one‑call excavation programs, and established a new program for review of pipeline security plans and critical facility inspections. Pursuant to the PIPES Act, the DOT issued regulations on May 5, 2011 that would, with limited exceptions, subject all low‑stress hazardous liquids pipelines, regardless of location or size, to the DOT’s pipeline safety regulations.
In December 2011, Congress passed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The act increased the maximum civil penalties for pipeline safety administrative enforcement actions; required the DOT to issue regulations requiring the use of automatic or remote‑controlled shutoff valves on new and rebuilt pipelines and to study and report on the expansion of integrity management requirements, the sufficiency of existing gathering line regulations to ensure

16


safety, and the use of leak detection systems by hazardous liquid pipelines; required pipeline operators to verify their records on maximum allowable operating pressure; and imposed new emergency response and incident notification requirements. The act reflects many of the areas of possible regulatory change described in an Advance Notice of Proposed Rulemaking issued by the DOT on August 18, 2011. Aside from rules contained in the act, which include revisions to DOT’s civil penalty authority and the requirement that pipelines verify maximum allowable operating pressure, the DOT has not yet promulgated any new regulations required by the act, although it is anticipated that the DOT will propose new regulations in early 2015. In January 2015, it was announced as part of a broad plan to reduce methane emissions from the oil and natural gas sector that PHMSA will propose pipeline safety standards in 2015 that will result in reduced methane emissions.
On December 3, 2009, the DOT adopted a regulation requiring gas and hazardous liquid pipelines that use supervisory control and data acquisition (SCADA) systems and have at least one controller and control room to develop written control room management procedures by August 1, 2011 and implement the procedures by February 1, 2013. The DOT expedited the program implementation deadline to October 1, 2011 for most of the requirements, except for certain provisions regarding adequate information and alarm management, which had a program implementation deadline of August 1, 2012. We developed and implemented the required control room management procedures in accordance with the deadlines. Effective January 1, 2011, natural gas and hazardous liquid pipelines also became subject to updated reporting requirements with DOT.
The cost of compliance with DOT’s integrity management rules depends on integrity testing and the repairs found to be necessary by such testing. Changes to the amount of pipe subject to integrity management, whether by expansion of the definition of the type of areas subject to integrity management procedures or of the applicability of such procedures outside of those defined areas can have a significant impact on costs we may incur to ensure compliance. In the future other laws and regulations may be enacted or adopted or existing laws may be reinterpreted in a manner that could impact our compliance costs. In addition, we may be subject to DOT’s enforcement actions and penalties for failure to comply with pipeline regulations.
Environmental and Safety Regulations
General. Our operations are subject to extensive federal, state and local laws and regulations relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. Permits are required for the operation of our various facilities. These permits can be revoked, modified or renewed by issuing authorities. Governmental authorities enforce compliance with their regulations through fines, injunctions or both. Government regulations can increase the cost of planning, designing, installing and operating, and can affect the timing of installing and operating, oil and natural gas facilities. Although we believe that compliance with environmental regulations will not have a material adverse effect on us, risks of substantial costs and liabilities related to environmental compliance issues are part of oil and natural gas production operations. No assurance can be given that significant costs and liabilities will not be incurred. Also, it is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from oil and natural gas production could result in substantial costs and liabilities to us.
U.S. laws and regulations applicable to our operations include those controlling the discharge of materials into the environment, requiring removal and cleanup of materials that may harm the environment or otherwise relating to the protection of the environment.
Solid and Hazardous Waste. We currently own or lease, and have in the past owned or leased, numerous properties that were used for the production of oil and natural gas for many years. Although operating and disposal practices that were standard in the industry at the time may have been utilized, it is possible that hydrocarbons or other wastes may have been disposed of or released on or under the properties currently owned or leased by us. State and federal laws applicable to oil and gas wastes and properties have become stricter over time. Under these increasingly stringent requirements, we could be required to remove or remediate previously disposed wastes (including wastes disposed or released by prior owners and operators) or clean up property contamination (including groundwater contamination by prior owners or operators) or to perform plugging operations to prevent future contamination.
We generate some hazardous wastes that are already subject to the Federal Resource Conservation and Recovery Act (RCRA) and comparable state statutes. The Environmental Protection Agency (EPA) has limited the disposal options for certain hazardous wastes. It is possible that certain wastes currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes under RCRA or other applicable statutes. We could, therefore, be subject to more rigorous and costly disposal requirements in the future than we encounter today.
Superfund. The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), also known as the “Superfund” law, and comparable state laws and regulations impose liability, without regard to fault or the legality of the original conduct, on certain persons with respect to the release of hazardous substances into the environment. These persons include the current and past owners and operators of a site where the release occurred and any party that treated or disposed of

17


or arranged for the treatment or disposal of hazardous substances found at a site. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA, and in some cases, private parties, to undertake actions to clean up such hazardous substances, or to recover the costs of such actions from the responsible parties. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of business, we have used materials and generated wastes and will continue to use materials and generate wastes that may fall within CERCLA’s definition of hazardous substances. We may also be an owner or operator of sites on which hazardous substances have been released. As a result, we may be responsible under CERCLA for all or part of the costs to clean up sites where such substances have been released.
Oil Pollution Act. The Federal Oil Pollution Act of 1990 (OPA) and resulting regulations impose a variety of obligations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. The term “waters of the United States” has been broadly defined to include inland water bodies, including wetlands and intermittent streams. The OPA assigns joint and several strict liability to each responsible party for oil removal costs and a variety of public and private damages. The OPA also imposes ongoing requirements on operators, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. We believe that we substantially comply with the Oil Pollution Act and related federal regulations.
Endangered Species Act. The Endangered Species Act (ESA) restricts activities that may affect endangered or threatened species or their habitats. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA, nor are we aware of any proposed listings that will affect our operations. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected states.
Clean Water Act. The Federal Water Pollution Control Act (Clean Water Act) and resulting regulations, which are primarily implemented through a system of permits, also govern the discharge of certain contaminants into waters of the United States. Sanctions for failure to comply strictly with the Clean Water Act are generally resolved by payment of fines and correction of any identified deficiencies. However, regulatory agencies could require us to cease construction or operation of certain facilities or to cease hauling wastewaters to facilities owned by others that are the source of water discharges. We believe that we substantially comply with the Clean Water Act and related federal and state regulations.
Clean Air Act. Our operations are subject to the Federal Clean Air Act and comparable local and state laws and regulations to control emissions from sources of air pollution. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control toxic air pollutants and greenhouse gases might require installation of additional controls. Payment of fines and correction of any identified deficiencies generally resolve penalties for failure to comply strictly with air regulations or permits. Regulatory agencies could also require us to cease construction or operation of certain facilities or to install additional controls on certain facilities that are air emission sources. We believe that we substantially comply with the emission standards under local, state, and federal laws and regulations.
Some of our producing wells and associated facilities are subject to restrictive air emission limitations and permitting requirements. In 2012, the EPA published final New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAP) that amended the existing NSPS and NESHAP standards for oil and gas facilities and created new NSPS standards for oil and gas production, transmission and distribution facilities with a compliance deadline of January 1, 2015. While these rules remain in effect, the EPA announced in 2013 that it would reexamine and reissue the rules over the next three years. The EPA has issued updated rules regarding storage tanks and additional rules are expected. In December 2014, the EPA issued finalized additional amendments to these rules that, among other things, distinguished between multiple flowback stages during completion of hydraulically fractured wells and clarified that storage tanks permanently removed from service are not affected by any requirements. Further, in 2012, seven states sued the EPA to compel the agency to make a determination as to whether standards of performance limiting methane emissions from oil and gas sources is appropriate and, if so, to promulgate performance standards for methane emissions from existing oil and gas sources. In April 2014, the EPA released a set of five white papers analyzing methane emissions from the industry, and, based on responses received, in January 2015 announced plans to propose a rule governing methane emissions from the oil and gas industry in 2015. If we are unable to comply with air pollution regulations or to obtain permits for emissions associated with our operations, we could be required to forego construction, modification or certain operations. These regulations may also increase compliance costs for some facilities we own or operate, and result in administrative, civil and/or criminal penalties for

18


non-compliance. Obtaining permits may delay the development of our oil and natural gas projects, including the construction and operation of facilities.
Safe Drinking Water Act. The Safe Drinking Water Act (SDWA) and comparable local and state provisions restrict the disposal, treatment or release of water produced or used during oil and gas development. Subsurface emplacement of fluids (including disposal wells or enhanced oil recovery) is governed by federal or state regulatory authorities that, in some cases, includes the state oil and gas regulatory authority or the state’s environmental authority. These regulations may increase the costs of compliance for some facilities.
Hydraulic Fracturing. Many of our exploration and production operations depend on the use of hydraulic fracturing to enhance production from oil and natural gas wells. This technology involves the injection of fluids-usually consisting mostly of water but typically including small amounts of several chemical additives-as well as sand into a well under high pressure in order to create fractures in the rock that allow oil or natural gas to flow more freely to the wellbore. Most of our wells would not be economical without the use of hydraulic fracturing to stimulate production from the well. Due to concerns raised relating to potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal, state and local levels have been initiated to render permitting and compliance requirements more stringent for hydraulic fracturing or prohibit the activity altogether. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas production activities using hydraulic fracturing techniques which could have an adverse effect on oil and natural gas production activities, including operational delays or increased operating costs in the production of oil and natural gas from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells and increased compliance costs, which could increase costs of our operations and cause considerable delays in acquiring regulatory approvals to drill and complete wells. For additional information about hydraulic fracturing and related environmental matters, please read “Risk Factors-Federal and state legislation and regulatory initiatives related to oil and gas development, including hydraulic fracturing, could result in increased costs and operating restrictions or delays” in Item 1A.
Greenhouse Gas. In response to studies suggesting that emissions of carbon dioxide and certain other gases may be contributing to global climate change, the United States Congress has considered legislation to reduce emissions of greenhouse gases from sources within the United States between 2012 and 2050. In addition, many states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. The EPA has also begun to regulate carbon dioxide and other greenhouse gas emissions under existing provisions of the Clean Air Act. If we are unable to recover or pass through a significant portion of our costs related to complying with current and future regulations relating to climate change and GHGs, it could materially affect our operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of, and access to, capital. Future legislation or regulations adopted to address climate change could also make our products more or less desirable than competing sources of energy. Please read “Risk Factors-Climate change and climate change legislation and regulatory initiatives could result in increased operating costs and decreased demand for the oil and natural gas that we produce” in Item 1A.
OSHA and Other Laws and Regulations. We are subject to the requirements of the federal Occupational Safety and Health Act (OSHA), and comparable state laws. The OSHA hazard communication standard, the EPA community right‑ to‑know regulations under the Title III of CERCLA and similar state laws require that we organize and/or disclose information about hazardous materials used or produced in our operations. Also, pursuant to OSHA, the Occupational Safety and Health Administration has established a variety of standards related to workplace exposure to hazardous substances and employee health and safety.
Employees
As of December 31, 2014, we had 691 active employees. We recognize that our success is significantly influenced by the relationship we maintain with our employees. Overall, we believe that our relations with our employees are satisfactory. The Company and its employees are not represented by a collective bargaining agreement.
Website Access to Company Reports
We make available free of charge through our website, www.cabotog.com, our annual reports on Form 10‑K, quarterly reports on Form 10‑Q, current reports on Form 8‑K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission (SEC). Information on our website is not a part of this report. In addition, the SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements and other information filed by us. The public may read and copy materials that we file with

