Range Resources Annual Report 2014

← All annual reports

FY2014 Annual Report · Range Resources

Loading PDF…

2014 Annual Report

Financial Highlights

PRO DUCTION
(Mmcfe per day)

PRO vED RESERv ES
(Tcfe)

1200

1100

1000

900

800

700

600

500

400

300

200

100

2.50

2.25

2.00

1.75

1.50

1.25

1.00

0.75

0.50

0.25

‘04

‘05

‘06

‘07

‘08

‘09

‘10

‘11

‘12

‘13

‘14

‘04

‘05

‘06

‘07

‘08

‘09

‘10

‘11

‘12

‘13

‘14

PRO DUCTION PER
SHAR E DEB T ADJU STED
(Mcfe)

RESERv ES PER
SH AR E D EB T A DJU STED
(Mcfe)

‘10

‘11

‘12

‘13

‘14

‘10

‘11

‘12

‘13

‘14

10 Years in the Marcellus Shale

2014 marked the 10-year anniversary of the successful completion
of the Renz #1 well in Washington County, PA – and the discovery of
what is now the largest producing gas field in North America.

It has been a tremendous honor and privilege to play a leading role

in the development of a resource that supports more than 240,000
jobs across the state of Pennsylvania, while helping to improve air
quality, reduce consumer energy costs, and provide new opportu-
nities for domestic manufacturing. Perhaps most importantly, the
Marcellus is helping the United States to become more energy secure.
Range would like to congratulate all of the men and women who
helped to develop the Marcellus, including the many landowners who
have chosen to sign leases with Range.

While there will always be challenges in any industry, we’re confi-

dent that the best is yet to come.

Dear Fellow Shareholders:

In 2014, Range Resources achieved key milestones that I believe position the Company well
for the future. We grew production by 24%, while also driving down our cost structure and
(cid:90)(cid:92)(cid:73)(cid:90)(cid:91)(cid:72)(cid:85)(cid:91)(cid:80)(cid:72)(cid:83)(cid:83)(cid:96)(cid:3)(cid:80)(cid:85)(cid:74)(cid:89)(cid:76)(cid:72)(cid:90)(cid:80)(cid:85)(cid:78)(cid:3)(cid:86)(cid:92)(cid:89)(cid:3)(cid:74)(cid:72)(cid:87)(cid:80)(cid:91)(cid:72)(cid:83)(cid:3)(cid:76)(cid:77)(cid:196)(cid:74)(cid:80)(cid:76)(cid:85)(cid:74)(cid:80)(cid:76)(cid:90)(cid:21)(cid:3)(cid:57)(cid:76)(cid:90)(cid:76)(cid:89)(cid:93)(cid:76)(cid:90)(cid:3)(cid:72)(cid:85)(cid:75)(cid:3)(cid:87)(cid:89)(cid:86)(cid:75)(cid:92)(cid:74)(cid:91)(cid:80)(cid:86)(cid:85)(cid:3)(cid:87)(cid:76)(cid:89)(cid:3)(cid:75)(cid:76)(cid:73)(cid:91)(cid:20)(cid:72)(cid:75)(cid:81)(cid:92)(cid:90)(cid:91)(cid:76)(cid:75)(cid:3)
(cid:90)(cid:79)(cid:72)(cid:89)(cid:76)(cid:3)(cid:78)(cid:89)(cid:76)(cid:94)(cid:3)(cid:73)(cid:96)(cid:3)(cid:84)(cid:86)(cid:89)(cid:76)(cid:3)(cid:91)(cid:79)(cid:72)(cid:85)(cid:3)(cid:25)(cid:28)(cid:12)(cid:19)(cid:3)(cid:84)(cid:72)(cid:82)(cid:80)(cid:85)(cid:78)(cid:3)(cid:91)(cid:79)(cid:80)(cid:90)(cid:3)(cid:57)(cid:72)(cid:85)(cid:78)(cid:76)(cid:187)(cid:90)(cid:3)(cid:32)(cid:91)(cid:79)(cid:3)(cid:74)(cid:86)(cid:85)(cid:90)(cid:76)(cid:74)(cid:92)(cid:91)(cid:80)(cid:93)(cid:76)(cid:3)(cid:96)(cid:76)(cid:72)(cid:89)(cid:3)(cid:77)(cid:86)(cid:89)(cid:3)(cid:75)(cid:86)(cid:92)(cid:73)(cid:83)(cid:76)(cid:20)(cid:75)(cid:80)(cid:78)(cid:80)(cid:91)(cid:3)
growth in both of these important metrics. And we recorded net income of $634 million, over
(cid:196)(cid:93)(cid:76)(cid:3)(cid:91)(cid:80)(cid:84)(cid:76)(cid:90)(cid:3)(cid:79)(cid:80)(cid:78)(cid:79)(cid:76)(cid:89)(cid:3)(cid:91)(cid:79)(cid:72)(cid:85)(cid:3)(cid:83)(cid:72)(cid:90)(cid:91)(cid:3)(cid:96)(cid:76)(cid:72)(cid:89)(cid:187)(cid:90)(cid:3)(cid:11)(cid:24)(cid:24)(cid:29)(cid:3)(cid:84)(cid:80)(cid:83)(cid:83)(cid:80)(cid:86)(cid:85)(cid:21)(cid:3)(cid:3)

Industry-wide, 2014 presented challenges with the rapid erosion in
crude oil and NGL prices late in the year. But while the decline in
oil prices is a more recent trend, Range has been operating in a low
price environment since natural gas prices began to decline in 2008.
We believe that the high quality, low-cost drilling inventory that we
have built positions us well for down cycle pricing environments.
Despite the recent commodity market challenges, Range saw
reserves grow 26% in 2014 to 10.3 Tcfe, with all-in finding costs
of $0.64 per mcfe and drill-bit finding costs at $0.55 per mcfe. We
replaced 581% of production from drilling. As we’ve long asserted,
maintaining a low cost structure is critical, especially in a low
commodity price environment. We have reduced our total unit cost
by 43% since 2008, and in the last year our total unit cost is down
35 cents (10%). We expect this trend to continue. As our opera-
tional and technical teams continue to improve drilling and well
completion practices, our capital efficiency has increased substan-
tially since we pioneered Marcellus Shale development a decade ago.
Examples include faster drilling time by optimizing drill-bit design,
lower cost from using both air rigs and horizontal rigs, longer hor-
izontal laterals, improved formation targeting, improved recovery
from reduced cluster spacing completions, improved sand handling,
beneficial reuse of drill cuttings and continued improvement in
the use of even more environmentally sensitive technologies. These
improvements, innovations and new solutions will continue in the
months and years ahead. Some will result in lower costs, some in
increased recoveries, but all will drive greater capital efficiency.
In 2014, we also made significant progress in other areas.
We announced that our first Washington County, Pennsylvania,
Utica well achieved an average 24-hour test rate of 59.0 Mmcf
per day. This appears to be a record for any horizon drilled in
the Appalachian Basin and also currently represents the highest
test rate of any Utica well. By some accounts it may very well
be the largest unconventional oil or gas test rate onshore in the
United States. We believe it confirms our geological interpreta-
tion of the Utica formation in that area and enhances the value of
Range’s stacked-pay acreage position in southwest Pennsylvania.
We have a current leasehold position of approximately 525,000
net acres in the stacked-pay portion of southwest Pennsylvania,

with 400,000 acres prospective for the Utica. If each horizon is
looked at separately – the Upper Devonian, Marcellus and Utica
– Range’s stacked-pay acreage position totals approximately 1.6
million net acres.

The Mariner East pipeline, a project by our partners at Sunoco
Logistics, came on-line ahead of schedule in 2014, a development
we consider excellent news for Range and for job seekers and
consumers in southeast Pennsylvania. Mariner East gives Range
access to local propane markets in the northeast U.S., along with
great potential in the international marketplace. When fully opera-
tional in third quarter 2015, we expect to realize a $0.20 per gallon
transportation savings on propane shipped to eastern Pennsylvania.
Additionally, we will then have three ethane projects in our port-
folio: the Mariner West and ATEX pipelines, and the Mariner East
project. The revitalization of the Marcus Hook Industrial Complex,
a project outside of Philadelphia, is scheduled to be completed in
third quarter 2015, and we expect to begin shipping 20,000 barrels
of ethane per day to Europe. Once our three ethane outlets are fully
operational in 2016, we will have the ability to sell 55,000 barrels
per day of ethane. Range believes that over the long run, our liquids
portfolio results in a greater uplift in ethane revenue net of all costs,
compared to leaving the ethane in the gas stream. We are proud
of our marketing team and the expertise they continue to demon-
strate, including their work to secure Range with multiple ethane
solutions and options.

In mid-2014, we exchanged our Conger properties in the
Permian Basin of West Texas for the remaining 50% interest
in the Nora field in Virginia that we didn’t already own. Those
assets include 138,000 net acres along with 1,200 miles of
gathering lines and compression. Range also received $145
million in cash as part of the exchange. This acquisition of the
Nora field increased Range’s Virginia production to 110 MMcf
per day, our acreage grew to 365,000 gross and net, and we now
have full ownership of 1,530 miles of gathering pipelines along
with 83,000 horsepower of compression. Having full operational
control of these assets provides us with much greater flexibility
to market gas across the eastern seaboard, with growing demand
and some of the best natural gas prices in the United States.

On the financial front, we strengthened our balance sheet in
2014. In June, we successfully called our high coupon fixed rate
8% bonds, redeeming them with the proceeds from a $400 million
equity offering. We also entered a new five-year agreement with
a syndicate of twenty-nine banks with a maximum facility size of
$4 billion, an initial borrowing base of $3 billion and $2 billion in
credit commitments. This represents an increase in the borrowing
base of $1 billion and increased commitments of $250 million. The
agreement also reduces our borrowing costs by 25 basis points and
grants us the option to release all collateral upon the receipt of a
single investment grade rating. The maturity of this new facility was
extended to October 2019. Range’s current proved reserves support
the $3 billion borrowing base and significantly more, should we
choose to request it. We believe this new agreement demonstrates
Range’s continued progress in building a strong balance sheet which
will support us during low commodity prices as well as our future
growth. In September, Moody’s Investors Service upgraded Range’s
outlook to ‘Positive’ with a current corporate family rating of Ba1.
Additionally, Standard & Poor’s Ratings Services upgraded Range’s
corporate credit rating to BB+ in October.

Looking at health and safety, we saw productivity increase in
2014 as we closed out the year with zero hours lost due to injuries
sustained at work. Range reported a total recordable incident rate
of 0.51, one of the best rates we’ve had in the past five years despite
significant growth that included new employees and contractors.
And just as we continued our commitment to safety, so too did we
maintain our commitment to best environmental practices. We
refocused and realigned certain employees to better manage envi-
ronmental compliance and best practices. Innovations we tested
included a new surfactant (made up primarily of citrus oils) – early
testing indicates there is potential for increased production as well.
Our latest data also indicates that our already low greenhouse gas
emissions, on a unit of production basis, have declined 50% over
the past two years.

As I write this letter, 2015 is setting up to be a challenging
year for the oil and gas industry. Commodity prices are projected
to remain depressed for the year as the success of the horizon-
tal shale revolution has resulted in significant supply growth of
oil, gas and natural gas liquids. However, natural gas demand is
projected to increase, and combined with reductions in capital
budgets across the sector, this should result in reduced supply
growth and rebalancing of commodity prices. For years, we have
taken strategic steps to best position Range for the challenging
commodity markets that we see today. Our focus is on creating
long-term shareholder value by capitalizing on our large drilling
inventory, maintaining one of the lowest cost structures in the
industry, and identifying and implementing efficiencies across
our operations. It is this strategic approach that has positioned
Range to operate within the current commodity price environ-
ment and to prosper as supply and demand rebalance and com-
modity prices respond.

Responding to market conditions, we decreased our capital bud-
get for 2015 by 45% compared to 2014. Despite this reduction, we
anticipate growing production by 20% in 2015. We believe we have
the personnel, the large scale acreage position, and the gathering,
processing and product markets to grow our production to 3 Bcfe
per day and beyond. This is critical, because while the industry is
currently faced with pricing challenges, we believe the future holds
tremendous upside for natural gas demand. Companies like Range
who are well positioned should prosper as demand for natural
gas grows. Natural gas markets are expected to begin improving
later in 2015, with more significant improvements forecast for
2016, 2017 and beyond. In the spring of this year, new environ-
mental requirements for coal plants begin. This is leading to coal
plant retirements, which will result in power demand being met
by cleaner-burning natural gas. In addition, natural gas exports to
Mexico are projected to increase this summer and LNG exports
are on schedule to commence later this year. Many analysts believe
North American natural gas demand will increase by about 1 to 2
Bcf per day in 2015 and annually by 3 to 4 Bcf per day in 2016 and
beyond, resulting in an increase of about 20 Bcf per day of incre-
mental demand by 2020 as compared to 2014.

The decisions we made in 2014 position Range well for 2015
and beyond. As we go forward there are four key items that will
distinguish our performance: (i) a sizeable acreage position in the
core area of one of the best plays in the United States, the Marcellus;
(ii) the track record and ability to consistently execute operationally
and financially; (iii) a strong, forward thinking marketing and oper-
ational team; and (iv) financial strength to execute the plan. And as
we move forward our philosophy remains the same: to be good stew-
ards for our shareholders and for the environment and the commu-
nities where we live and work. It’s a core commitment that starts
with our Board of Directors and management team, and extends to
our nearly 900 employees. It’s part of a corporate culture that saw
us through this past year and will drive us well into the future.

I extend my sincere thanks to our innovative and hard-working
employees for their continued efforts in 2014. We seek to hire peo-
ple who are among the best at what they do and I am so proud of
their efforts this past year. Thank you to our Board of Directors for
their wisdom and guidance throughout the year. I would also like
to welcome our newest board member, Chris Helms, who joined
the Range board earlier this year. Chris has decades of oil and gas
experience, particularly on the midstream and marketing side of
the industry. And thank you, our loyal shareholders, for believing
in Range Resources and the bright future ahead.

JEFFREY L. VENTURA
President and Chief Executive Officer

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

(Mark one)
(cid:95) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF

1934

For the fiscal year ended December 31, 2014

(cid:133) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT

OF 1934

For the transition period from to

Commission File Number: 001-12209

RANGE RESOURCES CORPORATION

(Exact Name of Registrant as Specified in Its Charter)

Delaware
(State or Other Jurisdiction of Incorporation or Organization)

34-1312571
(IRS Employer Identification No.)