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the SEC at the SEC’s Public Reference Room located at 100 F Street, NE, Washington, DC 20549. Information regarding the operation of the Public Reference Room can be obtained by calling the SEC at 1‑800‑SEC‑0330.
Corporate Governance Matters
Our Corporate Governance Guidelines, Corporate Bylaws, Audit Committee Charter, Compensation Committee Charter, Corporate Governance and Nominations Committee Charter, Code of Business Conduct and Safety and Environmental Affairs Committee Charter are available on our website at www.cabotog.com, under the “Governance” section of “About Cabot.” Requests can also be made in writing to Investor Relations at our corporate headquarters at Three Memorial City Plaza, 840 Gessner Road, Suite 1400, Houston, Texas 77024.
ITEM 1A.    RISK FACTORS
Natural gas and crude oil prices fluctuate widely, and low prices for an extended period would likely have a material adverse impact on our business.
Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and oil. Lower commodity prices may reduce the amount of natural gas and oil that we can produce economically. Historically, natural gas and oil prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Because our reserves are predominantly natural gas (approximately 96% of equivalent proved reserves), changes in natural gas prices have a more significant impact on our financial results than oil prices. Natural gas prices, based on the first of the month Henry Hub index price, were $4.30 per Mmbtu in December 2014 and have continued to decline to $2.87 per Mmbtu in February 2015, while oil prices, based on the NYMEX monthly average price, were $59.29 per barrel in December 2014 and have continued to decline to $47.33 per barrel in January 2015. Substantial or extended decline in prices in the future would have a negative impact on our oil and gas reserves and financial results. See "Recent commodity price declines have resulted in an impairment of our oil and gas properties, and future natural gas and oil price declines may result in additional write-downs of the carrying amount of our assets, which could materially and adversely affect our results of operations."
Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control. These factors include but are not limited to the following:
the levels and location of natural gas and oil supply and demand and expectations regarding supply and demand, including the potential long-term impact of an abundance of natural gas from shale (such as that produced from our Marcellus Shale properties) on the global natural gas supply;
the level of consumer product demand;
weather conditions;
political conditions or hostilities in natural gas and oil producing regions, including the Middle East, Africa and South America;
the ability of the members of the Organization of Petroleum Exporting Countries and other exporting nations to agree to and maintain oil price and production controls;
the price level of foreign imports;
actions of governmental authorities;
the availability, proximity and capacity of gathering, transportation, processing and/or refining facilities in regional or localized areas that may affect the realized price for natural gas and oil;
inventory storage levels;
the nature and extent of domestic and foreign governmental regulations and taxation, including environmental and climate change regulation;
the price, availability and acceptance of alternative fuels;
technological advances affecting energy consumption;

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speculation by investors in oil and natural gas;
variations between product prices at sales points and applicable index prices; and
overall economic conditions, including the value of the U.S. dollar relative to other major currencies.
These factors and the volatile nature of the energy markets make it impossible to predict with any certainty the future prices of natural gas and crude oil. If natural gas and crude oil prices decline significantly for a sustained period of time, the lower prices may cause us to scale back our planned drilling program or adversely affect our ability to make planned expenditures, raise additional capital or meet our financial obligations.
Drilling natural gas and oil wells is a high-risk activity.
Our growth is materially dependent upon the success of our drilling program. Drilling for natural gas and oil involves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be encountered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors beyond our control, including:
unexpected drilling conditions, pressure or irregularities in formations;
equipment failures or accidents;
adverse weather conditions;
decreases in natural gas and oil prices;
surface access restrictions;
loss of title or other title related issues;
lack of available gathering or processing facilities or delays in the construction thereof;
compliance with, or changes in, governmental requirements and regulation, including with respect to wastewater disposal, discharge of greenhouse gases and fracturing; and
costs of shortages or delays in the availability of drilling rigs or crews and the delivery of equipment and materials.
Our future drilling activities may not be successful and, if unsuccessful, such failure will have an adverse effect on our future results of operations and financial condition. Our overall drilling success rate or our drilling success rate for activity within a particular geographic area may decline. We may be unable to lease or drill identified or budgeted prospects within our expected time frame, or at all. We may be unable to lease or drill a particular prospect because, in some cases, we identify a prospect or drilling location before seeking an option or lease rights in the prospect or location. Similarly, our drilling schedule may vary from our capital budget. The final determination with respect to the drilling of any scheduled or budgeted wells will be dependent on a number of factors, including:
the results of exploration efforts and the acquisition, review and analysis of the seismic data;
the availability of sufficient capital resources to us and the other participants for the drilling of the prospects;
the approval of the prospects by other participants after additional data has been compiled;
economic and industry conditions at the time of drilling, including prevailing and anticipated prices for natural gas and oil and the availability of drilling rigs and crews;
our financial resources and results; and
the availability of leases and permits on reasonable terms for the prospects and any delays in obtaining such permits.
These projects may not be successfully developed and the wells, if drilled, may not encounter reservoirs of commercially productive natural gas or oil.

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Our proved 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.
Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil 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 and oil prices. Additional assumptions include drilling and operating expenses, capital expenditures, 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 and oil 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 and oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the 12-month average crude oil and natural gas 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.
Recent commodity price declines have resulted in an impairment of our oil and gas properties, and future natural gas and oil price declines may result in additional write-downs of the carrying amount of our assets, which could materially and adversely affect our results of operations.
The value of our assets depends on prices of natural gas and oil. Declines in these prices as well as increases in development costs, changes in well performance, delays in asset development or deterioration of drilling results may result in our having to make material downward adjustments to our estimated proved reserves, and could result in an impairment charge and a corresponding write-down of the carrying amount of our oil and natural gas properties. For example, in December 2014, we recorded a $771.0 million impairment of oil and gas properties in certain non-core fields, primarily in east Texas. The impairment of these fields was due to a significant decline in commodity prices in late 2014 and management's decision not to pursue any further activity in these non-core areas in the current price environment. Because our reserves are predominately natural gas (approximately 96% of equivalent proved reserves), changes in natural gas prices have a more significant impact on our financial results than oil prices.
We evaluate our oil and gas properties for impairment on a field-by-field basis whenever events or changes in circumstances indicate a property's carrying amount may not be recoverable. We compare expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted expected cash flows, based on our estimate of future crude natural gas and crude oil prices, operating costs and anticipated production from proved reserves and risk-adjusted probable and possible reserves, are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of assumptions management uses in its budgeting and forecasting process as well as historical and current prices adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. In the event that commodity prices decline further, there could be a significant revision in the future.
Our future performance depends on our ability to find or acquire additional natural gas and oil reserves that are economically recoverable.
In general, the production rate of natural gas and oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Unless we successfully replace the reserves that we produce, our reserves will decline, eventually resulting in a decrease in natural gas and oil production and lower revenues and cash flow from operations. Our future natural gas and oil production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. We may not be able to replace reserves through our exploration, development and exploitation activities or by acquiring properties at acceptable costs. Low natural gas and oil prices may further limit the kinds of reserves that we can develop and produce economically.

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Our reserve report estimates that production from our proved developed reserves as of December 31, 2014 will increase at a rate of 9% during 2015 and then decline at estimated rates of 36%, 23% and 17% during 2016, 2017 and 2018, respectively. Future development of proved undeveloped and other reserves currently not classified as proved developed producing will impact these rates of decline. Because of higher initial decline rates from newly developed reserves, we consider this pattern fairly typical.
Exploration, development and exploitation activities involve numerous risks that may result in, among other things, dry holes, the failure to produce natural gas and oil in commercial quantities and the inability to fully produce discovered reserves.
We have substantial capital requirements, and we may not be able to obtain needed financing on satisfactory terms, if at all.
We rely upon access to both our revolving credit facility and longer-term capital markets as sources of liquidity for any capital requirements not satisfied by cash flow from operations or other sources. Future challenges in the global financial system, including the capital markets, may adversely affect our business and our financial condition. Our ability to access the capital markets may be restricted at a time when we desire, or need, to raise capital, which could have an impact on our flexibility to react to changing economic and business conditions. Adverse economic and market conditions could adversely affect the collectability of our trade receivables and cause our commodity hedging counterparties to be unable to perform their obligations or to seek bankruptcy protection. Future challenges in the economy could also lead to reduced demand for natural gas which could have a negative impact on our revenues.
Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are challenging, and our failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our financial condition and reduce our growth rate.
Our future growth prospects are dependent upon our ability to identify optimal strategies for our business. In developing our business plan, we considered allocating capital and other resources to various aspects of our businesses including well-development (primarily drilling), reserve acquisitions, exploratory activity, corporate items and other alternatives. We also considered our likely sources of capital. Notwithstanding the determinations made in the development of our 2015 plan, business opportunities not previously identified periodically come to our attention, including possible acquisitions and dispositions. If we fail to identify optimal business strategies, or fail to optimize our capital investment and capital raising opportunities and the use of our other resources in furtherance of our business strategies, our financial condition and growth rate may be adversely affected. Moreover, economic or other circumstances may change from those contemplated by our 2015 plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.
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, oil spills, greenhouse gas or methane emissions and explosions of natural gas transmission lines, may lead to increased 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.
Our ability to sell our natural gas and oil production and/or the prices we receive for our production could be materially harmed if we fail to obtain adequate services such as transportation and processing.
The sale of our natural gas and oil production depends on a number of factors beyond our control, including the availability and capacity of transportation and processing facilities. We deliver our natural gas and oil production primarily through gathering systems and pipelines that we do not own. The lack of available capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Third-party systems and facilities may be unavailable due to market conditions or mechanical or other reasons. To the extent these services are unavailable, we would be unable to realize revenue from wells served by such facilities until suitable arrangements are made to market our production. Our failure to obtain these services on acceptable terms could materially harm our business.
For example, the Marcellus Shale wells we have drilled to date have generally reported very high initial production rates. The amount of natural gas being produced in the area from these new wells, as well as natural gas produced from other existing wells, may exceed the capacity of the various gathering and intrastate or interstate transportation pipelines currently available.

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In such event, this could result in wells being shut in or awaiting a pipeline connection or capacity and/or natural gas being sold at much lower prices than those quoted on NYMEX or than we currently project, which would adversely affect our results of operations and cash flows.
We are subject to complex laws and regulations, including environmental and safety regulations, which can adversely affect the cost, manner or feasibility of doing business.
Our operations are subject to extensive federal, state and local laws and regulations, including drilling, permitting and safety laws and regulations and those relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. These laws and regulations can adversely affect the cost, manner or feasibility of doing business. Many laws and regulations require permits for the operation of various facilities, and these permits are subject to revocation, modification and renewal. Governmental authorities have the power to enforce compliance with their regulations, and violations could subject us to fines, injunctions or both. These laws and regulations have increased the costs of planning, designing, drilling, installing and operating natural gas and oil facilities, and new laws and regulations or revisions or reinterpretations of existing laws and regulations could further increase these costs. Increased scrutiny of our industry may also occur as a result of EPA's 2014-2016 National Enforcement Initiative, "Ensuring Energy Extraction Activities Comply with Environmental Laws," through which EPA will address incidences of noncompliance from natural gas extraction and production activities that may cause or contribute to significant harm to public health and/or the environment. In addition, we may be liable for environmental damages caused by previous owners of property we purchase or lease. Risks of substantial costs and liabilities related to environmental compliance issues are inherent in natural gas and oil operations. For example, we could be required to install expensive pollution control measures or limit or cease activities on lands located within wilderness, wetlands or other environmentally or politically sensitive areas. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties as well as the imposition of corrective action orders. It is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from natural gas and oil production, would result in substantial costs and liabilities.
Acquired properties may not be worth what we pay due to uncertainties in evaluating recoverable reserves and other expected benefits, as well as potential liabilities.
Successful property acquisitions require an assessment of a number of factors beyond our control. These factors include estimates of recoverable reserves, exploration potential, future natural gas and oil prices, operating costs, production taxes and potential environmental and other liabilities. These assessments are complex and inherently imprecise. Our review of the properties we acquire may not reveal all existing or potential problems. In addition, our review may not allow us to fully assess the potential deficiencies of the properties. We do not inspect every well, and even when we inspect a well we may not discover structural, subsurface, or environmental problems that may exist or arise.
There may be threatened or contemplated claims against the assets or businesses we acquire related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations. We often assume certain liabilities, and we may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities, and our contractual indemnification may not be effective. At times, we acquire interests in properties on an "as is" basis with limited representations and warranties and limited remedies for breaches of such representations and warranties. In addition, significant acquisitions can change the nature of our operations and business if the acquired properties have substantially different operating and geological characteristics or are in different geographic locations than our existing properties.
The integration of the properties we acquire could be difficult, and may divert management's attention away from our existing operations.
The integration of the properties we acquire could be difficult, and may divert management's attention and financial resources away from our existing operations. These difficulties include:
the challenge of integrating the acquired properties while carrying on the ongoing operations of our business;
the inability to retain key employees of the acquired business;
potential lack of operating experience in a geographic market of the acquired properties; and
the possibility of faulty assumptions underlying our expectations.
The process of integrating our operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our management may be required to devote considerable amounts of time to this integration process,

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which will decrease the time they will have to manage our existing business. If management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.
We face a variety of hazards and risks that could cause substantial financial losses.
Our business involves a variety of operating risks, including:
well site blowouts, cratering and explosions;
equipment failures;
pipe or cement failures and casing collapses, which can release natural gas, oil, drilling fluids or hydraulic fracturing fluids;
uncontrolled flows of natural gas, oil or well fluids;
pipeline ruptures;
fires;
formations with abnormal pressures;
handling and disposal of materials, including drilling fluids and hydraulic fracturing fluids;
release of toxic gas;
buildup of naturally occurring radioactive materials;
pollution and other environmental risks, including conditions caused by previous owners or lessors of our properties; and
natural disasters.
Any of these events could result in injury or loss of human life, loss of hydrocarbons, significant damage to or destruction of property, environmental pollution, regulatory investigations and penalties, suspension or impairment of our operations and substantial losses to us.
Our operation of natural gas gathering and pipeline systems also involves various risks, including the risk of explosions and environmental hazards caused by pipeline leaks and ruptures. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites, could increase these risks. As of December 31, 2014, we owned or operated approximately 3,100 miles of natural gas gathering and pipeline systems. As part of our normal maintenance program, we have identified certain segments of our pipelines that we believe periodically require repair, replacement or additional maintenance.
We may not be insured against all of the operating risks to which we are exposed.
We maintain insurance against some, but not all, of these risks and losses. We do not carry business interruption insurance. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.
We have limited control over the activities on properties we do not operate.
Other companies operate some of the properties in which we have an interest. As of December 31, 2014, non-operated wells represented approximately 9.2% of our total owned gross wells, or approximately 3.2% of our owned net wells. We have limited ability to influence or control the operation or future development of these non-operated properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we are required to fund with respect to them. The failure of an operator of our wells to adequately perform operations, an operator's breach of the applicable agreements or an operator's failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

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Terrorist activities and the potential for military and other actions could adversely affect our business.
The threat of terrorism and the impact of military and other action have caused instability in world financial markets and could lead to increased volatility in prices for natural gas and oil, all of which could adversely affect the markets for our operations. Acts of terrorism, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable, could be directed against companies operating in the United States. The U.S. government has issued public warnings that indicate energy assets might be specific targets of terrorist organizations. These developments have subjected our operations to increased risk and, depending on their ultimate magnitude, could have a material adverse effect on our business.
Competition in our industry is intense, and many of our competitors have substantially greater financial and technological resources than we do, which could adversely affect our competitive position.
Competition in the natural gas and oil industry is intense. Major and independent natural gas and oil companies actively bid for desirable natural gas and oil properties, as well as for the capital, equipment and labor required to operate and develop these properties. Our competitive position is affected by price, contract terms and quality of service, including pipeline connection times, distribution efficiencies and reliable delivery record. Many of our competitors have financial and technological resources and exploration and development budgets that are substantially greater than ours. These companies may be able to pay more for exploratory projects and productive natural gas and oil properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe will be increasingly important to attaining success in the industry. These companies may also have a greater ability to continue drilling activities during periods of low natural gas and oil prices and to absorb the burden of current and future governmental regulations and taxation.
We may have hedging arrangements that expose us to risk of financial loss and limit the benefit to us of increases in prices for natural gas and oil.
From time to time, when we believe that market conditions are favorable, we use certain financial derivative instruments to manage price risk associated with our natural gas and crude oil production. While there are many different types of derivatives available, we generally utilize collar and swap agreements to attempt to manage price risk more effectively.
The collar arrangements are put and call options used to establish floor and ceiling prices for a fixed volume of production during a certain time period. They provide for payments to counterparties if the index price exceeds the ceiling and payments from the counterparties if the index price falls below the floor. The swap agreements call for payments to, or receipts from, counterparties based on whether the index price for the period is greater or less than the fixed price established for that period when the swap is put in place. These arrangements limit the benefit to us of increases in prices. In addition, these arrangements expose us to risks of financial loss in a variety of circumstances, including when:
a counterparty is unable to satisfy its obligations;
production is less than expected; or
there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for our production.
The CFTC has promulgated regulations to implement statutory requirements for swap transactions. These regulations are intended to implement a regulated market in which most swaps are executed on registered exchanges or swap execution facilities and cleared through central counterparties. While we believe that our use of swap transactions exempt us from certain regulatory requirements, the changes to the swap market due to increased regulation could significantly increase the cost of entering into new swaps or maintaining existing swaps, materially alter the terms of new or existing swap transactions and/or reduce the availability of new or existing swaps. If we reduce our use of swaps as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.
We will continue to evaluate the benefit of utilizing derivatives in the future. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Item 7 and "Quantitative and Qualitative Disclosures about Market Risk" in Item 7A for further discussion concerning our use of derivatives.
The loss of key personnel could adversely affect our ability to operate.
Our operations are dependent upon a relatively small group of key management and technical personnel, and one or more of these individuals could leave our employment. The unexpected loss of the services of one or more of these individuals could

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have a detrimental effect on us. In addition, our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers and other professionals. Competition for experienced geologists, engineers and some other professionals is extremely intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.
Federal and state legislation and regulatory initiatives related to oil and gas development, including hydraulic fracturing, could result in increased costs and operating restrictions or delays.
Most of our exploration and production operations depend on the use of hydraulic fracturing to enhance production from oil and gas wells. This technology involves the injection of fluids—usually consisting mostly of water but typically including small amounts of several chemical additives—as well as sand or other proppants into a well under high pressure in order to create fractures in the rock that allow oil or gas to flow more freely to the wellbore. Most of our wells would not be economical without the use of hydraulic fracturing to stimulate production from the well. Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and gas regulatory programs; however, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act and has released permitting guidance for hydraulic fracturing activities that use diesel in fracturing fluids in those states where EPA is the permitting authority, including Pennsylvania. As a result, we may be subject to additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictions could result in delays in operations at well sites as well as increased costs to make wells productive. In addition, legislation introduced in Congress would provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and require the public disclosure of certain information regarding the chemical makeup of hydraulic fracturing fluids. If adopted, this legislation could establish an additional level of regulation and permitting at the federal, state or local levels, and could make it easier for third parties opposed to the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect the environment, including groundwater, soil or surface water. Moreover, in May 2014, the EPA announced an Advanced Notice of Proposed Rulemaking under the Toxic Substances Control Act relating to data collection, including the chemical substances and mixtures used in hydraulic fracturing. Further, in May 2013, the Department of the Interior's Bureau of Land Management (BLM) issued a proposed rule to regulate hydraulic fracturing on public and Indian land. The rule would require companies to publicly disclose the chemicals used in hydraulic fracturing operations to the BLM after fracturing operations have been completed and includes provisions addressing well-bore integrity and flowback water management plans. We voluntarily disclose on a well-by-well basis the chemicals we use in the hydraulic fracturing process at www.fracfocus.org.
On August 16, 2012, the EPA published final rules that establish new air emission control requirements for natural gas and NGL production, processing and transportation activities, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and National Emission Standards for Hazardous Air Pollutants (NESHAPS) to address hazardous air pollutants frequently associated with gas production and processing activities. Among other things, these final rules require the reduction of volatile organic compound emissions from natural gas wells through the use of reduced emission completions or "green completions" on all hydraulically fractured wells constructed or refractured after January 1, 2015. In addition, gas wells were required to use completion combustion device equipment (i.e., flaring) if emissions cannot be directed to a gathering line. Further, the final rules under NESHAPS include maximum achievable control technology (MACT) standards for "small" glycol dehydrators that are located at major sources of hazardous air pollutants and modifications to the leak detection standards for valves. In December 2014, the EPA finalized additional amendments to these rules that, among other things, distinguished between multiple flowback stages during completion and clarified that storage tanks permanently removed from service are not affected by any requirements. In January 2015, the EPA announced plans to propose a rule in summer 2015 governing methane emissions from oil and natural gas completion operations.
Compliance with these requirements, especially the imposition of these green completion requirements, may require modifications to certain of our operations, including the installation of new equipment to control emissions at the well site that could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.
In addition to these federal legislative and regulatory proposals, some states in which we operate, such as Pennsylvania, West Virginia and Texas, and certain local governments have adopted, and others are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, including requirements regarding chemical disclosure, casing and cementing of wells, withdrawal of water for use in high-volume hydraulic fracturing of horizontal wells, baseline testing of nearby water wells, and restrictions on the type of additives that may be used in hydraulic fracturing operations. For example, the City of Denton, Texas adopted a moratorium on hydraulic fracturing in November 2014, and New York announced the intention to create a statewide ban on hydraulic fracturing in December 2014. In addition, Pennsylvania's Act 13 of 2012 became law on February 14, 2012 and amended the state's Oil and Gas Act to impose an impact fee for drilling, increase setbacks from certain water sources, require water management plans, increase civil penalties, strengthen the Pennsylvania

27


Department of Environmental Protection's (PaDEP) authority over the issuance of drilling permits, and require the disclosure of chemical information regarding the components in hydraulic fracturing fluids. On December 19, 2013, the Pennsylvania Supreme Court struck down as unconstitutional portions of Act 13 that made statewide rules on oil and gas preempt local zoning rules. The remaining challenges to Act 13 were remanded to the state commonwealth court, which dismissed those challenges in July 2014. This could result in additional local restrictions on oil and gas activity in the state.
We use a significant amount of water in our hydraulic fracturing operations. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our operations, could adversely impact our operations. Moreover, new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial condition. For example, in April 2011, PaDEP called on all Marcellus Shale natural gas drilling operators to voluntarily cease by May 19, 2011 delivering wastewater to those centralized treatment facilities that were grandfathered from the application of PaDEP's Total Dissolved Solids regulations. In October 2011, the EPA announced that it plans to develop standards for disposal of wastewater produced from shale gas operations to publicly owned treatment works (POTWs), which will be proposed in 2015. The regulations will be developed under the EPA's Effluent Guidelines Program under the authority of the Clean Water Act. In response to these actions, operators including us have begun to rely more on recycling of flowback and produced water from well sites as a preferred alternative to disposal.
A number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing practices. The EPA is conducting a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. The EPA released a progress report outlining work currently underway on December 21, 2012 and is expected to release a draft report of final results in early 2015. This study and other studies that may be undertaken by EPA or other federal agencies could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act, the Toxic Substances Control Act, or other statutory and/or regulatory mechanisms.
Climate change and climate change legislation and regulatory initiatives could result in increased operating costs and decreased demand for the oil and natural gas that we produce.
Climate change, the costs that may be associated with its effects, and the regulation of greenhouse gas (GHG) emissions have the potential to affect our business in many ways, including increasing the costs to provide our products and services, reducing the demand for and consumption of our products and services (due to change in both costs and weather patterns), and the economic health of the regions in which we operate, all of which can create financial risks. In addition, legislative and regulatory responses related to GHG emissions and climate change may increase our operating costs. The United States Congress has previously considered legislation related to GHG emissions. There have also been international efforts seeking legally binding reductions in GHG emissions. For example, in November 2014, the Obama Administration announced an agreement with China to voluntarily reduce GHG emissions to 26% to 28% of 2005 levels by 2025. Further, the United States joined over 190 countries in Lima, Peru in December 2014 and agreed to draft an emissions reduction plan ahead of further international climate negotiations in Paris, France in 2015. In addition, increased public awareness and concern may result in more state, regional and/or federal requirements to reduce or mitigate GHG emissions. For example, in June 2013, the Obama Administration announced its Climate Action Plan, which, among other things, directs federal agencies to develop a strategy for the reduction of methane emissions, including emissions from the oil and gas sector. Pursuant to this plan, the EPA announced in January 2015 a plan to regulate methane emissions from the oil and gas sector.
In September 2009, the EPA finalized a mandatory GHG reporting rule that requires large sources of GHG emissions to monitor, maintain records on, and annually report their GHG emissions beginning January 1, 2010. The rule applies to large facilities emitting 25,000 metric tons or more of carbon dioxide-equivalent (CO2e) emissions per year and to most upstream suppliers of fossil fuels, as well as manufacturers of vehicles and engines. Subsequently, in November 2010, the EPA issued GHG monitoring and reporting regulations that went into effect on December 30, 2010, specifically for oil and natural gas facilities, including onshore and offshore oil and natural gas production facilities that emit 25,000 metric tons or more of CO2e per year. The rule required reporting of GHG emissions by regulated facilities to the EPA by March 2012 for emissions during 2011 and annually thereafter. We are required to report our GHG emissions to the EPA each year in March under this rule and have submitted our annual reports in compliance with the deadline. The EPA also issued a final rule that makes certain stationary sources and newer modification projects subject to permitting requirements for GHG emissions, beginning in 2011, under the CAA. However, in June 2014, the U.S. Supreme Court, in UARG v. EPA, limited the application of the GHG permitting requirements under the Prevention of Significant Deterioration and Title V permitting programs to sources that would otherwise need permits based on the emission of conventional pollutants.