100 Throckmorton Street, Suite 1200, Fort Worth, Texas
(Address of Principal Executive Offices)

76102
(Zip Code)

Registrant’s telephone number, including area code
(817) 870-2601

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class
Common Stock, $.01 par value

Name of each exchange on which registered
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 (cid:95) No (cid:133)

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 (cid:133) No (cid:95)

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 (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes (cid:95) No (cid:133)

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 (cid:95) No (cid:133)

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. (cid:133)

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

(cid:95)

Non-accelerated filer

(cid:133) (Do not check if a smaller reporting company)

Accelerated filer

Smaller reporting company

(cid:133)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes (cid:133) No (cid:95)

The aggregate market value of the voting and non-voting common equity held by non-affiliates as of June 30, 2014 was $14,270,959,000. This
amount is based on the closing price of registrant’s common stock on the New York Stock Exchange on that date. Shares of common stock held by executive
officers and directors of the registrant are not included in the computation. However, the registrant has made no determination that such individuals are
“affiliates” within the meaning of Rule 405 of the Securities Act of 1933.

As of February 23, 2015, there were 168,909,287 shares of Range Resources Corporation Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement to be furnished to stockholders in connection with its 2015 Annual Meeting of Stockholders,

which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this report relates, are
incorporated by reference in Part III, Items 10-14 of this report.

RANGE RESOURCES CORPORATION

Unless the context otherwise indicates, all references in this report to “Range,” “we,” “us” or “our” are to Range

Resources Corporation and its directly and indirectly owned subsidiaries and its ownership interests in equity method
investments. Unless otherwise noted, all information in the report relating to natural gas, natural gas liquids and oil reserves
and the estimated future net cash flows attributable to those reserves are based on estimates and are net to our interest. If
you are not familiar with the oil and gas terms used in this report, please refer to the explanation of such terms under the
caption “Glossary of Certain Defined Terms” at the end of Item 15 of this report.

PART I

TABLE OF CONTENTS

ITEMS 1 & 2. Business and Properties .........................................................................................................................
General ..................................................................................................................................................
Available Information ...........................................................................................................................
Our Business Strategy ...........................................................................................................................
Significant Accomplishments in 2014 ...................................................................................................
Industry Operating Environment ...........................................................................................................
Segment and Geographical Information ................................................................................................
Outlook for 2015 ...................................................................................................................................
Production, Price and Cost History .......................................................................................................
Proved Reserves ....................................................................................................................................
Property Overview ................................................................................................................................
Producing Wells ....................................................................................................................................
Drilling Activity ....................................................................................................................................
Gross and Net Acreage ..........................................................................................................................
Undeveloped Acreage Expirations ........................................................................................................
Title to Properties ..................................................................................................................................
Delivery Commitments .........................................................................................................................
Employees .............................................................................................................................................
Competition ...........................................................................................................................................
Marketing and Customers .....................................................................................................................
Seasonal Nature of Business .................................................................................................................
Governmental Regulation ......................................................................................................................
Environmental and Occupational Health and Safety Matters ................................................................

Page
2
2
2
3
4
5
5
6
6
7
9
11
12
12
13
13
13
13
13
14
14
14
16

ITEM 1A.

Risk Factors ...........................................................................................................................................

ITEM 1B.

Unresolved Staff Comments .................................................................................................................

ITEM 3.

ITEM 4.

PART II

Legal Proceedings .................................................................................................................................

Mine Safety Disclosures ........................................................................................................................

ITEM 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of

Equity Securities ...............................................................................................................................
Market for Common Stock ....................................................................................................................
Holders of Record .................................................................................................................................
Dividends ..............................................................................................................................................
Stockholder Return Performance Presentation ......................................................................................

34
34
34
34
35

ITEM 6.

Selected Financial Data and Proved Reserve Data ................................................................................

TABLE OF CONTENTS (continued)

Management’s Discussion and Analysis of Financial Condition and Results of Operations ...............
Overview of Our Business ...................................................................................................................
Sources of Our Revenues .....................................................................................................................
Principal Components of Our Cost Structure .......................................................................................
Management’s Discussion and Analysis of Results of Operations ......................................................
Management’s Discussion and Analysis of Financial Condition, Cash Flows, Capital Resources

and Liquidity ...................................................................................................................................
Management’s Discussion of Critical Accounting Estimates ...............................................................

Quantitative and Qualitative Disclosures about Market Risk ...............................................................
Market Risk ..........................................................................................................................................
Commodity Price Risk .........................................................................................................................
Other Commodity Risk ........................................................................................................................
Commodity Sensitivity Analysis ..........................................................................................................
Interest Rate Risk .................................................................................................................................

Page

37
37
37
38
39

47
53

57
57
58
58
59
59

Financial Statements and Supplementary Data ....................................................................................

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ...............

ITEM 7.

ITEM 7A.

ITEM 8.

ITEM 9.

ITEM 9A.

Controls and Procedures .......................................................................................................................

ITEM 9B.

Other Information .................................................................................................................................

PART III

ITEM 10.

Directors, Executive Officers and Corporate Governance ...................................................................

ITEM 11.

Executive Compensation ......................................................................................................................

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder

Matters .............................................................................................................................................

Certain Relationships and Related Transactions, and Director Independence .....................................

Principal Accountant Fees and Services ...............................................................................................

ITEM 12.

ITEM 13.

ITEM 14.

PART IV

ITEM 15.

Exhibits and Financial Statement Schedules ........................................................................................
Financial Statements .............................................................................................................................
Financial Statement Schedules .............................................................................................................
Exhibits ................................................................................................................................................
GLOSSARY OF CERTAIN DEFINED TERMS .................................................................................................................
SIGNATURES ......................................................................................................................................................................

65
65
65
65
66
68

Disclosures Regarding Forward-Looking Statements

This Annual Report on Form 10-K, particularly Item 1. and 2. Business and Properties, Item 1A. Risk Factors, Item 3.

Legal Proceedings, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and
Item 7A. Quantitative Disclosures about Market Risk, includes forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933, as amended and Section 21E of the Securities Exchange Act of 1934, as amended.
These statements typically contain words such as “anticipate,” “believe,” “estimate,” “expect,” “forecast,” “plan,” “predict,”
“target,” “project,” “could,” “should,” “would” or similar words, indicating that future outcomes are uncertain. In accordance
with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by
cautionary language identifying important factors, though not necessarily all such factors that could cause future outcomes to
differ materially from those set forth in the forward-looking statements.

Forward-looking statements in this Annual Report on Form 10-K may include, but are not limited to, levels of

revenues, income from operations, net income or earnings per share; levels of capital and exploration expenditures; the
success or timing of completion of ongoing or anticipated capital; exploration projects; volumes of production or sales of
natural gas, natural gas liquids, and crude oil; levels of worldwide prices of crude oil; levels of domestic natural gas prices;
levels of natural gas liquids, natural gas and crude oil reserves; the acquisition or divestiture of assets; the potential effect of
judicial proceedings on our business and financial condition; and the anticipated effects of actions of third parties such as
competitors, or federal, state or local regulatory authorities.

While management believes that these forward-looking statements are reasonable as and when made, there can be no
assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations
for future revenues and operating results are based on our forecasts for our existing operations and do not include the
potential impact of any future acquisitions, should we choose to make any. Our forward-looking statements involve
significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to
differ materially from our historical experience and our present expectations or projections. For a description of known
material factors that could cause our actual results to differ from those in the forward-looking statements, see “Item 1A. Risk
Factors.”

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date
hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made,
whether as a result of new information, future events or otherwise.

ITEMS 1 AND 2. BUSINESS AND PROPERTIES
General

PART I

Range Resources Corporation, a Delaware corporation, is a Fort Worth, Texas-based independent natural gas, natural

gas liquids (“NGLs”) and oil company, engaged in the exploration, development and acquisition of natural gas and oil
properties, mostly in the Appalachian and Midcontinent regions of the United States. Our corporate offices are located at 100
Throckmorton Street, Suite 1200, Fort Worth, Texas 76102 (telephone (817) 870-2601). Our common stock is listed and
traded on the New York Stock Exchange (the “NYSE”) under the symbol “RRC.” At December 31, 2014, we had 168.7
million shares outstanding.

Our 2014 production from operations consisted of the following:
• average total production of 1,162.4 Mmcfe per day, an increase of 24% from 2013;
(cid:121) 68% natural gas;

(cid:121)

total natural gas production of 286.9 Bcf, an increase of 8% from 2013;
total NGLs production of 18.8 Mmbbls (including ethane), an increase of 103% from 2013;
total crude oil production of 4.1 Mmbbls, an increase of 6% from 2013; and
(cid:121)
(cid:121) 81% of our total production was from the Marcellus Shale in Pennsylvania.

At year-end 2014, our proved reserves had the following characteristics:

(cid:121) 10.3 Tcfe of proved reserves;
(cid:121) 67% natural gas;
(cid:121) 52% proved developed;
(cid:121) 96% operated;
(cid:121) 86% of proved reserves are in the Marcellus Shale in Pennsylvania;

(cid:121)

a reserve life index of approximately 22 years (based on fourth quarter 2014 production);
a pre-tax present value of $10.1 billion of future net cash flows, discounted at 10% per annum (“PV-10”(a)); and
a standardized after-tax measure of discounted future net cash flows of $7.6 billion.

(a) PV-10 is considered a non-GAAP financial measure as defined by the SEC. We believe that the presentation of PV-10 is relevant and
useful to our investors as supplemental disclosure to the standardized measure, or after-tax amount, because it presents the discounted
future net cash flows attributable to our proved reserves before taking into account future corporate income taxes and our current tax
structure. While the standardized measure is dependent on the unique tax situation of each company, PV-10 is based on prices and
discount factors that are consistent for all companies. Because of this, PV-10 can be used within the industry and by creditors and
security analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis. The difference between the
standardized measure and the PV-10 amount is discounted estimated future income tax of $2.5 billion at December 31, 2014.

Available Information

Our internet website is available at http://www.rangeresources.com. Information contained on or connected to our
website is not incorporated by reference into this Form 10-K and should not be considered part of this report or any other
filing we make with the U.S. Securities and Exchange Commission (the “SEC”). We make available, free of charge, on our
website, the annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to
those reports, as soon as reasonably practicable after filing such reports with the SEC. Other information such as
presentations, our Corporate Governance Guidelines, the charters of the Audit Committee, the Compensation Committee, the
Dividend Committee, and the Governance and Nominating Committee, and the Code of Business Conduct and Ethics are
available on our website and in print to any stockholder who provides a written request to the Corporate Secretary at 100
Throckmorton Street, Suite 1200, Fort Worth, Texas 76102. Our Code of Business Conduct and Ethics applies to all
directors, officers and employees, including the President and Chief Executive Officer and Chief Financial Officer.

The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F
Street, NE, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by
calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an internet website that contains reports, proxy and information
statements, and other information regarding issuers, including Range, that file electronically with the SEC. The public can
obtain any document we file with the SEC at http://www.sec.gov.

Our Business Strategy

Our overarching business objective is to build stockholder value through consistent growth in reserves and production

on a cost-efficient basis. Our strategy to achieve our business objective is to increase reserves and production through
internally generated drilling projects coupled with occasional complementary acquisitions and occasional divestiture of non-
core assets. Our strategy requires us to make significant investments and financial commitments in technical staff, acreage,
seismic data, drilling and completion technology and gathering and transportation arrangements to build drilling inventory
and market our products. Our strategy has the following key elements:

(cid:121)

commit to environmental protection and worker and community safety;
concentrate in core operating areas;
(cid:121)
(cid:121) maintain a multi-year drilling inventory;

focus on cost efficiency;

(cid:121)
(cid:121) maintain a long-life reserve base;
(cid:121) market our products to a large number of customers in different markets under a variety of commercial terms;
(cid:121) maintain operational and financial flexibility; and
(cid:121) provide employee equity ownership and incentive compensation.

Commit to Environmental Protection and Worker and Community Safety. We strive to implement the latest
technologies and best commercial practices to minimize adverse impacts from the development of our properties on the
environment, worker health and safety and the safety of the communities where we operate. Working with peer companies,
regulators, nongovernmental organizations, industries not related to the oil and natural gas industry and other engaged
stakeholders, we consistently analyze and review performance while striving for continual improvement. We participate in
FracFocus, a national publicly accessible web-based registry to report, on a well-by-well basis, the additives and chemicals
and amount of water used in the hydraulic fracturing process for each of the wells we operate. We encourage every
employee to maintain safe operations, minimize environmental impact and conduct their daily business with the highest
ethical standards.

Concentrate in Core Operating Areas. We currently operate in two regions: Appalachia (which includes

Pennsylvania, Virginia, and West Virginia) and Midcontinent (which includes the Texas Panhandle, Oklahoma and Southern
Kansas). Concentrating our drilling and producing activities in these core areas allows us to develop the regional expertise
needed to interpret specific geological and operating conditions and develop economies of scale. Operating in core areas
allows us to create a portfolio to assist in our goal of consistent production and reserve growth at attractive returns.

Maintain a Multi-Year Drilling Inventory. We focus on areas with multiple prospective and productive horizons and
development opportunities. We use our technical expertise to build and maintain a multi-year drilling inventory. We believe
that a large, multi-year inventory of drilling projects increases our ability to efficiently plan for the economic growth of
production and reserves. Currently, we have over 10,000 proven and unproven drilling locations in inventory. Our goal is to
grow year-over-year production by 20-25% by focusing on developing fields in our operating areas.

Focus on Cost Efficiency. We concentrate in core areas which we believe to have sizable hydrocarbon deposits in

place that will allow us to consistently increase production while controlling costs. As there is little long-term competitive
sales price advantage available to a commodity producer, the costs to find, develop, and produce a commodity are important
to organizational sustainability and long-term shareholder value creation. We endeavor to control costs such that our cost to
find, develop and produce natural gas, NGLs and oil is one of the lowest in the industry. We operate almost all of our total
net production and believe that our extensive knowledge of the geologic and operating conditions in the areas where we
operate provides us with the ability to achieve operational efficiencies.

Maintain a Long-Life Reserve Base. Long-life natural gas and oil reserves provide a more stable growth platform than

short-life reserves. Long-life reserves reduce reinvestment risk as they lessen the amount of reinvestment capital deployed
each year to replace production. Long-life natural gas and oil reserves also assist us in minimizing costs as stable production
makes it easier to build and maintain operating economies of scale. Long-life reserves also offer upside from technology
enhancements. We use our drilling, divestiture and acquisition activities to assist in executing this strategy.

Market our products to a large number of customers in different markets under a variety of commercial terms. We

market our natural gas, NGLs, and oil to a large number of customers in both domestic and international markets to maximize
price and diversify risk. We hold considerable firm transportation contracts on multiple pipelines to enable us to transport and
sell natural gas and NGLs in the Midwest, Gulf Coast, Southeast, Northeast and international markets. We sell our products

under a variety of price indexes and price formulas that assist us in managing regional price differentials and commodity
price volatility.

Maintain Operational and Financial Flexibility. Because of the risks involved in drilling, coupled with changing
commodity prices, we are flexible and adjust our capital budget throughout the year. If certain areas generate higher than
anticipated returns, we may accelerate development in those areas and decrease expenditures elsewhere. We also believe in
maintaining a strong balance sheet, ample liquidity and using commodity derivatives to stabilize our realized prices. This
provides more consistent cash flows and financial results.

Provide Employee Equity Ownership and Incentive Compensation. We want our employees to think and act like

business owners. To achieve this, we reward and encourage them through equity ownership in Range. All full-time
employees are eligible to receive equity grants. As of December 31, 2014, our employees owned equity securities in our
benefit plans (vested and unvested) that had an aggregate market value of approximately $227.3 million. Our directors also
have equity ownership in Range.

Significant Accomplishments in 2014

(cid:121) Production growth – In 2014, our production averaged 1,162.4 Mmcfe per day, an increase of 24% from 2013.

Drilling in the Marcellus Shale play in Pennsylvania drove our production growth.

(cid:121) Reserve growth – Total proved reserves increased 26% in 2014 to 10.3 Tcfe, marking the thirteenth consecutive
year our proved reserves have increased. This achievement is the result of continued drilling success, as the
majority of our production and reserve growth in 2014 came from our drilling program. While consistent growth
is challenging to sustain, we believe the quality of our technical teams and our substantial inventory of high
quality drilling locations provide the basis for future reserve and production growth.

(cid:121) Successful drilling program – In 2014, we drilled 255 gross natural gas and oil wells plus an additional 2 service
wells. We replaced 565% of our production through drilling in 2014 and our overall drilling success rate was
99%. We continue to build our drilling inventory which is critical to our ability to drill a large number of wells
each year on a cost effective and efficient basis. We drilled our first Utica/ Point Pleasant well located in
Washington County, Pennsylvania, which achieved an average 24-hour test rate of 59.0 Mmcf per day during the
initial flow back. We believe this well represents the highest initial production rate of any reported Utica well.

(cid:121) Large resource potential – Maintaining a large exposure to potential resources is important. We continued
expansion of our unconventional resource shale plays in 2014. We have four large unconventional and
prospective plays – the Marcellus, Utica/Point Pleasant and Upper Devonian shales in Pennsylvania and the
Huron Shale in Virginia. These plays cover expansive areas, provide multi-year drilling opportunities and,
collectively, have sustainable lower risk growth profiles. The economics of these plays have been enhanced by
continued advancements in drilling and completion technologies. We have leased 1.4 million net acres in our
four shale plays. We also have approximately 278,000 net acres in our coal bed methane plays in Virginia.

(cid:121) Continued development of processing, pipeline takeaway capacity and marketing of NGLs – We continue to

ensure we have sufficient processing capacity and marketing agreements in place for our Pennsylvania
production. In 2012, we entered into a fifteen year agreement (“Mariner East”) to transport ethane and propane
from the tailgate of a third-party processing plant to a terminal and dock facility near Philadelphia. In the last few
weeks of December 2014, line fill on the propane portion of this pipeline was completed with propane delivered
to storage caverns to be sold at a later date. We expect both propane and ethane operations on Mariner East to be
fully functional by the end of third quarter 2015. During 2014, we entered into additional firm transportation
agreements to provide gas gathering and transportation from southwestern and northeastern Pennsylvania. At
December 31, 2014, our agreements provide commitments that total 3.3 Bcfe per day.

(cid:121) Focus on financial flexibility – We ended the year with less debt than year-end 2013. Debt per mcfe of proved
reserves was $0.30 at December 31, 2014 compared to $0.38 at December 31, 2013. In June 2014, we redeemed
all $300.0 million aggregate principal amount of our 8.0% senior subordinated notes due 2019 with proceeds
received of $397 million from a public offering of our common stock. As of December 31, 2014, we maintain a
$4.0 billion bank credit facility, with a current borrowing base of $3.0 billion and our committed borrowing
capacity on that date was $2.0 billion.

(cid:121) Land acquisitions completed – In 2014, we leased or renewed $226.5 million of acreage located in our core
areas, primarily in the Marcellus Shale. We continue to see outstanding results in the Marcellus Shale.
Production in the Marcellus Shale increased 32% while we continue to prove up acreage, acquire additional
acreage and gain access to additional pipeline and processing capacity.

(cid:121) Acquisitions and dispositions completed – In June 2014, we sold our Conger assets in Glasscock and Sterling
Counties, Texas in exchange for producing properties and other assets in Virginia and $145.0 million in cash,

before closing adjustments (the “Conger Exchange”). We recognized a pre-tax gain of $282.7 million related to
the Conger Exchange in the year ended December 31, 2014. We also received $28.8 million of additional
proceeds during the year primarily related to the sale of miscellaneous proved and unproved properties.

Industry Operating Environment

We operate entirely within the continental United States. The oil and natural gas industry is affected by many factors

that we cannot control. Government regulations, particularly in the areas of taxation, energy, climate change and the
environment, can have a significant impact on operations and profitability. The impact of these factors is extremely difficult
to accurately predict or anticipate. It is difficult for us to predict the occurrence of events that may affect commodity prices or
the degree to which these prices will be affected; however, the prices we receive for the commodities we produce will
generally approximate current market prices in the geographic region of the production.

Natural gas prices are generally determined by North American supply and demand. The New York Mercantile
Exchange (“NYMEX”) monthly settlement prices for natural gas averaged $4.37 per mcf in 2014, with a high of $5.56 per
mcf in February and a low of $3.73 per mcf in November. Recently, natural gas prices have declined significantly, with the
monthly settlement price for natural gas falling from $4.28 per mcf in December 2014 to $2.87 per mcf in February 2015.
Natural gas prices continue to be under pressure due to concerns over excess supply of natural gas due to the high
productivity of shale plays in the United States outpacing demand. Historically, the demand for drilling rigs, oilfield supplies
and drill pipe is expected to decline with falling commodity prices but such declines tend to lag behind the declines in natural
gas and crude oil prices.

Significant factors that will impact 2015 crude oil prices include worldwide economic conditions, political and
economic developments in the Middle East, demand in Asian and European markets, and the extent to which members of the
Organization of Petroleum Exporting Countries and other oil exporting nations choose to manage oil supply through export
quotas. NYMEX monthly settlement prices for oil averaged $92.64 per barrel in 2014, with a high of $105.15 per barrel in
June and a low of $59.29 per barrel in December. Recently, crude oil prices have declined significantly, with the monthly
settlement price for crude oil falling from $75.81 per barrel in November 2014 to $47.33 per barrel in January 2015.

NGLs prices are generally determined by North American supply and demand. We expect NGLs prices in 2015 to

continue to be under pressure due to concerns over excess supply.

Natural gas, NGLs and oil prices affect:

the amount of cash flow available to us for capital expenditures;

(cid:121)
(cid:121) our ability to borrow and raise additional capital;

(cid:121)

the quantity of natural gas, NGLs and oil that we can economically produce; and
revenues and profitability.

Natural gas and NGLs prices are likely to affect us more than oil prices because approximately 97% of our proved

reserves is natural gas and NGLs. Any continued or extended decline in natural gas, NGLs and oil prices could have a
material adverse effect on our financial position, results of operations, cash flows and access to capital. To achieve more
predictable cash flows and to reduce our exposure to downward price fluctuations, we currently, and may in the future, use
derivative instruments to hedge future sales prices on our natural gas, NGLs and oil production. The use of derivative
instruments has in the past and may in the future, prevent us from realizing the full benefit of upward price movements but
also partially protect us from declining price movements.

Segment and Geographical Information

Our operations consist of one reportable segment. We have a single, company-wide management team that administers
all properties as a whole rather than by discrete operating segments. We track only basic operational data by area. We do not
maintain complete separate financial statement information by area. We measure financial performance as a single enterprise
and not on an area-by-area basis. Our operations are limited to the United States and we focus on both unconventional
resource plays and conventional plays in the Appalachian and Midcontinent regions of the United States.

Outlook for 2015

Our capital expenditure budget for 2015 has been set at approximately $870 million. As has been our historical practice,

we will periodically review our capital expenditures throughout the year and may adjust the budget based on commodity
prices, drilling success and markets for our products. At December 31, 2014, we have entered into hedging agreements
covering 229.7 Bcfe for 2015. Since year-end 2014, we have entered into additional natural gas and NGLs hedges for 2015,
2016 and 2017. For a complete discussion of our hedging activities, a listing of open contracts at December 31, 2014 and the
estimated fair value of these contracts as of that date, see Note 10 to our consolidated financial statements. Recently, natural
gas and crude oil prices have dropped significantly. In response to the weakened natural gas and crude oil market, we
lowered our capital expenditure budget that was announced in December 2014 from $1.3 billion to $870 million and we have
announced a plan to close our Oklahoma City administrative and operations office by mid-2015 to reduce general and
administrative expenses. These properties will be operated out of our Fort Worth offices. Our estimated 2015 capital
expenditure budget detail and budget by area are shown below:

Production, Price and Cost History

The following table sets forth information regarding natural gas, NGLs and oil production, realized prices and

production costs for the last three years. For more information, see “Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations.”

Production

Natural gas (Mmcf)
Natural gas liquids (Mbbls)
Crude oil and condensate (Mbbls)

Total (Mmcfe) (a)
Average sales prices (wellhead)

Natural gas (per mcf)
Natural gas liquids (per bbl)
Crude oil and condensate (per bbl)

Total (per mcfe) (a)

Average realized prices (including derivatives that qualify for hedge accounting):

Natural gas (per mcf)
Natural gas liquids (per bbl)
Crude oil and condensate (per bbl)

Total (per mcfe) (a)

Average realized prices (including all derivative settlements and third party

transportation costs)
Natural gas (per mcf)
Natural gas liquids (per bbl)
Crude oil and condensate (per bbl)

Total (per mcfe) (a)

Direct operating costs

Lease operating (per mcfe)
Workovers (per mcfe)
Stock-based compensation (per mcfe)

Total (per mcfe)

Year Ended December 31,
2013

2012

2014

286,926
18,821
4,070
424,267

264,528
9,255
3,827
343,022

216,555
6,967
2,851
275,465

3.98 $
23.60
77.80
4.48

3.99 $
23.60
79.16
4.51

2.80 $
22.04
79.75
3.64

0.31 $
0.03
0.01
0.35 $

3.61 $
34.07
86.00
4.66

4.03 $
34.07
87.47
5.00

3.08 $
31.29
84.70
4.16

0.34 $
0.02
0.01
0.37 $

2.83
38.05
83.46
4.05

3.93
38.05
82.77
4.91

3.11
41.03
83.64
4.35

0.39
0.02
0.01
0.42

(a) Oil and NGLs are converted at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural

gas, which is not indicative of the relationship of oil and natural gas prices.

Proved Reserves

The following table sets forth our estimated proved reserves for year ended 2014, 2013 and 2012 based on the average
of prices on the first day of each month of the given calendar year, in accordance with the SEC rules. Oil includes both crude
oil and condensate. We have no natural gas, NGLs or oil reserves from non-traditional sources. Additionally, we do not
provide optional disclosures of probable or possible reserves.

Reserve Category

Natural Gas
(Mmcf)

NGLs
(Mbbls)

Summary of Oil and Gas Reserves as of Year-End
Based on Average Prices
Oil

(Mbbls)

Total
(Mmcfe) (a)

2014:
Proved

Developed
Undeveloped

Total Proved

2013:
Proved

Developed
Undeveloped

Total Proved

2012:
Proved

Developed
Undeveloped

Total Proved

3,583,051 270,271
3,339,785 245,636
6,922,836 515,907

5,349,761
24,180
24,478
4,960,468
48,658 10,310,229

52%
48%
100%

2,797,483 206,477
2,868,162
167,935
5,665,645 374,412

26,054 4,192,666
22,306 4,009,608
48,360 8,202,274

51%
49%
100%

2,373,604 154,984
2,419,072
85,415
4,792,676 240,399

25,667 3,457,502
19,415 3,048,068
45,082 6,505,570

53%
47%
100%

(a) Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcf based upon the relative energy content of oil to natural gas,

which is not indicative of the relationship of oil and natural gas prices.

The following table sets forth summary information by area with respect to estimated proved reserves at December 31,

2014:

Appalachian Region
Midcontinent Region

Total

Reserve Volumes

PV-10 (a)

NGLs
(Mbbls)

Natural Gas
(Mmcf)

Oil
(Mbbls)
96 % $ 9,610,327
6,681,073 495,586 40,006
241,763 20,321
459,947
8,652
6,922,836 515,907 48,658 10,310,229 100 % $ 10,070,274

Total
(Mmcfe)
9,894,625
415,604

Amount

4 %

(In thousands) %

95%
5%
100%

(a) PV-10 was prepared using the twelve-month average prices for 2014, discounted at 10% per annum. Year-end PV-10 is a non-GAAP

financial measure as defined by the SEC. We believe that the presentation of PV-10 is relevant and useful to our investors as
supplemental disclosure to the standardized measure, or after tax amount, because it presents the discounted future net cash flows
attributable to our proved reserves prior to taking into account future corporate income taxes and our current tax structure. While the
standardized measure is dependent on the unique tax situation of each company, PV-10 is based on prices and discount factors that are
consistent for all companies. Because of this, PV-10 can be used within the industry and by creditors and securities analysts to evaluate
estimated net cash flows from proved reserves on a more comparable basis. Our total standardized measure was $7.6 billion at
December 31, 2014. The difference between the standardized measure and the PV-10 amount is the discounted estimated future income
tax of $2.5 billion at December 31, 2014. Included in the $10.1 billion pre-tax PV-10 is $6.6 billion related to proved developed
reserves.

Reserve Estimation

All reserve information in this report is based on estimates prepared by our petroleum engineering staff. We also have

the following independent petroleum consultants conduct an audit of our year-end reserves: DeGolyer and MacNaughton
(Midcontinent) and Wright and Company, Inc. (Appalachian). These engineers were selected for their geographic expertise
and their historical experience in engineering certain properties. The proved reserve audits performed for 2014, 2013 and
2012, in the aggregate represented 96%, 96% and 93% of our proved reserves. The reserve audits performed for 2014, 2013
and 2012, in the aggregate represented 98%, 97% and 88% of our 2014, 2013 and 2012 associated pre-tax present value of
proved reserves discounted at ten percent. Copies of the summary reserve reports prepared by each of these independent

petroleum consultants are included as an exhibit to this Annual Report on Form 10-K. The technical person at each
independent petroleum consulting firm responsible for reviewing the reserve estimates presented herein meets the
requirements regarding qualifications, independence, objectivity and confidentiality as set forth in the Standards Pertaining to
the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We
maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent
petroleum consultants to ensure the integrity, accuracy and timeliness of data furnished during the reserve audit process.
Throughout the year, our technical team meets periodically with representatives of each of our independent petroleum
consultants to review properties and discuss methods and assumptions. While we have no formal committee specifically
designated to review reserves reporting and the reserve estimation process, our senior management reviews and approves
significant changes to our proved reserves. We provide historical information to our consultants for our largest producing
properties such as ownership interest, natural gas, NGLs and oil production, well test data, commodity prices and operating
and development costs. The consultants perform an independent analysis and differences are reviewed with our Senior Vice
President of Reservoir Engineering and Economics. In some cases, additional meetings are held to review identified reserve
differences. The reserve auditor estimates of proved reserves and the pre-tax present value of such reserves discounted at
10% did not differ from our estimates by more than 10% in the aggregate. However, when compared on a lease-by-lease,
field-by-field or area-by-area basis, some of our estimates may be greater than those of the auditors and some may be less
than the estimates of the reserve auditors. When such differences do not exceed 10% in the aggregate, our reserve auditors
are satisfied that the proved reserves and pre-tax present value of such reserves discounted at 10% are reasonable and will
issue an unqualified opinion. Remaining differences are not resolved due to the limited cost benefit of continuing such
analysis.