28



Federal and state regulatory agencies can impose administrative, civil and/or criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. In addition, the passage of any federal or state climate change laws or regulations in the future could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any GHG emissions program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy.    

Moreover, some experts believe climate change poses potential physical risks, including an increase in sea level and changes in weather conditions, such as an increase in changes in precipitation and extreme weather events. To the extent that such unfavorable weather conditions are exacerbated by global climate change or otherwise, our operations may be adversely affected to a greater degree than we have previously experienced, including increased delays and costs. However, the uncertain nature of changes in extreme weather events (such as increased frequency, duration, and severity) and the long period of time over which any changes would take place make any estimations of future financial risk to our operations caused by these potential physical risks of climate change unreliable.
Certain federal income tax law changes have been proposed that, if passed, would have an adverse effect on our financial position, results of operations, and cash flows.
Substantive changes to existing federal income tax laws have been proposed that, if adopted, would repeal many tax incentives and deductions that are currently used by U.S. oil and gas companies and would impose new taxes. The proposals include: repeal of the percentage depletion allowance for oil and natural gas properties; elimination of the ability to fully deduct intangible drilling costs in the year incurred; repeal of the manufacturing tax deduction for oil and gas companies; and increase in the geological and geophysical amortization period for independent producers. Should some or all of these proposals become law, our taxes will increase, potentially significantly, which would have a negative impact on our net income and cash flows. This could also reduce our drilling activities in the U.S. Since none of these proposals have yet to become law, we do not know the ultimate impact these proposed changes may have on our business.
Provisions of Delaware law and our bylaws and charter could discourage change in control transactions and prevent stockholders from receiving a premium on their investment.
Our charter authorizes our Board of Directors to set the terms of preferred stock. In addition, Delaware law contains provisions that impose restrictions on business combinations with interested parties. Our bylaws prohibit the calling of a special meeting by our stockholders and place procedural requirements and limitations on stockholder proposals at meetings of stockholders. Because of these provisions of our charter, bylaws and Delaware law, persons considering unsolicited tender offers or other unilateral takeover proposals may be more likely to negotiate with our Board of Directors rather than pursue non-negotiated takeover attempts. As a result, these provisions may make it more difficult for our stockholders to benefit from transactions that are opposed by an incumbent Board of Directors.
The personal liability of our directors for monetary damages for breach of their fiduciary duty of care is limited by the Delaware General Corporation Law and by our charter.
The Delaware General Corporation Law allows corporations to limit available relief for the breach of directors' duty of care to equitable remedies such as injunction or rescission. Our charter limits the liability of our directors to the fullest extent permitted by Delaware law. Specifically, our directors will not be personally liable for monetary damages for any breach of their fiduciary duty as a director, except for liability:
for any breach of their duty of loyalty to the company or our stockholders;
for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law;
under provisions relating to unlawful payments of dividends or unlawful stock repurchases or redemptions; and
for any transaction from which the director derived an improper personal benefit.
This limitation may have the effect of reducing the likelihood of derivative litigation against directors, and may discourage or deter stockholders or management from bringing a lawsuit against directors for breach of their duty of care, even though such an action, if successful, might otherwise have benefited our stockholders.

29


ITEM 1B.    UNRESOLVED STAFF COMMENTS
None.
ITEM 3.    LEGAL PROCEEDINGS
Legal Matters
The information set forth under the heading "Legal Matters" in Note 9 of the Notes to Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K is incorporated by reference in response to this item.
Environmental Matters
From time to time we receive notices of violation from governmental and regulatory authorities in areas in which we operate relating to alleged violations of environmental statutes or the rules and regulations promulgated thereunder. While we cannot predict with certainty whether these notices of violation will result in fines and/or penalties, if fines and/or penalties are imposed, they may result in monetary sanctions, individually or in the aggregate, in excess of $100,000.
On November 17, 2014, we entered into a Consent Assessment of Civil Penalty with the Pennsylvania Department of Environmental Protection regarding a production fluid spill that resulted from a storage tank fire in Susquehanna County, Pennsylvania.  We paid a $120,000 civil penalty with respect to this matter.


30


ITEM 4.    MINE SAFETY DISCLOSURES
Not applicable.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table shows certain information as of February 19, 2015 about our executive officers, as such term is defined in Rule 3b-7 of the Securities Exchange Act of 1934, and certain of our other officers.
Name
Age
 
Position
 
Officer
Since
Dan O. Dinges
61

 
Chairman, President and Chief Executive Officer
 
2001
Scott C. Schroeder
52

 
Executive Vice President and Chief Financial Officer
 
1997
Jeffrey W. Hutton
59

 
Senior Vice President, Marketing
 
1995
G. Kevin Cunningham
61

 
Vice President and General Counsel
 
2010
Robert G. Drake
67

 
Vice President, Information Services
 
1998
Todd L. Liebl
57

 
Vice President, Land and Business Development
 
2012
Steven W. Lindeman
54

 
Vice President, Engineering and Technology
 
2011
Phillip L. Stalnaker
55

 
Vice President, Regional Manager North Region
 
2009
Matthew P. Kerin
34

 
Treasurer
 
2014
Todd M. Roemer
44

 
Controller
 
2010
Deidre L. Shearer
47

 
Corporate Secretary and Managing Counsel
 
2012
All officers are elected annually by our Board of Directors. During 2014, Mr. Scott C. Schroeder was promoted to Executive Vice President and Mr. Jeffrey W. Hutton was promoted to Senior Vice President, Marketing. Prior to this promotion, Mr. Schroeder was Vice President, Chief Financial Officer and Treasurer and Mr. Hutton was Vice President, Marketing. All of the executive officers have been employed by Cabot Oil & Gas Corporation for at least the last five years, except for Mr. Matthew P. Kerin, Mr. Todd M. Roemer and Ms. Deidre L. Shearer.
Mr. Kerin joined the Company in March 2012 and was appointed Treasurer in September 2014. Mr. Kerin most recently served as Manager - Finance and Investor Relations. Prior to joining the Company, Mr. Kerin served as an Associate in the Oil and Gas Investment Banking group at J.P. Morgan Securities.  He is a graduate of Texas A&M University with a Bachelor in Business Administration degree in Accounting and a Master of Science degree in Finance. He is also a graduate from the Jones Graduate School of Business at Rice University with a Master in Business Administration degree with a concentration in Finance and Energy.
Mr. Roemer joined the Company in February 2010 and was appointed Controller in March 2010. Prior to joining the Company, Mr. Roemer was in the Energy Practice of PricewaterhouseCoopers LLP from 1996 to February 2010, most recently as an Audit Senior Manager, where he served clients focused on exploration and production. He is a graduate of the University of Houston—Clear Lake with a Bachelor of Science degree in Accounting and is a Certified Public Accountant in the state of Texas.
Ms. Shearer joined the Company in December 2011 and was appointed Corporate Secretary and Managing Counsel in February 2012. Prior to joining the Company, Ms. Shearer was Assistant General Counsel of KBR, Inc. from January 2007, where she was responsible for corporate governance and SEC and NYSE compliance matters. Ms. Shearer received her J.D. degree from The University of Texas School of Law in 1992 and was primarily in private practice until she joined KBR.


31


PART II
ITEM 5.    MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is listed and principally traded on the New York Stock Exchange under the ticker symbol "COG." The following table presents the high and low closing sales prices per share of our common stock during certain periods, as reported in the consolidated transaction reporting system. Cash dividends paid per share of the common stock are also shown. A regular dividend has been declared each quarter since we became a public company in 1990.
 
High
 
Low
 
Dividends
2014
 

 
 

 
 

First Quarter
$
41.54

 
$
32.18

 
$
0.02

Second Quarter
$
39.33

 
$
32.35

 
$
0.02

Third Quarter
$
35.16

 
$
31.41

 
$
0.02

Fourth Quarter
$
34.71

 
$
28.46

 
$
0.02

2013
 

 
 

 
 

First Quarter
$
34.08

 
$
23.72

 
$
0.01

Second Quarter
$
36.21

 
$
31.72

 
$
0.01

Third Quarter
$
39.91

 
$
34.75

 
$
0.02

Fourth Quarter
$
38.93

 
$
32.63

 
$
0.02

As of February 2, 2015, there were 408 registered holders of our common stock.
EQUITY COMPENSATION PLAN INFORMATION
On May 1, 2014, our shareholders approved the 2014 Incentive Plan, which replaced the 2004 Incentive Plan that expired on April 29, 2014. Under the 2014 Incentive Plan, incentive and non-statutory stock options, stock appreciation rights (SARs), stock awards, cash awards and performance awards may be granted to key employees, consultants and officers. Non-employee directors may be granted discretionary awards under the 2014 Incentive Plan consisting of stock options or stock awards. A total of 18 million shares of common stock may be issued under the 2014 Incentive Plan. Under the 2014 Incentive Plan, no more than 10 million shares may be issued pursuant to incentive stock options. No additional awards may be granted under the 2014 Incentive Plan on or after May 1, 2024.
No additional awards will be granted under any of our prior plans, including the 2004 Incentive Plan.  Awards outstanding under the 2004 Incentive Plan will remain outstanding in accordance with their original terms and conditions.

32


The following table provides information as of December 31, 2014 regarding the number of shares of common stock that may be issued under our incentive plans.
 
(a)
 
(b)
 
(c)
 
Plan Category
Number of securities to be
issued upon exercise of
outstanding options, warrants
and rights
 
 Weighted-average exercise
price of outstanding options,
warrants and rights
 
Number of securities
remaining available for
future issuance under equity
compensation plans
(excluding securities
reflected in column (a))
 
Equity compensation plans approved by security holders
3,414,655

(1) 
$12.63

(2) 
18,044,547

(3) 
Equity compensation plans not approved by security holders
n/a

 
n/a

 
n/a

 
Total
3,414,655

 
$
12.63

 
18,044,547

 
_______________________________________________________________________________
(1)
Includes 667,764 SARs to be settled in common stock which become fully vested, if at all, in 2015; 1,088,960 employee performance shares, the performance periods of which end on December 31,2014, 2015 and 2016; 674,787 TSR performance shares, the performance periods of which end on December 31, 2014, 2015 and 2016; 329,061 hybrid performance shares, of which vest, if at all, in 2015, 2016, and 2017; and 604,214 restricted stock units awarded to the non-employee directors, the restrictions on which lapse upon a non-employee director's departure from the Board of Directors.
(2)
Price is only with respect to the 667,764 SARs outstanding because all other outstanding awards are issued without an exercise price.
(3)
Includes 49,869 shares of restricted stock, the restrictions on which lapse on various dates in 2015, 2016 and 2017; and 17,994,678 shares that are available for future grants under the 2014 Incentive Plan.
ISSUER PURCHASES OF EQUITY SECURITIES
Our Board of Directors has authorized a share repurchase program under which we may purchase shares of common stock in the open market or in negotiated transactions. There is no expiration date associated with the authorization. The shares included in the table below were repurchased on the open market and were held as treasury stock as of December 31, 2014.
Period
 
Total Number of
Shares
Purchased
 
Average Price Paid per Share
 
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
 
Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs
October 2014
 
253,700

 
$
31.91

 
253,700

 
10,107,320

November 2014
 

 

 

 
10,107,320

December 2014
 

 

 

 
10,107,320

Total
 
253,700

 
 
 
253,700

 
10,107,320


33


PERFORMANCE GRAPH
The following graph compares our common stock performance ("COG") with the performance of the Standard & Poors' 500 Stock Index and the Dow Jones U.S. Exploration & Production Index for the period December 2009 through December 2014. The graph assumes that the value of the investment in our common stock and in each index was $100 on December 31, 2009 and that all dividends were reinvested.
 
December 31,
Calculated Values
2009
 
2010
 
2011
 
2012
 
2013
 
2014
COG
$
100.00

 
$
87.14

 
$
175.11

 
$
229.98

 
$
359.07

 
$
274.93

S&P 500
$
100.00

 
$
115.06

 
$
117.49

 
$
136.30

 
$
180.44

 
$
205.14

Dow Jones U.S. Exploration & Production
$
100.00

 
$
116.74

 
$
111.85

 
$
118.36

 
$
156.05

 
$
139.24

The performance graph above is furnished and not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and will not be incorporated by reference into any registration statement filed under the Securities Act of 1933 unless specifically identified therein as being incorporated therein by reference. The performance graph is not soliciting material subject to Regulation 14A.

34


ITEM 6.    SELECTED FINANCIAL DATA
The following table summarizes our selected consolidated financial data for the periods indicated. This information should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7, and the Consolidated Financial Statements and related Notes in Item 8.
 
Year Ended December 31,
(In thousands, except per share amounts)
2014
 
2013
 
2012
 
2011
 
2010
Statement of Operations Data
 

 
 

 
 

 
 

 
 

Operating revenues
2,173,011

 
1,746,278

 
1,204,546

 
$
979,864

 
$
863,104

Impairment of oil and gas properties and other assets(1)
771,037

 

 

 

 
40,903

Gain on sale of assets(2)
17,120

 
21,351

 
50,635

 
63,382

 
106,294

Income from operations
106,186

 
551,582

 
306,186

 
306,850

 
266,439

Net income
104,468

 
279,773

 
131,730

 
122,408

 
103,386

Basic earnings per share
$
0.25

 
$
0.67

 
$
0.31

 
$
0.29

 
$
0.25

Diluted earnings per share
$
0.25

 
$
0.66

 
$
0.31

 
$
0.29

 
$
0.25

Dividends per common share
$
0.08

 
$
0.06

 
$
0.04

 
$
0.03

 
$
0.03

 
December 31,
 
2014
 
2013
 
2012
 
2011
 
2010
Balance Sheet Data
 

 
 

 
 

 
 

 
 

Properties and equipment, net
$
4,925,711

 
$
4,546,227

 
$
4,310,977

 
$
3,934,584

 
$
3,762,760

Total assets
5,437,716

 
4,981,080

 
4,616,313

 
4,331,493

 
4,005,031

Current portion of long-term debt

 

 
75,000

 

 

Long-term debt
1,752,000

 
1,147,000

 
1,012,000

 
950,000

 
975,000

Stockholders' equity
2,142,733

 
2,204,602

 
2,131,447

 
2,104,768

 
1,872,700

_______________________________________________________________________________
(1)
For discussion of impairment of oil and gas properties, refer to Note 3 of the Notes to the Consolidated Financial Statements.
(2)
Gain on sale of assets in 2014 includes a $19.9 million gain from the sale of certain proved and unproved oil and gas properties located in east Texas. Gain on sale of assets in 2013 includes a $19.4 million gain from the sale of certain proved and unproved oil and gas properties located in the Oklahoma and Texas panhandles, and a $17.5 million loss from the sale of certain proved and unproved oil and gas properties located in Oklahoma, Texas and Kansas and an aggregate net gain of $19.5 million from the sale of various other oil and gas properties during the year. Gain on sale of assets in 2012 includes a $67.0 million gain from the sale of certain Pearsall Shale undeveloped leaseholds in south Texas and an $18.2 million loss from the sale of certain proved oil and gas properties located in south Texas. Gain on sale of assets in 2011 includes a $34.2 million gain from the sale of certain Haynesville and Bossier Shale oil and gas properties and an aggregate net gain of $29.2 million from the sale of various other properties during the year. Gain on sale of assets in 2010 includes a $49.3 million gain from the sale of our Pennsylvania gathering infrastructure, a $40.7 million gain from the sale of our investment in Tourmaline Oil Corporation and an aggregate net gain of $16.3 million from the sale of various other properties during the year.

35


ITEM 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Consolidated Financial Statements and the accompanying Notes to the Consolidated Financial Statements included elsewhere in this Form 10-K contain additional information that should be referred to when reviewing this material.
OVERVIEW
On an equivalent basis, our production in 2014 increased by 29% from 2013. We produced 531.8 Bcfe, or 1.5 Bcfe per day, in 2014, compared to 413.6 Bcfe, or 1.1 Bcfe per day, in 2013. Natural gas production increased by 113.8 Bcf, or 29%, to 508.0 Bcf in 2014 compared to 394.2 Bcf in 2013. This increase was primarily the result of higher production in the Marcellus Shale associated with our drilling program in Pennsylvania, partially offset by lower production primarily in Oklahoma and west Texas as a result of certain non-core asset dispositions in the fourth quarter of 2013 and normal production declines in Texas and West Virginia. Crude oil/condensate/NGL production increased by 0.7 Mbbls, or 23%, from 3.2 MMbbls in 2013 to 4.0 MMbbls in 2014. This increase was the result of higher production resulting from our oil-focused Eagle Ford Shale drilling program in south Texas, partially offset by lower production associated with certain non-core asset dispositions in Oklahoma in the fourth quarter of 2013.
Our financial results depend on many factors, particularly the price of natural gas and crude oil and our ability to market our production on economically attractive terms. Our average realized natural gas price for 2014 was $3.28 per Mcf, 8% lower than the $3.56 per Mcf price realized in 2013. Our average realized crude oil price for 2014 was $88.50 per Bbl, 12% lower than the $101.13 per Bbl price realized in 2013. These realized prices include realized gains and losses resulting from commodity derivatives. For information about the impact of these derivatives on realized prices, refer to "Results of Operations" in Item 7.
Commodity prices are determined by many factors that are outside of our control. Historically, commodity prices have been volatile, and we expect them to remain volatile. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas, NGL and crude oil prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases will have on our capital program, production volumes or future revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of natural gas and crude oil reserves at economical costs are critical to our long-term success. See "Risk Factors—Natural gas and oil prices fluctuate widely, and low prices for an extended period would likely have a material adverse impact on our business" and "Risk Factors—Our future performance depends on our ability to find or acquire additional natural gas and oil reserves that are economically recoverable" in Item 1A.

In December 2014, we recorded a $771.0 million impairment of oil and gas properties in certain non-core fields, primarily in east Texas. The impairment of these fields was due to a significant decline in commodity prices in late 2014 and management's decision not to pursue any further activity in these non-core areas in the current price environment.

Effective April 1, 2014, we elected to discontinue hedge accounting on a prospective basis. Subsequent to April 1, 2014, our derivative instruments were accounted for on a mark-to-market basis with changes in fair value recognized currently in operating revenues in the Consolidated Statement of Operations. As a result of these mark-to-market adjustments, we will likely experience volatility in our earnings from time to time due to commodity price volatility. Refer to “Impact of Derivative Instruments on Operating Revenues” below and Note 6 to the Consolidated Financial Statements for more information.

We drilled 200 gross wells (176.5 net) with a success rate of 99.5% in 2014 compared to 181 gross wells (153.5 net) with a success rate of 98.3% in 2013. Our 2014 total capital and exploration spending was approximately $1.6 billion (excluding the Eagle Ford Shale acquisitions discussed below) compared to $1.2 billion in 2013. The increase in capital spending was the result of our drilling programs in the Marcellus Shale and Eagle Ford Shale. We allocate our planned program for capital and exploration expenditures among our various operating areas based on return expectations, availability of services and human resources.
Our 2015 drilling program includes approximately $900.0 million in capital and exploration expenditures and approximately $69.8 million in expected contributions to our equity method investments. These expenditures are expected to be funded by operating cash flow, existing cash and, if required, borrowings under our revolving credit facility. We will continue to assess the natural gas and crude oil price environment along with our liquidity position and may increase or decrease our capital and exploration expenditures accordingly.

36


Acquisitions and Divestitures
In December 2014, we completed the acquisition of certain proved and unproved oil and gas properties in the Eagle Ford Shale in south Texas for approximately $30.5 million and paid total cash consideration as of the closing date of approximately $29.6 million, which reflects the impact of customary purchase price adjustments and acquisition costs. The acquisition was funded with borrowings under our revolving credit facility.
In October 2014, we completed the acquisition of certain proved and unproved oil and gas properties in the Eagle Ford Shale in south Texas for approximately $210.0 million and paid total net cash consideration as of the closing date of approximately $185.2 million, which reflects the purchase price and adjustments of approximately $17.4 million for consents that the seller was unable to obtain for certain leaseholds prior to closing and approximately $8.0 million for the impact of customary purchase price adjustments and acquisition costs. The acquisition was funded with proceeds from the private placement of senior unsecured fixed rate notes completed in September 2014.
In October 2014, we completed the divestiture of certain proved and unproved oil and gas properties in east Texas to a third party for approximately $44.3 million. Total cash consideration received by the Company as of the closing date was approximately $42.8 million, which reflects the impact of customary purchase price adjustments.
FINANCIAL CONDITION
Capital Resources and Liquidity
Our primary sources of cash in 2014 were from funds generated from the sale of natural gas and oil production, the issuance of fixed rate notes and proceeds from the sale of certain oil and gas properties during the year. These cash flows were primarily used to fund our capital and exploration expenditures, repayments of borrowings under our revolving credit facility and related interest payments, share repurchases and the payment of dividends. See below for additional discussion and analysis of cash flow.
Operating cash flow fluctuations are substantially driven by commodity prices and changes in our production volumes and operating expenses. Prices for natural gas and crude oil have historically been volatile, including seasonal influences and demand; however, the impact of other risks and uncertainties have also influenced prices throughout the recent years. In addition, fluctuations in cash flow may result in an increase or decrease in our capital and exploration expenditures. See "Results of Operations" for a review of the impact of prices and volumes on revenues.
Our working capital is also substantially influenced by the variables discussed above. From time to time, our working capital will reflect a surplus, while at other times it will reflect a deficit. This fluctuation is not unusual. We believe we have adequate availability under our revolving credit facility and liquidity available to meet our working capital requirements.
 