Historical variances between our reserve estimates and the aggregate estimates of our independent petroleum

consultants have been less than 5%. All of our reserve estimates are reviewed and approved by our Senior Vice President of
Reservoir Engineering and Economics, who reports directly to our Chairman, President and Chief Executive Officer. Our
Senior Vice President of Reservoir Engineering and Economics holds a Bachelor of Science degree in Electrical Engineering
from the Pennsylvania State University. Before joining Range, he held various technical and managerial positions with
Amoco, Hunt Oil and Union Pacific Resources and has more than thirty-five years of engineering experience in the oil and
gas industry. During the year, our reserves group may also perform separate, detailed technical reviews of reserve estimates
for significant acquisitions or for properties with problematic indicators such as excessively long lives, sudden changes in
performance or changes in economic or operating conditions. We did not file any reports during the year ended December 31,
2014 with any federal authority or agency with respect to our estimate of natural gas and oil reserves.

Reserve Technologies

Proved reserves are those quantities of natural gas, natural gas liquids and oil, 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, operating methods, and government regulations. The term
“reasonable certainty” implies a high degree of confidence that the quantities of natural gas, NGLs and oil actually recovered
will equal or exceed the estimate. To achieve reasonable certainty, our internal technical staff employs technologies that have
been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the
estimation of our proved reserves include, but are not limited to, empirical evidence through drilling results and well
performance, well logs, geologic maps and available downhole and production data, seismic data, well test data and reservoir
simulation modeling.

Reporting of Natural Gas Liquids

We produce natural gas liquids, or NGLs, as part of the processing of our natural gas. The extraction of NGLs in the

processing of natural gas reduces the volume of natural gas available for sale. At December 31, 2014, NGLs represented
approximately 30% of our total proved reserves on an mcf equivalent basis. NGLs are products priced by the gallon (and sold
by the barrel) to the end-user. In reporting proved reserves and production of NGLs, we have included production and
reserves in barrels. Prices for a barrel of NGLs in 2014 averaged approximately 70% lower than the average prices for
equivalent volumes of oil. We report all production information related to natural gas net of the effect of any reduction in
natural gas volumes resulting from the processing of NGLs. As of December 31, 2014, we have 1,170 Bcfe of ethane
reserves (264.3 Mmbbls) associated with our Marcellus Shale, which are included in NGLs proved reserves.

Proved Undeveloped Reserves (PUDs)

As of December 31, 2014, our PUDs totaled 24.5 Mmbbls of crude oil, 245.6 Mmbbls of NGLs and 3.3 Tcfe of natural

gas, for a total of 5.0 Tcfe. Costs incurred in 2014 relating to the development of PUDs were approximately $591.0 million.
Approximately 93% of our PUDs at year-end 2014 were associated with the Marcellus Shale. All PUD drilling locations are
scheduled to be drilled prior to the end of 2019 with more than 80% of the future development costs expected to be spent in
the next three years. Changes in PUDs that occurred during the year were due to:

conversion of approximately 620 Bcfe of PUDs into proved developed reserves;

(cid:121)
(cid:121) new PUDs added consisting of 1,776 Bcfe;

(cid:121) 147 Bcfe negative revision with 611 Bcfe of reserves reclassified to unproved because of a slower pace of

development activity beyond the five-year development horizon as we continue to see success from drilling
longer laterals, increasing the number of frac stages and better lateral targeting partially offset by improved
recovery of 450 Bcfe and other performance revisions; and

(cid:121) 58 Bcfe reduction from the sale of properties.

Proved Reserves (PV-10)

The following table sets forth the estimated future net cash flows, excluding open derivative contracts, from proved

reserves, the present value of those net cash flows discounted at a rate of 10% (PV-10), and the expected benchmark prices
and average field prices used in projecting net cash flows over the past five years. Our reserve estimates do not include any
probable or possible reserves (in millions, except prices):

Future net cash flows
Present value:

Before income tax
After income tax (Standardized Measure)

Benchmark prices (NYMEX):

Gas price (per mcf)
Oil price (per bbl)

Wellhead prices:

Gas price (per mcf)
Oil price (per bbl)
NGLs price (per bbl)

2014
26,993 $ 21,029 $ 11,156 $ 15,610 $

2013

2012

2011

10,070
7,593

7,898
5,862

3,960
3,224

6,084
4,515

4.35
94.42

3.67
97.33

2.76
95.05

4.12
95.61

4.14
79.04
27.20

3.75
86.66
25.93

2.75
86.91
32.23

3.55
85.59
49.24

2010
12,516

4,647
3,479

4.38
79.81

3.70
72.51
39.14

Future net cash flows represent projected revenues from the sale of proved reserves net of production and development
costs (including operating expenses and production taxes) and revenues are based on a twelve-month unweighted average of
the first day of the month pricing, without escalation. Future cash flows are reduced by estimated production costs,
administrative costs, costs to develop and produce the proved reserves and abandonment costs, all based on current economic
conditions at each year-end. There can be no assurance that the proved reserves will be produced in the future or that prices,
production or development costs will remain constant. There are numerous uncertainties inherent in estimating reserves and
related information and different reservoir engineers often arrive at different estimates for the same properties.

Property Overview

Our natural gas and oil operations are concentrated in the Appalachian and Midcontinent regions of the United States.
Our properties consist of interests in developed and undeveloped natural gas and oil leases in these regions. These interests
entitle us to drill for and produce natural gas, NGLs, crude oil and condensate from specific areas. Our interests are mostly in
the form of working interests and, to a lesser extent, royalty and overriding royalty interests. We have a single company-wide
management team that administers all properties as a whole. We track only basic operational data by area. We do not
maintain complete separate financial statement information by area. We measure financial performance as a single enterprise
and not on an area-by-area basis.

The table below summarizes data for our operating regions for the year ended December 31, 2014.

Region

Appalachian
Midcontinent
Total

Average
Daily
Production
(mcfe per day)

Production
(Mmcfe)

Percentage of
Production

Proved
Reserves
(Mmcfe)

Percentage of
Proved
Reserves

1,059,318 386,651
37,616
1,162,374 424,267

103,056

91% 9,894,625
415,604
100% 10,310,229

96%
4%
100%

The following table summarizes our costs incurred by operating region for the year ended December 31, 2014 (in

thousands):

Appalachian
Midcontinent

Total costs incurred

Acreage
Purchases

Acquisitions
(a)

Development
Costs

Exploration
Costs
$ 404,252 $207,838 $ 1,026,968 $ 221,112 $ 12,035 $ 53,383 $1,925,588
139,467
$ 404,252 $226,475 $ 1,119,896 $ 244,473 $ 13,137 $ 56,822 $2,065,055

Gathering
Facilities

⎯ 18,637

23,361

92,928

1,102

3,439

Total

Asset
Retirement
Obligations

(a) Includes $11.9 million of asset retirement obligations and $134.8 million of gas gathering assets.

Approximately 86% of our proved reserves at December 31, 2014 are located in the Marcellus Shale in our
Appalachian region. This play has a large portfolio of drilling opportunities. The following table below sets forth annual
production volumes, average sales prices and production cost data for our wells in the Marcellus Shale which, as of
December 31, 2014, is our only field in which reserves are greater than 15% of our total proved reserves.

Marcellus Shale Field
Production:

Natural gas (Mmcf)
NGLs (Mbbls)
Crude oil and condensate (Mbbls)

Total Mmcfe (a)

Sales Prices: (b)

Natural gas (per mcf)
NGLs (per bbl)
Crude oil and condensate (per bbl)

Total (per mcfe)

Production Costs:

Lease operating (per mcfe)
Production and ad valorem tax (per mcfe) (c)

2014

2013

2012

224,034
17,093
3,089
345,127

203,926
7,213
2,529
262,377

149,589
5,034
1,564
189,178

2.72 $
20.32
73.77
3.43

0.19 $
0.08

2.59 $
33.19
82.11
3.72

0.16 $
0.11

1.86
38.48
78.56
3.14

0.18
0.26

(a) Oil and NGLs are converted at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural

gas, which is not indicative of the relationship of oil and natural gas prices.

(b) We do not record derivatives or the results of derivatives at the field level. Includes deductions for third party transportation, gathering

and compression expense.

Appalachian Region

Our properties in this area are located in the Appalachian Basin in the northeastern United States, principally in
Pennsylvania, Virginia and West Virginia. The reserves from the Marcellus Shale, the Pennsylvanian (coalbed formation),
Berea, Big Lime, Huron Shale, Medina and Upper Devonian formations principally produce at depths ranging from 2,500
feet to 9,000 feet. We own 7,582 net producing wells, 96% of which we operate. Our average working interest in this region
is 90%. As of December 31, 2014, we have approximately 1.6 million gross (1.4 million net) acres under lease, which
includes 305,000 acres in which we also own a royalty interest.

Reserves at December 31, 2014 were 9.9 Tcfe, an increase of 2.4 Tcfe, or 31%, from 2013. Drilling additions (2.3

Tcfe), purchases (262.8 Bcfe), favorable reserve revisions for performance and price and improved recovery were partially
offset by production and downward revisions for proved undeveloped reserves no longer in our current five year
development plan (581.5 Bcfe). Annual production increased 30% from 2013. During 2014, we spent $1.2 billion in this
region to drill 201 (190.5 net) development wells and 25 (21.4 net) exploratory wells, of which all were productive. At
December 31, 2014, the Appalachian region had an inventory of over 800 proven drilling locations and over 600 proven
recompletions. During the year, the Appalachian region drilled 105 proven locations, added 163 new proven drilling
locations and deleted 116 proven drilling locations with reserves reclassified to unproved because of a slower pace of
development activity beyond the five-year development horizon as required by the SEC’s reserve reporting requirements.
During the year, the region achieved a 100% drilling success rate.

Marcellus Shale

We began operations in the Marcellus Shale in Pennsylvania during 2004. The Marcellus Shale is an unconventional

reservoir, which produces natural gas, NGLs and condensate. This has been our largest investment area over the last six
years. We had over 500 proven drilling locations at December 31, 2014. Our 2014 production from the Marcellus Shale
increased 32% from 2013. During 2014, we drilled 149 (139.5 net) development wells and 25 (21.4 net) exploratory wells, all
of which were successful. In 2015, we plan to drill over 130 net wells. During 2014, we had approximately 9 drilling rigs in
the field and expect to run an average of 7 rigs throughout 2015.

We have long-term agreements with third parties to provide gathering and processing services and infrastructure assets

in the Marcellus Shale, which includes gathering and residue gas pipelines, compression, cryogenic processing, de-
ethanization and liquid fractionation. In 2011, we executed an ethane sales contract for the liquids-rich gas in southwestern
Pennsylvania whereby a third party will transport ethane from the tailgate of the third-party processing and fractionation
facilities to the international border for further delivery into Canada. Initial deliveries commenced in second half 2013. Also
in 2011, we entered into an agreement to transport ethane to the Gulf Coast where initial deliveries also commenced in late
2013.

In 2012, we entered into a fifteen year agreement to transport ethane and propane from the tailgate of a third-party

processing plant to a terminal and dock facility near Philadelphia. Line fill on the propane portion of this pipeline was
completed in late December 2014, with propane delivered to storage caverns to be sold at a later date. We expect both
propane and ethane operations to be fully functional by the end of third quarter 2015. In the meantime, since 2012, we have
been transporting a portion of our propane by rail and truck to the terminal and dock facility near Philadelphia for sale to
domestic and international customers. Also in 2012, we executed a fifteen year ethane sales agreement from the same
terminal near Philadelphia which is expected to begin in third quarter 2015.

Since 2008, we have entered into various firm transportation agreements to provide gas gathering and transportation

from southwestern and northeastern Pennsylvania which, at December 31, 2014 provide commitments for 3.3 Bcfe per day.
Some of our agreements, which extend to 2030, are contingent on pipeline modifications and/or construction. To support our
drilling efforts and to control costs, we have agreements for hydraulic fracturing services, including related equipment,
material and labor, in Pennsylvania through 2015.

Midcontinent Region

The Midcontinent region includes drilling, production and field operations in the Texas Panhandle, as well as in the
Anadarko Basin of western Oklahoma, the Nemaha Uplift of northern Oklahoma and Kansas, the Permian Basin of West
Texas and Mississippi. In the Midcontinent region, we own 653 net producing wells, 95% of which we operate. Our average
working interest is 78%. As of December 31, 2014, we have approximately 507,000 gross (383,000 net) acres under lease.

Total proved reserves in the Midcontinent region decreased 247.5 Bcfe, or 37%, at December 31, 2014, when

compared to year-end 2013. Drilling additions (80.4 Bcfe) and positive pricing revisions were offset by production, property
sales (220.1 Bcfe) and negative performance revisions. Annual production volumes decreased 18% from 2013. During 2014,
this region spent $116.3 million to drill 28 (26.2 net) development wells and one (one net) exploratory well, of which 27
(25.2 net) were productive. During the year, the region achieved a 93% drilling success rate. The region also drilled 2 service
wells in 2014.

At December 31, 2014, the Midcontinent region had a development inventory of over 80 proven drilling locations and

over 220 proven recompletions. During the year, the Midcontinent region drilled 6 proven locations, added 26 new proven
locations and deleted 69 proven drilling locations primarily due to the sale of properties. Development projects include
recompletions and infill drilling. These activities also include increasing reserves and production through cost control,
upgrading lifting equipment, improving gathering systems and surface facilities, and performing restimulations and
refracturing operations.

Producing Wells

The following table sets forth information relating to productive wells at December 31, 2014. If we own both a royalty

and a working interest in a well, such interest is included in the table below. Wells are classified as natural gas or crude oil
according to their predominant production stream. We do not have a significant number of dual completions.