Year Ended December 31,
(In thousands)
2014
 
2013
 
2012
Cash flows provided by operating activities
$
1,236,435

 
$
1,024,526

 
$
652,093

Cash flows used in investing activities
(1,664,840
)
 
(918,207
)
 
(765,514
)
Cash flows provided by (used in) financing activities
425,959

 
(113,655
)
 
114,246

Net increase (decrease) in cash and cash equivalents
$
(2,446
)
 
$
(7,336
)
 
$
825

Operating Activities. Net cash provided by operating activities in 2014 increased by $211.9 million over 2013. This increase was primarily due to higher operating revenues, partially offset by higher operating expenses (excluding non-cash expenses) and an increase in working capital. The increase in operating revenues was primarily due to an increase in equivalent production, partially offset by a decrease in realized natural gas and crude oil prices. Equivalent production volumes increased by 29% for 2014 compared to 2013 as a result of higher natural gas and oil production. Average realized natural gas and crude oil prices decreased by 8% and 12%, respectively, for 2014 compared to 2013.
Net cash provided by operating activities in 2013 increased by $372.4 million over 2012. This increase was primarily due to higher operating revenues partially offset by higher operating expenses (excluding non-cash expenses) and unfavorable changes in working capital and other assets and liabilities. The increase in operating revenues was primarily due to an increase in equivalent production, partially offset by lower realized natural gas and crude oil prices. Equivalent production volumes increased by 55% for 2013 compared to 2012 as a result of higher natural gas and crude oil production. Average realized natural gas and crude oil prices decreased by 3% and less than 1%, respectively, for 2013 compared to 2012.

37


See "Results of Operations" for additional information relative to commodity price, production and operating expense movements. We are unable to predict future commodity prices and, as a result, cannot provide any assurance about future levels of net cash provided by operating activities. Realized prices may decline in future periods.
Investing Activities. Cash flows used in investing activities increased by $746.6 million from 2013 to 2014 due to a $284.9 million increase in capital and exploration expenditures, a decrease of $284.0 million in proceeds from the sale of assets, a $214.7 million increase in acquisition expenditures related to the acquisitions of Eagle Ford Shale assets that closed in the fourth quarter of 2014, and a $19.2 million increase in capital contributions associated with our equity investments. Partially offsetting the increases was a $56.2 million decrease in restricted cash related to the release of funds by our qualified intermediary due to a lapse in the statutory holding period and the funding of oil and gas lease acquisitions during 2014 associated with like-kind exchange transactions pursuant to Section 1031 of the Internal Revenue Code.
Cash flows used in investing activities increased by $152.7 million from 2012 to 2013 due to a $266.8 million increase in capital and exploration expenditures and a $12.0 million increase associated with our equity investment in Constitution. These increases were partially offset by a net $126.1 million increase in proceeds from the sale of assets, a portion of which was retained in a qualified intermediary and recognized as restricted cash on the Consolidated Balance Sheet.
Financing Activities. Cash flows provided by financing activities increased by $539.6 million from 2013 to 2014 due to $545.0 million of higher net borrowings and a decrease in share repurchases of $25.8 million, partially offset by a decrease of $20.3 million in tax benefits associated with our stock-based compensation, an $8.0 million increase in dividends paid and an increase in cash paid for capitalized debt issuance costs of $2.9 million.
Cash flows used in financing activities increased by $227.9 million from 2012 to 2013 due to $164.6 million of stock repurchases, $77.0 million of lower net borrowings and an increase in dividends paid of $8.5 million, partially offset by an $18.9 million increase in the tax benefit associated with our stock‑based compensation and a decrease in cash paid for capitalized debt issuance costs of $2.3 million.
In September 2014, we completed a private placement of $925 million aggregate principal amount of senior unsecured fixed rate notes with a weighted-average interest rate of 3.65%, consisting of amounts due in 2021, 2024 and 2026.
Effective April 15, 2014, the lenders under our revolving credit facility approved an increase in our borrowing base from $2.3 billion to $3.1 billion as part of the annual redetermination under the terms of the revolving credit facility agreement. The commitments under the revolving credit facility remain unchanged at $1.4 billion. See Note 5 of the Notes to the Consolidated Financial Statements for further details.
At December 31, 2014, we had $140.0 million of borrowings outstanding under our revolving credit facility at a weighted-average interest rate of 2.4% compared to $460.0 million of borrowings outstanding at a weighted-average interest rate of 2.0% at December 31, 2013. As of December 31, 2014, we had $1.3 billion available for future borrowings under our revolving credit facility.
We were in compliance with all restrictive financial covenants in both the revolving credit facility and fixed rate notes as of December 31, 2014.
We strive to manage our debt at a level below the available credit line in order to maintain borrowing capacity. Our revolving credit facility includes a covenant limiting our total debt. Management believes that, with internally generated cash flow, existing cash on hand and availability under our revolving credit facility, we have the capacity to finance our spending plans and maintain our strong financial position.

38


Capitalization
Information about our capitalization is as follows:
 
December 31,
(Dollars in thousands)
2014
 
2013
Debt(1)
$
1,752,000

 
$
1,147,000

Stockholders' equity
2,142,733

 
2,204,602

Total capitalization
$
3,894,733

 
$
3,351,602

Debt to capitalization
45
%
 
34
%
Cash and cash equivalents
$
20,954

 
$
23,400

_______________________________________________________________________________
(1)
Includes $140.0 million and $460.0 million of borrowings outstanding under our revolving credit facility at December 31, 2014 and 2013, respectively.
For the years ended December 31, 2014 and 2013, we repurchased 4.3 million shares for a total cost of $138.9 million and 4.8 million shares for a total cost of $164.6 million, respectively. During 2014 and 2013, we also paid dividends of $33.3 million ($0.08 per share) and $25.2 million ($0.06 per share) on our common stock, respectively. A regular dividend has been declared for each quarter since we became a public company in 1990.
Capital and Exploration Expenditures
On an annual basis, we generally fund most of our capital and exploration expenditures, excluding any significant property acquisitions, with cash generated from operations and, when necessary, borrowings under our revolving credit facility. We budget these expenditures based on our projected cash flows for the year.
The following table presents major components of our capital and exploration expenditures:
 
Year Ended December 31,
(In thousands)
2014
 
2013
 
2012
Capital Expenditures
 

 
 

 
 

Drilling and facilities
$
1,454,288

 
$
1,096,705

 
$
843,528

Leasehold acquisitions
73,962

 
71,106

 
88,880

Property acquisitions
214,737

 
128

 

Pipeline and gathering
1,287

 
1,222

 
94

Other
14,791

 
8,816

 
8,547

 
1,759,065

 
1,177,977

 
941,049

Exploration expense
28,746

 
18,165

 
37,476

Total
$
1,787,811

 
$
1,196,142

 
$
978,525

We plan to drill approximately 125 gross wells (or 115.0 net) in 2015 compared to 200 gross wells (176.5 net) drilled in 2014. In 2015, we plan to spend approximately $900.0 million in total capital and exploration expenditures, compared to $1.6 billion (excluding property acquisitions of $214.7 million, as discussed in Note 2 to the Consolidated Financial Statements) in 2014. Due to the weak commodity price environment, our overall capital and exploration spending in 2015 is expected to be lower than our expenditures in 2014. We will continue to assess the natural gas and crude oil price environment and our liquidity position and may increase or decrease our capital and exploration expenditures accordingly.

39


Contractual Obligations
A summary of our contractual obligations as of December 31, 2014 are set forth in the following table:
 
 
 
Payments Due by Year
(In thousands)
Total
 
2015
 
2016 to 2017
 
2018 to 2019
 
2020 & Beyond
Long-term debt
$
1,752,000

 
$

 
$
160,000

 
$
312,000

 
$
1,280,000

Interest on long-term debt(1)
590,597

 
82,595

 
160,842

 
125,375

 
221,785

Transportation and gathering agreements(2)
1,950,612

 
130,411

 
325,248

 
268,162

 
1,226,791

Drilling rig commitments(2)
21,428

 
14,399

 
7,029

 

 

Operating leases(2)
25,813

 
5,818

 
6,342

 
4,189

 
9,464

Equity investment contribution commitments(3)
275,002

 
69,833

 
194,825

 
10,344

 

Total contractual obligations
$
4,615,452

 
$
303,056

 
$
854,286

 
$
720,070

 
$
2,738,040

_______________________________________________________________________________
(1)
Interest payments have been calculated utilizing the fixed rates associated with our fixed rate notes outstanding at December 31, 2014. Interest payments on our revolving credit facility were calculated by assuming that the December 31, 2014 outstanding balance of $140.0 million will be outstanding through the May 2017 maturity date and that our fixed rate notes will remain outstanding through their respective maturity dates. A constant interest rate of 2.4% was assumed for the interest payments on our revolving credit facility, which was the December 31, 2014 weighted-average interest rate. Actual results will differ from these estimates and assumptions.
(2)
In January 2015, we entered into a natural gas transportation agreement associated with our production in Pennsylvania, which increased our future aggregate obligations under our transportation commitments by approximately $105.9 million over the next 10 years, which is not included in the table above. For further information on our obligations under transportation and gathering agreements, drilling rig commitments and operating leases, see Note 9 of the Notes to the Consolidated Financial Statements.
(3)
For further information on our equity investment contribution commitment, see Note 4 of the Notes to the Consolidated Financial Statements.
Amounts related to our asset retirement obligation are not included in the above table given the uncertainty regarding the actual timing of such expenditures. The total amount of our asset retirement obligation at December 31, 2014 was $126.7 million. See Note 8 of the Notes to the Consolidated Financial Statements for further details.
We have no off-balance sheet debt or other similar unrecorded obligations.
Potential Impact of Our Critical Accounting Policies
Readers of this document and users of the information contained in it should be aware of how certain events may impact our financial results based on the accounting policies in place. Our most significant policies are discussed below.
Successful Efforts Method of Accounting
We follow the successful efforts method of accounting for our oil and gas producing activities. Acquisition costs for proved and unproved properties are capitalized when incurred. Exploration costs, including geological and geophysical costs, the costs of carrying and retaining unproved properties and exploratory dry hole costs are expensed. Development costs, including costs to drill and equip development wells and successful exploratory drilling costs to locate proved reserves are capitalized.
Oil and Gas Reserves
The process of estimating quantities of proved reserves is 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 crude oil and natural gas prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds. Any significant variance in the interpretations or assumptions could materially affect the estimated quantity and value of our reserves.