Natural gas
Crude oil
Total

Total Wells

Gross

Net

9,125
132
9,257

8,113
122
8,235

Average
Working
Interest

89%
93%
89%

The day-to-day operations of natural gas and oil properties are the responsibility of the operator designated under
pooling or operating agreements. The operator supervises production, maintains production records, employs or contracts for
field personnel and performs other functions. An operator receives reimbursement for direct expenses incurred in the
performance of its duties as well as monthly per-well producing and drilling overhead reimbursement at rates customarily
charged by unaffiliated third parties. The charges customarily vary with the depth and location of the well being operated.

Drilling Activity

The following table summarizes drilling activity for the past three years. Gross wells reflect the sum of all wells in

which we own an interest. Net wells reflect the sum of our working interests in gross wells. As of December 31, 2014, we
were in the process of drilling 49.0 (48.1 net) wells. In 2014, we also drilled 2 (2 net) service wells.

Development wells
Productive
Dry

Exploratory wells
Productive
Dry
Total wells

Productive
Dry

Total

Success ratio

Gross and Net Acreage

2014

2013

2012

Gross

Net

Gross

Net

Gross

Net

228.0
1.0

215.7
1.0

178.0
1.0

171.9
1.0

226.0
⎯

202.3
⎯

25.0
1.0

21.4
1.0

39.0
1.0

35.5
0.2

72.0
⎯

54.5
⎯

253.0
2.0
255.0

237.1

2.0
239.1

217.0
2.0
219.0

207.4
1.2
208.6

298.0
⎯
298.0

256.8
⎯
256.8

99.2%

99.1%

99.4 %

100 %

100%

We own interests in developed and undeveloped natural gas and oil acreage. These ownership interests generally take

the form of working interests in oil and natural gas leases that have varying terms. Developed acreage includes leased acreage
that is allocated or assignable to producing wells or wells capable of production even though shallower or deeper horizons
may not have been fully explored. Undeveloped acreage includes leased acres on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities of natural gas or oil, regardless of whether or
not the acreage contains proved reserves.

The following table sets forth certain information regarding the developed and undeveloped acreage in which we own a

working interest as of December 31, 2014. Acreage related to royalty, overriding royalty and other similar interests is
excluded from this summary:

Developed Acres
Net

Gross

Undeveloped
Acres

Total Acres

Gross

Net

Gross

Net

Illinois
Kansas
Louisiana
Mississippi
New York
Ohio
Oklahoma
Pennsylvania
Texas
Virginia
West Virginia
Wyoming

⎯
⎯
571
5,373
⎯
40
152,205
556,559
37,301
122,719
51,792
⎯

⎯
⎯
226
3,264
⎯
40
126,340
514,893
29,885
120,924
50,229

⎯

7,312
28,419

13,332
28,604
⎯
904

3,067

⎯
623
968
⎯
⎯
231,505 163,841
467,347 403,915
26,287
238,185 238,185
50,330
9,565
929,445

51,068
9,565
1,080,980

37,403

13,332
28,604
571
6,277
3,067

40
383,710
1,023,906
74,704
360,904
102,860

9,565
2,007,540

86%

7,312
28,419
226
3,887
968
40
290,181
918,808
56,172
359,109
100,559
9,565
1,775,246
88%

Average working interest

926,560

845,801

91%

Undeveloped Acreage Expirations

The table below summarizes by year our undeveloped acreage scheduled to expire in the next five years.

As of December 31,
2015
2016
2017
2018
2019

Acres

Gross
104,886
120,028
150,215
52,778
36,599

Net
90,266
111,578
107,712
40,972
32,062

10%
12%
12%
4%
3%

% of Total
Undeveloped

In all cases the drilling of a commercial well will hold acreage beyond the expiration date. We have leased acreage that

is subject to lease expiration if initial wells are not drilled within a specified period, generally between three to five years.
However, we have in the past and expect in the future, to be able to extend the lease terms of some of these leases and sell or
exchange some of these leases with other companies. The expirations included in the table above do not take into account the
fact that we may be able to extend the lease terms. We do not expect to lose significant lease acreage because of failure to
drill due to inadequate capital, equipment or personnel. However, based on our evaluation of prospective economics, we have
allowed acreage to expire from time to time and expect to allow additional acreage to expire in the future.

Title to Properties

We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted
industry standards. As is customary in the industry, in the case of undeveloped properties, often minimal investigation of
record title is made at the time of lease acquisition. Investigations are made before the consummation of an acquisition of
producing properties and before commencement of drilling operations on undeveloped properties. Individual properties may
be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. Burdens on
properties may include:

(cid:121)

customary royalty interests;
liens incident to operating agreements and for current taxes;

(cid:121)
(cid:121) obligations or duties under applicable laws;
(cid:121) development obligations under oil and gas leases; or
(cid:121) net profit interests.

Delivery Commitments

For a discussion of our delivery commitments, see “Item 7. Management’s Discussion and Analysis of Financial

Condition and Results of Operations-Delivery Commitments.”

Employees

As of January 1, 2015, we had 990 full-time employees, 401 of whom were field personnel. In first quarter 2015, we

announced we will close our Oklahoma City administrative and operations office which will impact approximately 100
employees. All full-time employees are eligible to receive equity awards approved by the Compensation Committee of the
Board of Directors. No employees are currently covered by a labor union or other collective bargaining arrangement. We
believe that the relationship with our employees is excellent. We regularly use independent consultants and contractors to
perform various professional services, particularly in the areas of drilling, completion, field services, on-site production
services and certain accounting functions.

Competition

Intense competition exists in all sectors of the oil and gas industry and in particular, we encounter substantial

competition in developing and acquiring natural gas and oil properties, securing and retaining personnel, conducting drilling
and field operations and marketing production. Competitors in exploration, development, acquisitions and production include
the major oil and gas companies as well as numerous independent oil and gas companies, individual proprietors and others.
Although our sizable acreage position and core area concentration provide some competitive advantages, many competitors
have financial and other resources substantially exceeding ours. Therefore, competitors may be able to pay more for desirable
leases and evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources
allow. Our ability to replace and expand our reserve base depends on our ability to attract and retain quality personnel and

identify and acquire suitable producing properties and prospects for future drilling. For more information, see “Item 1A. Risk
Factors.”

Marketing and Customers

We market the majority of our natural gas, NGLs, crude oil and condensate production from the properties we operate

for our interest, and that of the other working interest owners. We pay our royalty owners from the sales attributable to our
working interest. Natural gas, NGLs and oil purchasers are selected on the basis of price, credit quality and service reliability.
For a summary of purchasers of our natural gas, NGLs and oil production that accounted for 10% or more of consolidated
revenue, see Note 2 to our consolidated financial statements. Because alternative purchasers of natural gas and oil are usually
readily available, we believe that the loss of any of these purchasers would not have a material adverse effect on our
operations. Production from our properties is marketed using methods that are consistent with industry practice. Sales prices
for natural gas, NGLs and oil production are negotiated based on factors normally considered in the industry, such as index or
spot price, distance from the well to the pipeline, commodity quality and prevailing supply and demand conditions. Our
natural gas production is sold to utilities, marketing and mid-stream companies and industrial users. Our NGLs production is
typically sold to natural gas processors or users of NGLs. Our oil and condensate production is sold to crude oil processors,
transporters and refining and marketing companies in the area. Market volatility due to fluctuating weather conditions,
international political developments, overall energy supply and demand, economic growth rates and other factors in the
United States and worldwide have had, and will continue to have, a significant effect on energy prices.

We enter into derivative transactions with unaffiliated third parties for a varying portion of our production to achieve
more predictable cash flows and to reduce our exposure to short-term fluctuations in natural gas, NGLs and oil prices. For a
more detailed discussion, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of
Operations” and “Item 7A. Quantitative and Qualitative Disclosures about Market Risk.”

We incur gathering and transportation expense to move our production from the wellhead and tanks to purchaser

specified delivery points. These expenses vary based on volume, distance shipped and the fee charged by the third-party
gatherers and transporters. In the Midcontinent region, our production is transported primarily through purchaser-owned or
third-party trucks, field gathering systems and transmission pipelines. Transportation capacity on these gathering and
transportation systems and pipelines is occasionally constrained. In Appalachia, we own some gas gathering pipelines, which
transport a portion of our Appalachian production and third-party production to transmission lines, directly to end-users and
interstate pipelines. Our remaining Appalachian production is transported on third-party pipelines on which, in most cases,
we hold long-term contractual capacity. We attempt to balance sales, storage and transportation positions, which can include
purchase of commodities from third parties for resale, to satisfy transportation commitments.

We have not experienced significant difficulty to date in finding a market for all of our production as it becomes

available or in transporting our production to those markets; however, there is no assurance that we will always be able to
transport and market all of our production or obtain favorable prices.

We have entered into three ethane agreements to sell or transport ethane from our Marcellus Shale area. Initial

deliveries commenced in late 2013 on two of these agreements. The remaining agreement is contingent on pipeline
modifications and/or construction with operations expected to begin in mid-2015. For more information, see “Item 1A. Risk
Factors – Our business depends on natural gas and oil transportation and NGLs processing facilities, most of which are
owned by others and depends on our ability to contract with those parties.”

Seasonal Nature of Business

Generally, but not always, the demand for natural gas and propane decreases during the summer months and increases
during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes accentuate this fluctuation. In
addition, pipelines, utilities, local distribution companies and industrial end-users utilize natural gas storage facilities and
purchase some of their anticipated winter requirements during the summer. This can also impact the seasonality of demand.

Governmental Regulation

Enterprises that sell securities in public markets are subject to regulatory oversight by federal agencies such as the SEC
and the NYSE, a private stock exchange which requires us to comply with listing requirements for our common stock listed.
This regulatory oversight imposes on us the responsibility for establishing and maintaining disclosure controls and
procedures and internal controls over financial reporting, and ensuring that the financial statements and other information
included in submissions to the SEC do not contain any untrue statement of a material fact or omit to state a material fact
necessary to make the statements made in such submissions not misleading. Failure to comply with the NYSE listing rules
and regulations of the SEC could subject us to litigation from public or private plaintiffs. Failure to comply with the rules of
the NYSE could result in the de-listing of our common stock, which could have an adverse effect on the market price of our
14

common stock. Compliance with some of these rules and regulations is costly, and regulations are subject to change or
reinterpretation.

Exploration and development and the production and sale of oil and gas are subject to extensive federal, state and local
regulations. An overview of these regulations is set forth below. We believe we are in substantial compliance with currently
applicable laws and regulations and the continued substantial compliance with existing requirements will not have a material
adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may
change, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or
regulations may be discovered. See “Item 1A. Risk Factors – The natural gas and oil industry is subject to extensive
regulation.” We do not believe we are affected differently by these regulations than others in the industry.

General Overview. Our oil and gas operations are subject to various federal, state, tribal and local laws and regulations.

Generally speaking, these regulations relate to matters that include, but are not limited to:

(cid:121)

leases;
acquisition of seismic data;
location of wells, pads, roads, impoundments, facilities, rights of way;
size of drilling and spacing units or proration units;

(cid:121)
(cid:121) number of wells that may be drilled in a unit;
(cid:121) unitization or pooling of oil and gas properties;
(cid:121) drilling, casing and completion of wells;

issuance of permits in connection with exploration, drilling and production;

(cid:121)
(cid:121) well production, maintenance, operations and security;

(cid:121)

spill prevention and containment plans;
emissions permitting or limitations;

(cid:121)
(cid:121) protection of endangered species;
(cid:121) use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;

(cid:121)

surface usage and the restoration of properties upon which wells have been drilled;
calculation and disbursement of royalty payments and production taxes;

(cid:121)
(cid:121) plugging and abandoning of wells;
transportation of production; and

(cid:121)
(cid:121) health and safety of employees and contract service providers.

In August 2005, Congress enacted the Energy Policy Act of 2005 (“EPAct 2005”). Among other matters, EPAct 2005
amends the Natural Gas Act (“NGA”) to make it unlawful for “any entity,” including otherwise non-jurisdictional producers
such as Range, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural
gas or the purchase or sale of transportation services subject to regulation by the Federal Energy Regulatory Commission (the
“FERC”), in contravention of rules prescribed by the FERC. On January 20, 2006, the FERC issued rules implementing this
provision. The rules make it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of the
FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or
indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit
any such statement necessary to make the statements not misleading; or to engage in any act or practice that operates as a
fraud or deceit upon any person. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the
NGA of up to $1,000,000 per day per violation. The anti-manipulation rule does not apply to activities that relate only to
intrastate or other non-jurisdictional sales or gathering, but does apply to activities or otherwise non-jurisdictional entities to
the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to the FERC’s
jurisdiction which includes the reporting requirements under Order 704, defined and described below. It therefore reflects a
significant expansion of the FERC’s enforcement authority. Range has not been affected differently than any other producer
of natural gas by this act. Failure to comply with applicable laws and regulations can result in substantial penalties. The
regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in
substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or
reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and

proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the FERC, and the
courts. We cannot predict when or whether any such proposals may become effective.

On December 26, 2007, the FERC issued a final rule on the annual natural gas transaction reporting requirements, as

amended by subsequent orders on rehearing (“Order 704”). Under Order 704, wholesale buyers and sellers of more than
2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas gatherers and marketers, are
now required to report to the FERC, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale
in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price
indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on
the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index
publishers, and if so, whether their reporting complies with the FERC’s policy statement on price reporting. On
November 15, 2012, Docket No. RM13-1, the FERC issued a Notice of Inquiry seeking comments on whether it should
require all market participants engaged in sales of wholesale physical natural gas in interstate commerce to report quarterly to
the FERC every natural gas transaction within the FERC’s NGA jurisdiction that entails physical delivery for the next day or
for the next month in order to improve natural gas market transparency. We cannot predict when or whether any such
proposals may become effective.

Environmental and Occupational Health and Safety Matters

Our operations are subject to numerous stringent federal, state and local laws and regulations governing occupational
health and safety, the discharge of materials into the environment or otherwise relating to environmental protection, some of
which carry substantial administrative, civil and criminal penalties for failure to comply. These laws and regulations may
require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various
substances that can be released into the environment in connection with drilling, production and transporting through
pipelines, govern the sourcing and disposal of water used in the drilling and completion process, limit or prohibit drilling
activities on certain lands lying within wilderness, wetlands, frontier and other protected areas, require some form of remedial
action to prevent or mitigate pollution from existing and former operations such as plugging abandoned wells or closing
earthen impoundments and impose substantial liabilities for pollution resulting from operations or failure to comply with
regulatory filings. These laws and regulations also may restrict the rate of production. Moreover, changes in environmental
laws and regulations often occur, and any changes that result in more stringent and costly well construction, drilling, water
management or completion activities or more restrictive waste handling storage, transport, disposal or cleanup requirements
for any substances used or produced in our operations could materially adversely affect our operations and financial position,
as well as those of the oil and natural gas industry in general.

The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known

as the “Superfund” law, and comparable state laws impose liability, without regard to fault or the legality of the original
conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the
environment. These persons may include owners or operators of the disposal site or sites where the hazardous substance
release occurred and companies that disposed of or arranged for the disposal of the hazardous substances at the site where the
release occurred. Under CERCLA, all of these persons may be subject to joint and several 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. In addition, it is not uncommon for neighboring landowners and other third parties, pursuant to
environmental statutes, common law or both, to file claims for personal injury and property damages allegedly caused by the
release of hazardous substances or other pollutants into the environment. Although petroleum, including crude oil and natural
gas, is not a “hazardous substance” under CERCLA, at least two courts have ruled that certain wastes associated with the
production of crude oil may be classified as “hazardous substances” under CERCLA and that releases of such wastes may
therefore give rise to liability under CERCLA. While we generate materials in the course of our operations that may be
regulated as hazardous substances, we have not received notification that we may be potentially responsible for cleanup costs
under CERCLA or comparable state laws. Other state laws regulate the disposal of oil and natural gas wastes, and new state
and federal regulatory initiatives that could have a significant adverse impact on us may periodically be proposed and
enacted.

We also may incur liability under the Resource Conservation and Recovery Act, as amended (“RCRA”) and
comparable state laws, which impose requirements related to the handling and disposal of non-hazardous solid wastes and
hazardous wastes. Drilling fluids, produced waters, and other wastes associated with the exploration, development or
production of crude oil, natural gas or geothermal energy are currently regulated by the United States Environmental
Protection Agency (“EPA”) and state agencies under RCRA’s less stringent non-hazardous solid waste provisions. It is
possible that these solid wastes could in the future be reclassified as hazardous wastes, whether by amendment of RCRA or
adoption of new laws, which could significantly increase our costs to manage and dispose of such wastes. Moreover, ordinary
industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils, may be regulated as

hazardous wastes. Although the costs of managing wastes classified as hazardous waste may be significant, we do not expect
to experience more burdensome costs than similarly situated companies in our industry.

We currently own or lease, and have in the past owned or leased, properties that for many years have been used for the

exploration and production of crude oil and natural gas. Petroleum hydrocarbons or wastes may have been disposed of or
released on or under the properties owned or leased by us, or on or under other locations where such materials have been
taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or
release of petroleum hydrocarbons and wastes was not under our control. These properties and the materials disposed or
released on them may be subject to CERCLA, RCRA and comparable state laws and regulations. Under such laws and
regulations, we could be required to remove or remediate previously disposed wastes or property contamination, or to
perform remedial activities to prevent future contamination.

The Federal Water Pollution Control Act, as amended (the “CWA”), and comparable state laws impose restrictions and

strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into
federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms
of a permit issued by the EPA or the state. These laws also prohibit the discharge of dredge and fill material in regulated
waters, including wetlands, unless authorized by permit. These laws and any implementing regulations provide for
administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable
quantities and may impose substantial potential liability for the costs of removal, remediation and damages. Pursuant to these
laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or
storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as
“SPCC plans,” in connection with on-site storage of greater than threshold quantities of oil. We regularly review our natural
gas and oil properties to determine the need for new or updated SPCC plans and, where necessary, we will be developing or
upgrading such plans, the costs of which are not expected to be substantial.

The Oil Pollution Act of 1990, as amended (“OPA”), contains numerous requirements relating to the prevention of and

response to oil spills into waters of the United States. The OPA subjects owners of facilities to strict, joint and several
liability for all containment and cleanup costs and certain other damages arising from an oil spill, including, but not limited
to, the costs of responding to a release of oil to surface waters. While we believe we have been in substantial compliance with
OPA, noncompliance could result in varying civil and criminal penalties and liabilities.

The Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from many sources,
including compressor stations. These laws and any implementing regulations may require us to obtain pre-approval for the
construction or modification of certain projects or facilities expected to produce air emissions, impose stringent air permit
requirements, or use specific equipment or technologies to control emissions. We may be required to incur certain capital
expenditures in the next few years for air pollution control equipment in connection with maintaining or obtaining operating
permits and approvals for emissions of pollutants. For example, on January 14, 2015, the Obama Administration announced
that the EPA is expected to propose in the summer of 2015 and finalize in 2016 new regulations that will set methane
emission standards for new and modified oil and gas production and natural gas processing and transmission facilities as part
of the Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45 percent from 2012 levels
by 2025. In a second example, in December 2014, the EPA published a proposed rulemaking that it expects to finalize by
October 1, 2015, which rulemaking proposes to revise the National Ambient Air Quality Standard for ozone between 65 to
70 parts per billion for both the 8-hour primary and secondary standards. Compliance with one or both of these regulatory
initiative could directly impact us by requiring installation of new emission controls on some of our equipment, resulting in
longer permitting timelines, and significantly increasing our capital expenditures and operating costs, which could adversely
impact our business.

In 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases
(“GHGs”) present a danger to public health and the environment because emissions of such gases are, according to the EPA,
contributing to warming of the Earth’s atmosphere and other climatic conditions. Based on these findings, the EPA adopted
regulations under the existing Clean Air Act establishing Title V and Prevention of Significant Deterioration (“PSD”)
permitting reviews for GHG emissions from certain large stationary sources that already are potential major sources of
certain principal, or criteria, pollutant emissions. We could become subject to these Title V and PSD permitting reviews and
be required to install “best available control technology” to limit emissions of GHGs from any new or significantly modified
facilities that we may seek to construct in the future if such facilities emitted volumes of GHGs in excess of threshold
permitting levels. The EPA has also adopted rules requiring the reporting of GHG emissions from specified emission sources
in the United States on an annual basis, including certain oil and natural gas production facilities, which include several of
our facilities. We are monitoring several of our operations for GHG emissions and believe that our monitoring activities are
in substantial compliance with applicable reporting obligations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been
significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the
absence of federal climate legislation in the U.S., a number of state and regional efforts have emerged that are aimed at
tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG
emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address

GHG emissions would impact our business, any such future laws and regulations could require us to incur increased
operating costs, such as costs to purchase and operate emissions control systems, to acquire emission allowances or comply
with new regulatory or reporting requirements. For example, pursuant to President Obama’s Strategy to Reduce Methane
Emissions, the Obama Administration announced on January 14, 2015 that the EPA is expected to propose in the summer of
2015, and finalize in 2016, new regulations that will set methane emission standards for new and modified oil and gas
production and natural gas processing and transmission facilities as part of the Administration’s efforts to reduce methane
emissions from the oil and gas sector by up to 45 percent from 2012 levels by 2025. Any such legislation or regulatory
programs could also increase the cost of consuming, and thereby reduce demand for oil and natural gas, which could reduce
the demand for the oil and natural gas that we produce. Finally, it should be noted that some scientists have concluded that
increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical
effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects
were to occur, they could have an adverse effect on our financial condition and results of operations.

Hydraulic fracturing, which has been used by the industry for over 60 years, is an important and common practice used

to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process
involves the injection of water, sand and chemicals under pressure into targeted subsurface formations to fracture the
surrounding rock and stimulate production. We routinely apply hydraulic fracturing techniques as part of our operations. This
process is typically regulated by state oil and natural gas commissions; however, several federal agencies have asserted
regulatory authority over certain aspects of the process. For example, the EPA has issued final Clean Air Act regulations
governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing;
announced its intent to propose in early 2015 effluent limit guidelines that wastewater from shale gas extraction operations
must meet before discharging to a treatment plant; and issued in May 2014 a prepublication of its Advance Notice of
Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in
hydraulic fracturing. Also, in May 2013, the federal Bureau of Land Management (“BLM”) issued a revised proposed rule
containing disclosure requirements and other mandates for hydraulic fracturing on federal lands and the agency is now
analyzing comments to the proposed rulemaking and is expected to promulgate a final rule in early 2015. Moreover, from
time to time, Congress has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing
and to require disclosure of the chemicals used in the hydraulic fracturing process. In addition to any actions by Congress,
certain states in which we operate, including Pennsylvania, Texas and West Virginia have adopted, and other states are
considering adopting, regulations imposing or that could impose new or more stringent permitting, public disclosure, or well
construction requirements on hydraulic fracturing operations. States could also elect to prohibit hydraulic fracturing
altogether. In December 2014, Governor Cuomo of the State of New York announced fracturing activities in New York
would be prohibited. Local governments also may seek to adopt ordinances within their jurisdiction regulating the time, place
or manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state
or local legal restrictions relating to the hydraulic fracturing process is adopted in areas where we currently or in the future
plan to operate, we may incur additional, more significant, costs to comply with such requirements and also could become
subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration,
development, or production activities.

In addition, certain government reviews are underway that focus on environmental aspects of hydraulic fracturing

practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic
fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on
drinking water and groundwater, with a final draft report drawing conclusions about the potential impacts of hydraulic
fracturing on drinking water resources expected to be available for public comment and peer review in early 2015. These
existing or any future studies, depending on any meaningful results obtained, could spur initiatives to further regulate
hydraulic fracturing under the federal Safe Drinking Act or other regulatory mechanisms.

We believe that our hydraulic fracturing activities follow applicable industry practices and legal requirements for
groundwater protection and that our fracturing operations have not resulted in material environmental liabilities. We do not
have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing
operations; however, we believe our existing insurance policies would cover third-party bodily injury and property damage
caused by hydraulic fracturing including sudden and accidental pollution coverage.

Oil and natural gas exploration, development and production activities on federal lands, including Indian lands and

lands administered by the BLM, are subject to the National Environmental Policy Act, as amended (“NEPA”). NEPA
requires federal agencies, including the BLM, to evaluate major agency actions having the potential to significantly impact
the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the
potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed
Environmental Impact Statement that may be made available for public review and comment. Currently, we have minimal
exploration and production activities on federal lands. However, for those current activities as well as for future or proposed
exploration and development plans on federal lands, governmental permits or authorizations that are subject to the
requirements of NEPA are required. This process has the potential to delay or limit, or increase the cost of, the development
of oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which
may delay or halt projects.

The federal Endangered Species Act, as amended (the “ESA”), restricts activities that may affect endangered and
threatened species or their habitats. If endangered species are located in an area where we wish to conduct seismic surveys,
development activities or abandonment operations, the work could be prohibited or delayed or expensive mitigation may be
required. Moreover, 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 areas. As a result of a settlement approved
by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service (“FWS”) is
required to make a determination on the listing of numerous species as endangered or threatened under the Endangered
Species Act prior to the completion of the agency’s 2017 fiscal year. For example, in March 2014, the FWS announced the
listing of the lesser prairie chicken, whose habitat is over a five-state region, including Oklahoma, where we conduct
operations, as a threatened species under the ESA. However, the FWS also announced a final rule that will limit regulatory
impacts on landowners and businesses from the listing if those landowners and businesses have entered into certain range-
wide conservation planning agreements, such as those developed by the Western Association of Fish and Wildlife Agencies,
pursuant to which such parties agreed to take steps to protect the lesser prairie chicken’s habitat and to pay a mitigation fee if
its actions harm the lesser prairie chicken habitat. The designation of previously unprotected species in areas where we
operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could
result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop
and produce our reserves.

The Migratory Bird Treaty Act implements various treaties and conventions between the United States and certain
other nations for the protection of migratory birds. In accordance with this law, the taking, killing or possessing of migratory
birds covered under this act is unlawful without a permit. If there is the potential to adversely affect migratory birds as a
result of our operations, we may be required to obtain necessary permits to conduct those operations, which may result in
specified operating restrictions on a temporary, seasonal, or permanent basis in affected areas and an adverse impact on our
ability to develop and produce our reserves.

In summary, we believe we are in substantial compliance with currently applicable environmental laws and regulations.
Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no
assurance that this will continue. We did not have any material capital or other non-recurring expenditures in connection with
complying with environmental laws or environmental remediation matters in 2014, nor do we anticipate that such
expenditures will be material in 2015. However, we regularly have expenditures to comply with environmental laws and
those costs continue to increase as our operations expand.

We are also subject to the requirements of the federal Occupational Safety and Health Act, as amended (“OSHA”), and

comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard
communication standard requires that information be maintained about hazardous materials used or produced in our
operations and that this information be provided to employees, state and local government authorities and citizens. We
believe that our operations are in substantial compliance with the OSHA requirements.

ITEM 1A. RISK FACTORS

We are subject to various risks and uncertainties in the course of our business. The following summarizes the known
material risks and uncertainties, which may adversely affect our business, financial condition or results of operations. These
risks are not the only risks we face. Our business could also be impacted by additional risks and uncertainties not currently
known to us or that we currently deem to be immaterial.

Risks Related to Our Business

Volatility of natural gas, NGLs and oil prices significantly affects our cash flow and capital resources and could hamper
our ability to produce natural gas, NGLs, crude oil and condensate economically

Natural gas, NGLs and oil prices are volatile, and a decline in prices adversely affects our profitability and financial

condition. The oil and gas industry is typically cyclical, and we expect the volatility to continue. Between 2011 and 2014, the
average NYMEX monthly settlement price of natural gas has been as high as $5.56 per mcf and as low as $2.04 per mcf.
During that same time frame, the average NYMEX monthly oil settlement price was as high as $110.04 per barrel and as low
as $59.29 per barrel. Recently, natural gas and oil prices have declined significantly with the average NYMEX monthly
settlement price for natural gas for February 2015 falling to $2.87 per mcf and the monthly settlement for crude oil falling to
$47.33 per barrel in January 2015. Likewise, NGLs have suffered significant recent declines in realized prices. NGLs are
made up of ethane, propane, isobutane, normal butane and natural gasoline, all of which have different uses and different
pricing characteristics. A further or extended decline in commodity prices could materially and adversely affect our business,
financial condition and results of operations. Natural gas prices are likely to affect us more than oil prices because
approximately 67% of our December 31, 2014 proved reserves are natural gas.

Natural gas, NGLs and oil prices fluctuate in response to changes in supply and demand, market uncertainty and other
factors that are beyond our control. Long-term supply and demand for natural gas, NGLs and oil is uncertain and subject to a
myriad of factors such as:

(cid:121)

the domestic and foreign supply of natural gas, NGLs and oil;
the price, availability and demand for alternative fuels and sources of energy;

(cid:121)
(cid:121) weather conditions;

(cid:121)

the level of consumer demand for natural gas, NGLs and oil;
the price and level of foreign imports;

(cid:121)
(cid:121) U.S. domestic and worldwide economic conditions;

(cid:121)

the availability, proximity and capacity of transportation facilities, processing and storage facilities;
the effect of worldwide energy conservation efforts;

(cid:121)
(cid:121) political conditions in natural gas and oil producing regions; and
(cid:121) domestic (federal, state and local) and foreign governmental regulations and taxes.