40


Our reserves have been prepared by our petroleum engineering staff and audited by Miller and Lents, independent petroleum engineers, who in their opinion determined the estimates presented to be reasonable in the aggregate. For more information regarding reserve estimation, including historical reserve revisions, refer to the Supplemental Oil and Gas Information to the Consolidated Financial Statements included in Item 8.
Our rate of recording DD&A expense is dependent upon our estimate of proved and proved developed reserves, which are utilized in our unit-of-production calculation. If the estimates of proved reserves were to be reduced, the rate at which we record DD&A expense would increase, reducing net income. Such a reduction in reserves may result from lower market prices, which may make it uneconomic to drill and produce higher cost fields. A 5% positive or negative revision to proved reserves would result in a decrease of $0.05 per Mcfe and an increase of $0.05 per Mcfe, respectively, on our DD&A rate. Revisions in significant fields may individually affect our DD&A rate. It is estimated that a positive or negative reserve revision of 10% in one of our most productive fields would result in a decrease of $0.05 per Mcfe and an increase of $0.07 per Mcfe, respectively, on our total DD&A rate. These estimated impacts are based on current data, and actual events could require different adjustments to our DD&A rate.
In addition, a decline in proved reserve estimates may impact the outcome of our impairment test under applicable accounting standards. Due to the inherent imprecision of the reserve estimation process, risks associated with the operations of proved producing properties and market sensitive commodity prices utilized in our impairment analysis, management cannot determine if an impairment is reasonably likely to occur in the future.
Carrying Value of Oil and Gas Properties
We evaluate our proved oil and gas properties for impairment on a field-by-field basis whenever events or changes in circumstances indicate an asset's carrying amount may not be recoverable. We compare expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted expected cash flows, based on our estimate of future natural gas and crude oil prices, operating costs and anticipated production from proved reserves and risk-adjusted probable and possible reserves, are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of assumptions management uses in its budgeting and forecasting process, historical and current prices adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. In the event that commodity prices remain low or decline, there could be a significant revision in the future. Fair value is calculated by discounting the future cash flows. The discount factor used is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying natural gas and oil.
Unproved oil and gas properties are assessed periodically for impairment on an aggregate basis through periodic updates to our undeveloped acreage amortization based on past drilling and exploration experience, our expectation of converting leases to held by production and average property lives. Average property lives are determined on a geographical basis and based on the estimated life of unproved property leasehold rights. Historically, the average property life in each of the geographical areas has not significantly changed and generally range from three to five years. The commodity price environment may impact the capital available for exploration projects as well as development drilling. We have considered these impacts when determining the amortization rate of our undeveloped acreage, especially in exploratory areas. If the average unproved property life decreases or increases by one year, the amortization would increase by approximately $21.8 million or decrease by approximately $14.8 million, respectively, per year.
As these properties are developed and reserves are proved, the remaining capitalized costs are subject to depreciation and depletion. If the development of these properties is deemed unsuccessful, the capitalized costs related to the unsuccessful activity is expensed in the year the determination is made. The rate at which the unproved properties are written off depends on the timing and success of our future exploration and development program.
Asset Retirement Obligations
The majority of our asset retirement obligations (ARO) relates to the plugging and abandonment of oil and gas wells and to a lesser extent meter stations, pipelines, processing plants and compressors. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying amount of the related long-lived asset. The recognition of an asset retirement obligation requires management to make assumptions that include estimated plugging and abandonment costs, timing of settlements, inflation rates and discount rate. In periods subsequent to initial measurement, the asset retirement cost is depreciated using the units-of-production method, while increases in the discounted ARO liability resulting from the passage of time (accretion expense) are reflected as depreciation, depletion and amortization expense.

41


Accounting for Derivative Instruments and Hedging Activities
Under applicable accounting standards, the fair value of each derivative instrument is recorded as either an asset or liability on the balance sheet. At the end of each quarterly period, these instruments are marked-to-market.
Through March 31, 2014, we elected to designate our commodity derivatives as cash flow hedges for accounting purposes. Effective April 1, 2014, we elected to discontinue hedge accounting for our commodity derivatives on a prospective basis. Accordingly, the change in the fair value of derivatives designated as cash flow hedges that were effective was recorded to accumulated other comprehensive income (loss) in stockholders’ equity in the Consolidated Balance Sheet. The ineffective portion of the change in the fair value of derivatives designated as cash flow hedges and the change in fair value of derivatives not designated as hedges are recorded as a component of operating revenues in gain (loss) on derivative instruments in the Consolidated Statement of Operations.
Our derivative contracts are measured based on quotes from our counterparties. Such quotes have been derived using an income approach that considers various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, basis differentials, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term, as applicable. These estimates are verified using relevant NYMEX futures contracts or are compared to multiple quotes obtained from counterparties for reasonableness. The determination of fair value also incorporates a credit adjustment for non-performance risk. We measure the non-performance risk of our counterparties by reviewing credit default swap spreads for the various financial institutions in which we have derivative transactions, while our non-performance risk is evaluated using a market credit spread provided by one of our banks.
Employee Benefit Plans
Our costs of long-term employee benefits, particularly postretirement benefits, are incurred over long periods of time, and involve many uncertainties over those periods. The net periodic benefit cost attributable to current periods is based on several assumptions about such future uncertainties, and is sensitive to changes in those assumptions. It is management's responsibility, often with the assistance of independent experts, to select assumptions that in its judgment represent best estimates of those uncertainties. It also is management's responsibility to review those assumptions periodically to reflect changes in economic or other factors that affect those assumptions. Significant assumptions used to determine our postretirement benefit obligation and related costs include discount rates and health care cost trends. See Note 11 of the Notes to the Consolidated Financial Statements for further discussion relative to our employee benefit plans.
Stock-Based Compensation
We account for stock-based compensation under the fair value method of accounting in accordance with applicable accounting standards. Under the fair value method, compensation cost is measured at the grant date for equity-classified awards and remeasured each reporting period for liability-classified awards based on the fair value of an award and is recognized over the service period, which is generally the vesting period. To calculate fair value, we use either a Monte Carlo or Black-Scholes valuation model, as determined by the specific provisions of the award. The use of these models requires significant judgment with respect to expected life, volatility and other factors. Stock-based compensation cost for all types of awards is included in general and administrative expense in the Consolidated Statement of Operations. See Note 13 of the Notes to the Consolidated Financial Statements for a full discussion of our stock-based compensation.
Recent Accounting Pronouncements
In April 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The guidance applies prospectively to new disposals and new classifications of disposal groups as held for sale after the effective date. The guidance is effective for interim and annual periods beginning on or after December 15, 2014. We do not expect the adoption of this guidance to have a material impact on our financial position, results of operations or cash flows.
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, as a new Topic, Accounting Standards Codification Topic 606. The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU is effective beginning in fiscal year 2017 and can be adopted either retrospectively or as a cumulative-effect adjustment as of the date of adoption. We are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations or cash flows.

42


In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements - Going Concern, as a new Sub-topic, Accounting Standards Codification Sub-topic 205.40. The new going concern standard codifies in generally accepted accounting principles (GAAP) management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. This ASU is effective for interim and annual periods beginning on or after December 15, 2016 and early adoption is permitted. We do not expect the adoption of this guidance to have a material impact on our financial position or results of operations.
OTHER ISSUES AND CONTINGENCIES
Regulations.    Our operations are subject to various types of regulation by federal, state and local authorities. See "Regulation of Oil and Natural Gas Exploration and Production," "Natural Gas Marketing, Gathering and Transportation," "Federal Regulation of Petroleum," "Pipeline Safety Regulation," and "Environmental and Safety Regulations" in the "Other Business Matters" section of Item 1 for a discussion of these regulations.
Restrictive Covenants.    Our ability to incur debt and to make certain types of investments is subject to certain restrictive covenants in our various debt instruments. Among other requirements, our revolving credit agreement and our fixed rate notes specify a minimum annual coverage ratio of consolidated cash flow to interest expense for the trailing four quarters of 2.8 to 1.0 and a minimum asset coverage ratio of the present value of proved reserves plus adjusted cash to indebtedness and other liabilities of 1.75 to 1.0. Our revolving credit agreement also requires us to maintain a minimum current ratio of 1.0 to 1.0. At December 31, 2014, we were in compliance with all restrictive financial covenants in both the revolving credit agreement and fixed rate notes. In the unforeseen event that we fail to comply with these covenants, we may apply for a temporary waiver with the lender, which, if granted, would allow us a period of time to remedy the situation.
Operating Risks and Insurance Coverage.    Our business involves a variety of operating risks. See "Risk Factors—We face a variety of hazards and risks that could cause substantial financial losses" in Item 1A. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. The costs of these insurance policies are somewhat dependent on our historical claims experience, the areas in which we operate and market conditions.
Commodity Pricing and Risk Management Activities.    Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and crude oil. Declines in natural gas and crude oil prices may have a material adverse effect on our financial condition, liquidity, ability to obtain financing and operating results. Lower natural gas and crude oil prices also may reduce the amount of natural gas and crude oil that we can produce economically. Historically, natural gas and crude oil prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Depressed prices in the future would have a negative impact on our future financial results. In particular, substantially lower prices would significantly reduce revenue and could potentially trigger an impairment of our long-lived assets. Because our reserves are predominantly natural gas (approximately 96% of equivalent proved reserves), changes in natural gas prices may have a more significant impact on our financial results than oil prices.
The majority of our production is sold at market responsive prices. Generally, if the related commodity index declines, the price that we receive for our production will also decline. Therefore, the amount of revenue that we realize is partially determined by factors beyond our control. However, management may mitigate this price risk on all or a portion of our anticipated production with the use of commodity derivatives. Most recently, we have used commodity derivatives such as collar and swap arrangements to reduce the impact of declining prices on our revenue. Under both arrangements, there is also a risk that the movement of index prices may result in our inability to realize the full benefit of an improvement in market conditions.
RESULTS OF OPERATIONS
2014 and 2013 Compared
We reported net income for 2014 of $104.5 million, or $0.25 per share, compared to net income for 2013 of $279.8 million, or $0.67 per share. The decrease in net income was due to higher operating expenses, partially offset by an increase in operating revenues and an increase in income tax benefit.

43


Revenue, Price and Volume Variances
Our revenues vary from year to year as a result of changes in commodity prices and production volumes. Below is a discussion of revenue, price and volume variances.
 
Year Ended December 31,
 
Variance
Revenue Variances (In thousands)
2014
 
2013
 
Amount
 
Percent
Natural gas
$
1,590,625

 
$
1,405,262

 
$
185,363

 
13
 %
Crude oil and condensate
313,889

 
291,418

 
22,471

 
8
 %
Gain (loss) on derivative instruments
219,319

 

 
219,319

 
100
 %
Brokered natural gas
34,416

 
36,450

 
(2,034
)
 
(6
)%
Other
14,762

 
13,148

 
1,614

 
12
 %
 
$
2,173,011

 
$
1,746,278

 
$
426,733

 
24
 %
 
Year Ended
December 31,
 
Variance
Increase
(Decrease)
(In thousands)
 
 
2014
 
2013
 
Amount
 
Percent
Price Variances
 

 
 

 
 

 
 

 
 

Natural gas(1)
$
3.13

 
$
3.56

 
$
(0.43
)
 
(12
)%
 
$
(220,273
)
Crude oil and condensate(2)
$
87.48

 
$
101.13

 
$
(13.65
)
 
(13
)%
 
(48,973
)
Total
 

 
 

 
 

 
 

 
$
(269,246
)
Volume Variances
 

 
 

 
 

 
 

 
 

Natural gas (Bcf)
508.0

 
394.2

 
113.8

 
29
 %
 
$
405,636

Crude oil and condensate (Mbbl)
3,588

 
2,882

 
706

 
24
 %
 
71,444

Total
 

 
 

 
 

 
 

 
$
477,080

_______________________________________________________________________________
(1)
These prices include the realized impact of cash flow hedge settlements, which decreased the price by $0.28 per Mcf in 2014 and increased the price by $0.13 per Mcf in 2013.
(2)
These prices include the realized impact of cash flow hedge settlements, which decreased the price by $0.17 per Bbl in 2014 and increased the price by $1.48 per Bbl in 2013.
Natural Gas Revenues
The increase in natural gas revenues of $185.4 million is due to higher production, partially offset by lower natural gas prices. The increase in our production was the result of our Marcellus Shale drilling program in Pennsylvania, partially offset by lower production primarily in Oklahoma and west Texas as a result of certain non-core asset dispositions in the fourth quarter of 2013 and normal production declines in Texas and West Virginia.
Crude Oil and Condensate Revenues
The increase in crude oil and condensate revenues of $22.5 million is due to higher production, partially offset by lower crude oil prices. The increase in production was a result of our oil-focused Eagle Ford Shale drilling program in south Texas, partially offset by lower production associated with certain non-core asset dispositions in Oklahoma and west Texas in the fourth quarter of 2013.
Gain (Loss) on Derivative Instruments
Effective April 1, 2014, we elected to discontinue hedge accounting on a prospective basis. Subsequent to April 1, 2014, our derivative instruments were accounted for on a mark-to-market basis with changes in fair value recognized currently in operating revenues in the Consolidated Statement of Operations. Gain (loss) on derivative instruments includes an $81.7 million gain related to the change in fair value of realized cash settlements of derivative instruments previously frozen in accumulated other comprehensive income (loss) and a $137.6 million unrealized mark-to-market gain on our commodity derivative instruments.