Lower natural gas, NGLs and oil prices may not only decrease our revenues on a per unit basis but also may reduce the
amount of natural gas, NGLs and oil that we can economically produce. A reduction in production could result in a shortfall
in expected cash flows and require a reduction in capital spending or require additional borrowing. Without the ability to fund
capital expenditures, we would be unable to replace reserves which would negatively affect our future rate of growth. Lower
natural gas, NGLs and oil prices may also result in a reduction in the borrowing base under our bank credit facility, which is
determined by our lenders at their discretion, taking into account the value of our estimated proved reserves, which is
adversely affected by declines in natural gas, NGLs and oil prices. The borrowing base under our bank credit facility is
subject to redetermination annually each May and for event driven unscheduled redeterminations.

Producing natural gas, NGLs and oil may involve unprofitable efforts. As of December 31, 2014, the relationship
between the price of oil and the price of natural gas continues to be at an historically wide spread. Normally, natural gas
liquids production is a by-product of natural gas production. Due to the current differences in prices, we and other producers
may choose to sell natural gas at below cost, or otherwise dispose of natural gas to allow for the profitable sale of only NGLs
and condensate. Over the past four years, the average Mont Belvieu NGL composite has been as high as $1.31 per gallon and
as low as $0.44 per gallon.

Information concerning our reserves and future net cash flow estimates is uncertain

There are numerous uncertainties inherent in estimating quantities of proved natural gas and oil reserves and their
values, including many factors beyond our control. Estimates of proved reserves are by their nature uncertain and depend on
many assumptions relating to current and further economic conditions and commodity prices. Although we believe these

estimates are reasonable, actual production, revenues and costs to develop will likely vary from estimates and these variances
could be material.

Reserve estimation is a subjective process that involves estimating volumes to be recovered from underground
accumulations of natural gas and oil that cannot be directly measured. As a result, different petroleum engineers, each using
industry-accepted geologic and engineering practices and scientific methods, may calculate different estimates of reserves
and future net cash flows based on the same available data. Because of the subjective nature of natural gas, NGLs and oil
reserve estimates, each of the following items may differ materially from the amounts or other factors estimated:

(cid:121)

the amount and timing of natural gas, NGLs and oil production;
the revenues and costs associated with that production;
the amount and timing of future development expenditures; and
future commodity prices.

The discounted future net cash flows from our proved reserves included in this report should not be considered as the

market value of the reserves attributable to our properties. As required by generally accepted accounting principles, the
estimated discounted future net revenues from our proved reserves are based on a twelve month average price (first day of the
month) while cost estimates are based on current year-end economic conditions. Actual future prices and costs may be
materially higher or lower. In addition, the ten percent discount factor that is required to be used to calculate discounted
future net revenues for reporting purposes under generally accepted accounting principles is not necessarily the most
appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and
the oil and gas industry in general.

If natural gas, NGLs and oil prices decrease or drilling efforts are unsuccessful, we may be required to record writedowns
of our natural gas and oil properties

In the past we have been required to write down the carrying value of certain of our natural gas and oil properties, and
there is a risk that we will be required to take additional writedowns in the future. Writedowns may occur when natural gas
and oil prices are low, or if we have downward adjustments to our estimated proved reserves, increases in our estimates of
operating or development costs, deterioration in our drilling results or mechanical problems with wells where the cost to
redrill or repair is not supported by the expected economics.

Accounting rules require that the carrying value of natural gas and oil properties be periodically reviewed for possible
impairment. Impairment is recognized for the excess of book value over fair value when the book value of a proven property
is greater than the expected undiscounted future net cash flows from that property and on acreage when conditions indicate
the carrying value is not recoverable. We may be required to write down the carrying value of a property based on natural gas
and oil prices at the time of the impairment review, or as a result of continuing evaluation of drilling results, production data,
economics, divestiture activity, and other factors. A write down constitutes a non-cash charge to earnings and does not
impact cash or cash flows from operating activities; however, it reflects our long-term ability to recover an investment and
reduces our reported earnings and increases our leverage ratios.

Significant capital expenditures are required to replace our reserves

Our exploration, development and acquisition activities require substantial capital expenditures. Historically, we have

funded our capital expenditures through a combination of cash flow from operations, our bank credit facility and debt and
equity issuances. We have also engaged in asset monetization transactions. Future cash flows are subject to a number of
variables, such as the level of production from existing wells, prices of natural gas, NGLs and oil and our success in
developing and producing new reserves. If our access to capital were limited due to various factors, which could include a
decrease in revenues due to lower natural gas, NGLs and oil prices or decreased production or deterioration of the credit and
capital markets, we would have a reduced ability to replace our reserves. We may not be able to incur additional bank debt,
issue debt or equity, engage in asset monetization or access other methods of financing on an economic basis to meet our
reserve replacement requirements.

The amount available for borrowing under our bank credit facility is subject to a borrowing base, which is determined

by our lenders, at their discretion, taking into account our estimated proved reserves and is subject to periodic
redeterminations based on pricing models determined by the lenders at such time. Declines in natural gas, NGLs and oil
prices adversely impact the value of our estimated proved reserves and, in turn, the market values used by our lenders to
determine our borrowing base and could result in a determination to lower our borrowing base. Recently, natural gas, NGLs
and oil prices have declined significantly. A further or extended decline is commodity prices could materially and adversely
affect our business, financial condition and results of operation.

Our future success depends on our ability to replace reserves that we produce

Because the rate of production from natural gas and oil properties generally declines as reserves are depleted, our

future success depends upon our ability to economically find or acquire and produce additional natural gas, NGLs and oil
reserves. Except to the extent that we acquire additional properties containing proved reserves, conduct successful
exploration and development activities or, through engineering studies, identify additional behind-pipe zones or secondary
recovery reserves, our proved reserves will decline as reserves are produced. Future natural gas, NGLs and oil production,
therefore, is highly dependent upon our level of success in acquiring or finding additional reserves that are economically
recoverable. We cannot assure you that we will be able to find or acquire and develop additional reserves at an acceptable
cost.

We acquire significant amounts of unproved property to further our development efforts. Development and exploratory
drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will
be discovered. We acquire both producing and unproved properties as well as lease undeveloped acreage that we believe will
enhance growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be
economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that
unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by
us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such
unproved property or wells.

Drilling is an uncertain and costly activity

The cost of drilling, completing, and operating a well is often uncertain, and many factors can adversely affect the

economics of a well. Our efforts will be uneconomical if we drill dry holes or wells that are productive but do not produce
enough natural gas, NGLs and oil to be commercially viable after drilling, operating and other costs. There is no way to
conclusively know in advance of drilling and testing whether any particular prospect will yield natural gas, NGLs or oil in
commercially viable quantities. Furthermore, our drilling and producing operations may be curtailed, delayed, or canceled as
a result of a variety of factors, including:

(cid:121)

increases in the costs, shortages or delivery delays of drilling rigs, equipment, water for hydraulic fracturing
services, labor, or other services;

(cid:121) unexpected operational events and drilling conditions;

reductions in natural gas, NGLs and oil prices;
limitations in the market for natural gas, NGLs and oil;
adverse weather conditions;
facility or equipment malfunctions;
equipment failures or accidents;
title problems;

(cid:121)
(cid:121) pipe or cement failures;

(cid:121)

compliance with, or changes in, environmental, tax and other governmental requirements;

environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, and unauthorized
discharges of toxic gases;
lost or damaged oilfield drilling and service tools;

(cid:121)
(cid:121) unusual or unexpected geological formations;

loss of drilling fluid circulation;
(cid:121)
(cid:121) pressure or irregularities in formations;

fires;

(cid:121)
(cid:121) natural disasters;

surface craterings and explosions; and

(cid:121)
(cid:121) uncontrollable flows of oil, natural gas or well fluids.

If any of these factors were to occur, we could lose all or a part of our investment, or we could fail to realize the

expected benefits, either of which could materially and adversely affect our revenue and profitability.

Our identified drilling locations are scheduled out over multiple years, making them susceptible to uncertainties that
could materially alter the occurrence or timing of their drilling

Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future

multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth
strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas and oil
prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment,
drilling results, lease expirations, transportation constraints, regulatory and zoning approvals and other factors. Because of
these uncertain factors, we do not know if the numerous drilling locations we have identified will ever be drilled. In addition,
unless production is established within the spacing units covering the undeveloped acres on which some of the drilling
locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ
from those presently identified. In addition, we will require significant additional capital over a prolonged period in order to
pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any
drilling activities we are able to conduct on these locations may not be successful or result in our ability to add additional
proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which
could have a material adverse effect on our business and results of operations.

Our producing properties are concentrated in the Appalachian Basin, making us vulnerable to risks associated with
operating in one geographic area

Our producing properties are geographically concentrated in the Appalachian Basin in Pennsylvania, Virginia and West

Virginia. At December 31, 2014, 96% of our total estimated proved reserves were attributable to properties located in this
area with 86% in Pennsylvania alone. As a result of this concentration, we may be disproportionately exposed to the impact
of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental
regulation, state politics, processing or transportation capacity constraints, market limitations, availability of equipment and
personnel, water shortages or interruption of the processing or transportation of crude oil, condensate, natural gas or NGLs.

New technologies may cause our current exploration and drilling methods to become obsolete

There have been rapid and significant advancements in technology in the natural gas and oil industry, including the

introduction of new products and services using new technologies. As competitors use or develop new technologies, we may
be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a
substantial increase in cost. Further, competitors may obtain patents which might prevent us from implementing new
technologies. In addition, competitors may have greater financial, technical and personnel resources that allow them to enjoy
technological advantages and may in the future allow them to implement new technologies before we can. One or more of the
technologies that we currently use or that we may implement in the future may become obsolete. We cannot be certain that
we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain
technological advancements consistent with industry standards, our operations and financial condition may be adversely
affected.

Our indebtedness could limit our ability to successfully operate our business

We are leveraged and our exploration and development program will require substantial capital resources depending on

the level of drilling and the expected cost of services. Our existing operations will also require ongoing capital expenditures.
In addition, if we decide to pursue additional acquisitions, our capital expenditures will increase, both to complete such
acquisitions and to explore and develop any newly acquired properties.

The degree to which we are leveraged could have other important consequences, including the following:

(cid:121) we may be required to dedicate a substantial portion of our cash flows from operations to the payment of our

indebtedness, reducing the funds available for our operations;
a portion of our borrowings are at variable rates of interest, making us vulnerable to increases in interest rates;

(cid:121)

(cid:121) we may be more highly leveraged than some of our competitors, which could place us at a competitive

disadvantage;

(cid:121) our degree of leverage may make us more vulnerable to a downturn in our business or the general economy;

(cid:121) we are subject to numerous financial and other restrictive covenants contained in our existing debt agreements,
which restrict our ability to engage in certain activities and could limit our growth, and the breach of such
covenants, which could materially and adversely impact our financial performance;

(cid:121) our debt level could limit our flexibility to grow the business and in planning for, or reacting to, changes in our

business and the industry in which we operate; and
(cid:121) we may have difficulties borrowing money in the future.

Despite our current levels of indebtedness, we still may be able to incur substantially more debt. This could further

increase the risks described above. In addition to those risks above, we may not be able to obtain funding on acceptable
terms.

Any failure to meet our debt obligations could harm our business, financial condition and results of operations

We expect our earnings and cash flow to vary significantly from year to year due to the cyclical nature of our business.

If our cash flow and capital resources are insufficient to fund our debt obligations, we may be forced to sell assets, seek
additional equity or restructure our debt. Our ability to restructure our debt will depend on the condition of the capital
markets and our financial condition at such time. Any restructuring of debt could be at higher interest rates and may require
us to comply with more onerous covenants, which could further restrict our operations. The terms of existing or future debt
instruments may restrict us from adopting some of these alternatives. In addition, any failure to make scheduled payments of
interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could
harm our ability to incur additional indebtedness on acceptable terms. Our cash flow and capital resources may be insufficient
for payment of interest on and principal of our debt in the future and any such alternative measures may be unsuccessful or
may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations and impair
our liquidity.

We are subject to financing and interest rate exposure risks

Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital,
increases in interest rates or a reduction in our credit rating. These changes could cause our cost of doing business to increase,
limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive
disadvantage. For example, at December 31, 2014, approximately 76% of our debt is at fixed interest rates with the
remaining 24% subject to variable interest rates.

Disruptions or volatility in the global finance markets may lead to a contraction in credit availability impacting our

ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from
operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and
operating results. We are exposed to some credit risk related to our bank credit facility to the extent that one or more of our
lenders may be unable to provide necessary funding to us under our existing revolving line of credit if it experiences liquidity
problems.

A financial downturn or negative credit market conditions may have lasting effects on our liquidity, business and
financial condition that we cannot predict

Liquidity is essential to our business. Our liquidity could be substantially negatively affected by an inability to obtain
capital in the long-term or short-term debt capital markets or equity capital markets or an inability to access bank financing.
A prolonged credit crisis or turmoil in the domestic or global financial systems could materially affect our liquidity, business
and financial condition. These conditions have adversely impacted financial markets previously and created substantial
volatility and uncertainty, and could do so again, with the related negative impact on global economic activity and the
financial markets. Negative credit market conditions could materially affect our liquidity and may inhibit our lenders from
fully funding our bank credit facility or cause them to make the terms of our bank credit facility costlier and more restrictive.
We are subject to annual reviews, as well as unscheduled reviews, of our borrowing base under our bank credit facility, and
we do not know the results of future redeterminations or the effect of then-current oil and natural gas prices on that process.
A weak economic environment could also adversely affect the collectability of our trade receivables or performance by our
suppliers and cause our commodity derivative arrangements to be ineffective if our counterparties are unable to perform their
obligations or seek bankruptcy protection. Additionally, negative economic conditions could lead to reduced demand for
natural gas, NGLs and oil or lower prices for natural gas and oil, which could have a negative impact on our revenues.

Derivative transactions may limit our potential gains and involve other risks

To manage our exposure to price risk, we currently and may in the future enter into derivative arrangements, utilizing

commodity derivatives with respect to a portion of our future production. The goal of these hedges is to lock in prices so as to
limit volatility and increase the predictability of cash flow. These transactions limit our potential gains if natural gas, NGLs
and oil prices rise above the price established by the hedge.

In addition, derivative transactions may expose us to the risk of financial loss in certain circumstances, including

instances in which:

(cid:121) our production is less than expected;

(cid:121)

the counterparties to our futures contracts fail to perform on their contract obligations; or

(cid:121)

an event materially impacts natural gas, NGLs or oil prices or the relationship between the hedged price index
and the natural gas or oil sales price.