44


Impact of Derivative Instruments on Operating Revenues
The following table reflects the realized and unrealized gain (loss) of our derivative instruments:
 
Year Ended
December 31,
(In thousands)
2014
 
2013
Realized
 

 
 

Natural gas
$
(143,577
)
 
$
52,733

Crude oil and condensate
(626
)
 
4,269

Gain (loss) on derivative instruments
81,716

 

 
$
(62,487
)
 
$
57,002

Unrealized
 

 
 

Gain (loss) on derivative instruments
137,603

 

 
$
75,116

 
$
57,002

Brokered Natural Gas
 
 
Year Ended
December 31,
 
 
 
Price and
Volume
Variances (In thousands)
 
 
2014
 
 
2013
 
Amount
 
Percent
 
Brokered Natural Gas Sales
 
 

 
 
 

 
 

 
 

 
 

Sales price ($/Mcf)
$
4.65

 
$
4.11

 
$
0.54

 
13
 %
 
$
3,997

Volume brokered (Mmcf)
x
7,402

 
x
8,874

 
(1,472
)
 
(17
)%
 
(6,031
)
Brokered natural gas (In thousands)
$
34,416

 
$
36,450

 
 

 
 

 
$
(2,034
)
Brokered Natural Gas Purchases
 
 

 
 
 

 
 

 
 

 
 

Purchase price ($/Mcf)
$
4.06

 
$
3.37

 
$
0.69

 
20
 %
 
$
(5,134
)
Volume brokered (Mmcf)
x
7,402

 
x
8,874

 
(1,472
)
 
(17
)%
 
5,040

Brokered natural gas (In thousands)
$
30,030

 
$
29,936

 
 

 
 

 
$
(94
)
Brokered natural gas margin (In thousands)
$
4,386

 
$
6,514

 
 

 
 

 
$
(2,128
)
The $2.1 million decrease in brokered natural gas margin is a result of lower brokered volumes and an increase in purchase price that outpaced the increase in sales price.

45


Operating and Other Expenses
 
Year Ended December 31,
 
Variance
(In thousands)
2014
 
2013
 
Amount
 
Percent
Operating and Other Expenses
 

 
 

 
 

 
 

Direct operations
$
145,529

 
$
140,856

 
$
4,673

 
3
 %
Transportation and gathering
349,321

 
229,489

 
119,832

 
52
 %
Brokered natural gas
30,030

 
29,936

 
94

 
 %
Taxes other than income
47,012

 
43,045

 
3,967

 
9
 %
Exploration
28,746

 
18,165

 
10,581

 
58
 %
Depreciation, depletion and amortization
632,760

 
651,052

 
(18,292
)
 
(3
)%
Impairment of oil and gas properties
771,037

 

 
771,037

 
100
 %
General and administrative
82,590

 
104,606

 
(22,016
)
 
(21
)%
Total operating expense
$
2,087,025

 
$
1,217,149

 
$
869,876

 
71
 %
 
 
 
 
 
 
 
 
Earnings (loss) on equity method investments
$
3,080

 
$
1,102

 
$
1,978

 
179
 %
Gain (loss) on sale of assets
17,120

 
21,351

 
(4,231
)
 
(20
)%
Interest expense
73,785

 
66,044

 
7,741

 
12
 %
Income tax (benefit) expense
(72,067
)
 
205,765

 
(277,832
)
 
(135
)%
Total costs and expenses from operations increased by $869.9 million from 2013 to 2014. The primary reasons for this fluctuation are as follows:
Direct operations increased $4.7 million largely due to higher operating costs as a result of higher production, an increase in disposal and recycling costs related to our Marcellus Shale operations and an increase in costs associated with oil processing and related fuel charges related to our Eagle Ford Shale operations. Partially offsetting these increases were lower costs associated with certain non-core assets in Oklahoma and west Texas that were sold in the fourth quarter of 2013.
Transportation and gathering increased $119.8 million due to higher throughput as a result of higher production, slightly higher transportation rates and the commencement of various transportation and gathering agreements in late 2013 and during 2014.
Brokered natural gas increased $0.1 million from 2013 to 2014. See the preceding table titled "Brokered Natural Gas" for further analysis.
Taxes other than income increased $4.0 million due to $2.5 million higher drilling impact fees associated with our Marcellus Shale drilling activities, $2.5 million higher production taxes and $0.9 million higher franchise and other taxes. Production taxes increased due to higher oil production in south Texas, offset by taxes associated with certain non-core assets in Oklahoma and west Texas that were sold in the fourth quarter of 2013. These increases are partially offset by a $1.9 million decrease in ad valorem taxes.
Exploration increased $10.6 million as a result of higher exploratory dry hole costs of $7.5 million and higher geophysical and geological and other expenses.
Depreciation, depletion and amortization decreased $18.3 million due to a $36.2 million decrease in amortization of unproved properties in 2014 due to lower amortization rates as a result of favorable results from our drilling program in Pennsylvania. This decrease was partially offset by a net increase in depreciation and depletion of $14.6 million, consisting of a $167.6 million increase due to higher equivalent production volumes for 2014 compared to 2013, partially offset by a decrease of $153.0 million due to a lower DD&A rate of $1.13 per Mcfe for 2014 compared to $1.42 per Mcfe for 2013. The lower DD&A rate was primarily due to lower cost of reserve additions associated with our Marcellus Shale drilling program and the impact of the disposition of higher rate fields in Oklahoma and west Texas in the fourth quarter of 2013.
Impairment of oil and gas properties was $771.0 million in 2014 due to the impairment of certain non-core fields, primarily in east Texas. The impairment of these fields was due to a significant decline in commodity prices in late

46


2014 and management's decision not to pursue activity in these non-core areas in the current price environment. There was no impairment in 2013.
General and administrative decreased $22.0 million due to lower stock-based compensation expense of $30.4 million associated with the mark-to-market of our liability-based performance awards and our supplemental employee incentive plan due to changes in our stock price during 2014 compared to 2013 and lower employee-related expenses. These decreases were partially offset by increases in professional fees.
Earnings (loss) on equity method investments. The increase in equity method investments is the result of the increase in our proportionate share of net earnings from our equity method investments in 2014 compared to 2013.
Gain (Loss) on Sale of Assets.    During 2014, we recognized an aggregate gain of $17.1 million primarily due to the sale of certain proved and unproved oil and gas properties in east Texas. During 2013, we recognized an aggregate net gain of $21.4 million, which includes a $19.4 million gain from the sale of certain proved and unproved oil and gas properties located in the Oklahoma and Texas panhandles and a $17.5 million loss from the sale of certain proved and unproved oil and gas properties located in Oklahoma, Texas and Kansas. We also sold various other proved and unproved properties in 2013 for a net gain of $19.5 million.

Interest Expense.    Interest expense increased $7.7 million as a result of an increase in interest expense of $9.7 million associated with our private placement in September 2014 of $925 million aggregate principal amount of senior unsecured fixed rate notes with a weighted-average interest rate of 3.65%, higher commitment fees of $2.3 million and increased amortization of debt issuance costs of $1.1 million. These increases were partially offset by a decrease in interest expense of $3.1 million due to the repayment of $75.0 million of our 7.33% weighted-average fixed rate notes in July 2013 and $1.1 million associated with our revolving credit facility due to a decrease in weighted-average borrowings based on daily balances of approximately $410.0 million compared to approximately $454.4 million during 2014 and 2013, respectively.

Income Tax Expense.    Income tax expense decreased $277.8 million due to a decrease in pretax income and a lower effective tax rate.  The effective tax rates for 2014 and 2013 were (222.4)% and 42.4%, respectively. The effective tax rate was lower as a result of a change in estimated net deferred state tax liabilities reflected in our Consolidated Balance Sheet, which were based on updated state apportionment factors in states in which we operate.
2013 and 2012 Compared
We reported net income for 2013 of $279.8 million, or $0.67 per share, compared to net income for 2012 of $131.7 million, or $0.31 per share. The increase in net income was primarily due to an increase in natural gas and crude oil and condensate revenues, partially offset higher operating expenses.
Revenue, Price and Volume Variances
Our revenues vary from year to year as a result of changes in commodity prices and production volumes. Below is a discussion of revenue, price and volume variances.
 
Year Ended
December 31,
 
Variance
Revenue Variances (In thousands)
2013
 
2012
 
Amount
 
Percent
Natural gas
$
1,405,262

 
$
934,134

 
$
471,128

 
50
%
Crude oil and condensate
291,418

 
227,933

 
63,485

 
28
%
Gain (loss) on derivative instruments

 
(494
)
 
494

 
100
%
Brokered natural gas
36,450

 
34,005

 
2,445

 
7
%
Other
13,148

 
8,968

 
4,180

 
47
%
 
$
1,746,278

 
$
1,204,546

 
$
541,732

 
45
%

47


 
Year Ended
December 31,
 
Variance
 
Increase
(Decrease)
(In thousands)
 
 
2013
 
2012
 
Amount
 
Percent
 
Price Variances
 

 
 

 
 

 
 

 
 

Natural gas(1)
$
3.56

 
$
3.67

 
$
(0.11
)
 
(3
)%
 
$
(43,290
)
Crude oil and condensate(2)
$
101.13

 
$
101.65

 
$
(0.52
)
 
(1
)%
 
(1,571
)
Total
 

 
 

 
 

 
 

 
$
(44,861
)
Volume Variances
 

 
 

 
 

 
 

 
 

Natural gas (Bcf)
394.2

 
253.2

 
141.0

 
56
 %
 
$
514,418

Crude oil and condensate (Mbbl)
2,882

 
2,242

 
640

 
29
 %
 
65,056

Total
 

 
 

 
 

 
 

 
$
579,474

_______________________________________________________________________________
(1)
These prices include the realized impact of cash flow hedge settlements, which increased the price by $0.13 per Mcf in 2013 and $0.89 per Mcf in 2012.
(2)
These prices include the realized impact of cash flow hedge settlements, which increased the price by $1.48 per Bbl in 2013 and $5.00 per Bbl in 2012.
Natural Gas Revenues
The increase in natural gas revenues of $471.1 million is due to higher production, partially offset by lower natural gas prices. The increase in our production was the result of our Marcellus Shale drilling program in Pennsylvania and expanded infrastructure in the area, partially offset by lower production primarily in Texas, Oklahoma and West Virginia due to reduced natural gas drilling in these areas and normal production declines.
Crude Oil and Condensate Revenues
The increase in crude oil and condensate revenues of $63.5 million is due to higher production associated with our oil‑focused Eagle Ford Shale drilling program in south Texas and, to a lesser extent, Oklahoma, partially offset by lower crude oil prices.
Impact of Derivative Instruments on Operating Revenues
The following table reflects the realized and unrealized gain (loss) of our derivative instruments:
 
Year Ended
December 31,
(In thousands)
2013
 
2012
Realized
 

 
 

Natural gas
$
52,733

 
$
225,108

Crude oil and condensate
4,269

 
11,218

 
$
57,002

 
$
236,326

Unrealized
 

 
 

Gain (loss) on derivative instruments

 
(494
)
 
$
57,002

 
$
235,832


48


Brokered Natural Gas
 
Year Ended
December 31,
 
Variance
 
Price and Volume Variances
(In thousands)
 
2013
 
2012
 
Amount
 
Percent
 
Brokered Natural Gas Sales
 
 

 
 
 

 
 

 
 

 
 

Sales price ($/Mcf)
$
4.11

 
$
3.57

 
$
0.54

 
15
 %
 
$
4,776

Volume brokered (Mmcf)
x
8,874

 
x
9,527

 
(653
)
 
(7
)%
 
(2,331
)
Brokered natural gas (In thousands)
$
36,450

 
$
34,005

 
 

 
 

 
$
2,445

Brokered Natural Gas Purchases