We cannot assure you that any derivative transaction we may enter into will adequately protect us from declines in the
prices of natural gas, NGLs or oil. On the other hand, where we choose not to engage in derivative transactions in the future,
we may be more adversely affected by changes in natural gas, NGLs or oil prices than our competitors who engage in
derivative transactions. Lower natural gas and oil prices may also negatively impact our ability to enter into derivative
contracts at favorable prices.

Many of our current and potential competitors have greater resources than we have and we may not be able to
successfully compete in acquiring, exploring and developing new properties

We face competition in every aspect of our business, including, but not limited to, acquiring reserves and leases,
obtaining goods, services and employees needed to operate and manage our business and marketing natural gas, NGLs or oil.
Competitors include multinational oil companies, independent production companies and individual producers and operators.
Many of our competitors have greater financial and other resources than we do. As a result, these competitors may be able to
address these competitive factors more effectively than we can or weather industry downturns more easily than we can. For
more discussion regarding competition, see “Items 1 and 2. Business and Properties – Competition.”

We could experience periods of higher costs if commodity prices rise. These increases could reduce our profitability, cash
flow and ability to complete development activities as planned

Historically, our capital and operating costs have risen during periods of increasing oil, NGLs and gas prices. These
cost increases result from a variety of factors beyond our control, such as increases in the cost of electricity, steel and other
raw materials that we and our vendors rely upon; increased demand for labor, services and materials as drilling activity
increases; and increased taxes. Increased levels of drilling activity in the natural gas and oil industry in recent periods have
led to increased costs of some drilling equipment, materials and supplies. Such costs may rise faster than increases in our
revenue, thereby negatively impacting our profitability, cash flow and ability to complete development activities as scheduled
and on budget.

The natural gas and oil industry is subject to extensive regulation

The natural gas and oil industry is subject to various types of regulations in the United States by local, state and federal

agencies. Legislation affecting the industry is under constant review for amendment or expansion, frequently increasing our
regulatory burden. Numerous departments and agencies, both state and federal, are authorized by statute to issue rules and
regulations binding on participants in the natural gas and oil industry. Compliance with such rules and regulations often
increases our cost of doing business, delays our operations and, in turn, decreases our profitability.

Our operations are subject to numerous and increasingly strict federal, state and local laws, regulations and

enforcement policies relating to the environment. We may incur significant costs and liabilities in complying with existing or
future environmental laws, regulations and enforcement policies and may incur costs arising out of property or natural
resource damage or injuries to employees and other persons. These costs may result from our current and former operations
and even may be caused by previous owners of property we own or lease or relate to third party sites where we have taken
materials for recycling or disposal. Failure to comply with these laws and regulations may result in the suspension or
termination of our operations and subject us to administrative, civil and criminal penalties as well as corrective action orders.
Matters subject to regulation include:

(cid:121)

the amounts and types of substances and materials that may be released into the environment;
response to unexpected releases to the environment;
reports and permits concerning exploration, drilling, production and other regulated activities;
the spacing of wells;

(cid:121)
(cid:121) unitization and pooling of properties;

(cid:121)

calculating royalties on oil and gas produced under federal and state leases; and
taxation.

Under these laws and regulations, we could be liable for personal injuries, property damages, oil spills, discharges of
hazardous materials, remediation and clean-up costs, natural resource damages and other environmental damages. We also
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. If we incur these costs or damages it may reduce
or eliminate funds available for exploration, development or acquisitions or cause us to incur losses.

The subject of climate change is receiving increasing attention from scientists, legislators, governmental agencies and
the general public. There is an ongoing debate as to the extent to which our climate is changing, the potential causes of this
change and its potential impacts. Some attribute global warming to increased levels of GHGs, including carbon dioxide and
methane, which has led to significant legislative and regulatory efforts to limit GHG emissions.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been
significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. However,
there have been a number of regulatory initiatives to address GHG emissions, which include the establishing of Title V and
PSD permitting reviews for GHG emissions from certain large stationary sources that are already major potential sources of
certain principal, or criteria, pollutant emissions, and the implementation of a GHG monitoring and reporting program for
certain sectors of the natural gas and oil industry, including onshore and production, which includes certain of our operations.
A number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of
cap and trade programs, in which major sources of GHG emissions acquire and surrender emission allowances in return for
emitting those GHGs. The outcome of federal and state actions to address global climate change could result in a variety of
regulatory programs including potential new regulations to control or restrict emissions, taxes or other charges to deter
emissions of GHGs, energy efficiency requirements to reduce demand, or other regulatory actions. For example, pursuant to
President Obama’s Strategy to Reduce Methane Emissions, the Obama Administration announced on January 14, 2015, that
EPA is expected to propose in the summer of 2015 and finalize in 2016 new regulations that will set methane emission
standards for new and modified oil and gas production and natural gas processing and transmission facilities as part of the
Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45 percent from 2012 levels by
2025. These actions could:

(cid:121)

result in increased costs associated with our operations;
increase other costs to our business;
affect the demand for natural gas; and
impact the prices we charge our customers.

Adoption of federal or state requirements mandating a reduction in GHG emissions could have far-reaching and

significant impacts on the energy industry and the U.S. economy. We cannot predict the potential impact of such laws or
regulations on our future consolidated financial condition, results of operations or cash flows. For more information
regarding the environmental regulation of our business, see “Items 1 and 2. Business and Properties – Environment and
Occupational Health and Safety Matters.”

Our business is subject to operating hazards that could result in substantial losses or liabilities that may not be fully
covered under our insurance policies

Natural gas, NGLs and oil operations are subject to many risks, including well blowouts, craterings, explosions,

uncontrollable flows of oil, natural gas or well fluids, fires, pipe or cement failures, pipeline ruptures or spills, vandalism,
pollution, releases of toxic gases, adverse weather conditions or natural disasters, and other environmental hazards and risks.
If any of these hazards occur, we could sustain substantial losses as a result of:

(cid:121)

injury or loss of life;
severe damage to or destruction of property, natural resources and equipment;

(cid:121)

(cid:121)
(cid:121) pollution or other environmental damage;
investigatory and cleanup responsibilities;
regulatory investigations and penalties or lawsuits;
suspension of operations; and
repairs to resume operations.

(cid:121)

We maintain insurance against many, but not all, potential losses or liabilities arising from our operations in

accordance with what we believe are customary industry practices and in amounts and at costs that we believe to be prudent
and commercially practicable. Our insurance includes deductibles that must be met prior to recovery, as well as sub-limits
and/or self-insurance. Additionally, our insurance is subject to exclusions and limitations. Our insurance does not cover every
potential risk associated with our operations, including the potential loss of significant revenues. We can provide no
assurance that our coverage will adequately protect us against liability from all potential consequences, damages and losses.

We currently have insurance policies covering our operations that include coverage for general liability, excess
liability, physical damage to our oil and gas properties, operational control of wells, oil pollution, third-party liability,
workers’ compensation and employer’s liability and other coverages. Consistent with insurance coverage generally available
to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with coverage for
sudden and accidental occurrences. For example, we maintain operator’s extra expense coverage provided by third-party
insurers for obligations, expenses or claims that we may incur from a sudden incident that results in negative environmental
effects, including obligations, expenses or claims related to seepage and pollution, cleanup and containment, evacuation
expenses and control of the well (subject to policy terms and conditions). In the specific event of a well blowout or out-of-
control well resulting in negative environmental effects, such operator’s extra expense coverage would be our primary source
of coverage, with the general liability and excess liability coverage referenced above also providing certain coverage.

In the event we make a claim under our insurance policies, we will be subject to the credit risk of the insurers.

Volatility and disruption in the financial and credit markets may adversely affect the credit quality of our insurers and impact
their ability to pay claims.

Further, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to
the risks presented. Some forms of insurance may become unavailable in the future or unavailable on terms that we believe
are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that
we consider reasonable, and we may elect to maintain minimal or no insurance coverage. If we incur substantial liability from
a significant event and the damages are not covered by insurance or are in excess of policy limits, then we would have lower
revenues and funds available to us for our operations, that could, in turn, have a material adverse affect on our business,
financial condition and results of operations.

Additionally, we rely to a large extent on facilities owned and operated by third parties, and damage to or destruction of

those third-party facilities could affect our ability to process, transport and sell our production. To a limited extent, we
maintain business interruption insurance related to a third-party processing plant in Pennsylvania where we are insured for
potential losses from the interruption of production caused by loss of or damage to the processing plant.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a
change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to
decline and operating expenses to increase

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by the FERC as a natural gas
company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests the
FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, we
have not received a declaratory order from the FERC regarding our natural gas gathering pipelines and the distinction
between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing
litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations
by the FERC, the courts or Congress.

While we believe our natural gas gathering operations are generally exempt from FERC regulation under the NGA, our

gas gathering operations may be subject to certain FERC reporting and posting requirements in a given year. The FERC has
issued a final rule requiring certain participants in the natural gas market, including certain gathering facilities and natural gas
marketers that engage in a minimum level of natural gas sales or purchases, to submit annual reports to the FERC on the
aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions
utilize, contribute to, or may contribute to, the formation of price indices.

Other FERC regulations may indirectly impact our businesses and the markets for products derived from these

businesses. The FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example,
its policies on open access transportation, gas quality, ratemaking, capacity release and market-center promotion, may
indirectly affect the intrastate natural gas market. In recent years, the FERC has pursued pro-competitive policies in its
regulation of interstate natural gas pipelines. However, we cannot assure you that the FERC will continue this approach as it
considers matters such as pipelines rates and rules and policies that may affect rights of access to transportation capacity. For
more information regarding the regulation of our operations, see “Items 1 and 2. Business and Properties – Governmental
Regulation.”

Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be
subject to substantial penalties and fines

Under EPAct 2005, the FERC has civil penalty authority under the NGA to impose penalties for current violations of
up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our operations
have not been regulated as a natural gas company by the FERC under the NGA, the FERC has adopted regulations that may
subject certain of our otherwise non-FERC jurisdictional facilities to the FERC annual reporting requirements. We also must
comply with the anti-market manipulation rules enforced by the FERC. Additional rules and legislation pertaining to those

and other matters may be considered or adopted by the FERC from time to time. Failure to comply with those regulations in
the future could subject Range to civil penalty liability. For more information regarding the regulation of our operations, see
“Items 1 and 2. Business and Properties – Governmental Regulation.”

Certain federal income tax deductions currently available with respect to natural gas and oil exploration and development
may be eliminated, and additional state taxes on natural gas extraction may be imposed, as a result of future legislation

Legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax

laws, including the elimination of certain U.S. federal income tax benefits currently available to oil and gas exploration and
production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for
oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the
elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain
geological and geophysical expenditures. It is unclear, however, whether any such changes will be enacted or how soon such
changes could be effective. As of December 31, 2014, we had a tax basis of $2.2 billion related to prior years capitalized
intangible drilling costs, which will be amortized over the next five years.

The passage of this legislation or any other similar change in U.S. federal income tax law could eliminate or postpone

certain tax deductions that are currently available with respect to natural gas and oil exploration and development, and any
such change could negatively affect our financial condition and results of operations.

In February 2012, the state legislature of Pennsylvania passed a new natural gas impact fee in Pennsylvania, where the

majority of our acreage in the Marcellus Shale is located. The legislation imposes an annual fee on natural gas and oil
operators for each well drilled for a period of fifteen years. Much like a severance tax, the fee is on a sliding scale set by the
Public Utility Commission and is based on two factors: changes in the Consumer Price Index and the average NYMEX
natural gas prices from the last day of each month. The passage of this legislation increases the financial burden on our
operations in the Marcellus Shale. There can be no assurance that the impact fee will remain as currently structured or that
additional taxes will not be imposed. In addition, there are currently proposals by various Pennsylvania state lawmakers to
enact a severance tax in addition to the impact fee already in place.

Changes in laws or regulations relating to hydraulic fracturing could result in increased costs and additional operating
restrictions or delays and adversely affect our production

Hydraulic fracturing involves the injection of water, sand and small amounts of additives under pressure into rock
formations to stimulate hydrocarbon (natural gas and oil) production. We find that the use of hydraulic fracturing is necessary
to produce commercial quantities of natural gas and oil from many reservoirs, especially shale formations such as the
Marcellus Shale. The process is typically regulated by state oil and gas commissions. However, several federal agencies have
asserted regulatory authority over certain aspects of the process. For example, the EPA has issued final Clean Air Act
regulations governing performance standards, including standards for the capture of air emissions released during hydraulic
fracturing; announced its intent to propose in early 2015 effluent limit guidelines that wastewater from shale gas extraction
operations must meet before discharging to a treatment plant; and issued in May 2014 a prepublication of its Advance Notice
of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in
hydraulic fracturing. Also, for example, in May 2013, the BLM issued a revised proposed rule containing disclosure
requirements and other mandates for hydraulic fracturing on federal lands and the agency is now analyzing comments to the
proposed rulemaking and is expected to promulgate a final rule in early 2015.

From time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of

hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Certain states in which we
operate, including Pennsylvania, Texas and West Virginia, have adopted, and other states are considering adopting,
regulations that could impose new or more stringent permitting, disclosure or well-construction requirements on hydraulic
fracturing operations. States could elect to prohibit hydraulic fracturing altogether, as Governor Andrew Cuomo of the State
of New York announced in December 2014 with regard to fracturing activities in New York. Local land use restrictions, such
as city ordinances, may restrict or prohibit drilling in general and/or hydraulic fracturing in particular. In the event federal,
state or local restrictions or prohibitions are adopted in areas where we conduct operations, we may incur significant costs to
comply with such requirements or we may experience delays or curtailment in the pursuit of exploration, development, or
production activities, and possibly be limited or precluded in the drilling of wells or in the amounts that we are ultimately
able to produce from our reserves. Moreover, a number of federal entities are analyzing a variety of environmental issues
associated with hydraulic fracturing. For example, the White House Council on Environmental Quality is coordinating an
administration-wide review of hydraulic fracturing and the EPA has been pursuing a study begun in 2011 of the potential
environmental effects of hydraulic fracturing on drinking water and groundwater, with a draft final report expected to be
issued for peer review and comment by early 2015. These studies and initiatives, or any future studies, depending on their
degree of pursuit and any meaningful results obtained, could spur efforts to further regulate hydraulic fracturing.

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.

The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce
the effect of commodity price, interest rate and other risks associated with our business

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), enacted in July 2010, established
federal oversight and regulation of the over-the-counter derivatives market and entities, including Range, that participate in
that market. The Act requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules
and regulations implementing the Act. Although the CFTC has finalized certain regulations, others remain to be finalized or
implemented and it is not possible at this time to predict when this will be accomplished.

In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major

energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United
States District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new
rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain
physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are
not yet final, the impact of those provisions on us is uncertain at this time.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated

rules also will require us, in connection with covered derivative activities, to comply with clearing and trade-execution
requirements or take steps to qualify for an exemption to such requirements. The CFTC has not yet proposed rules
designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. Although we expect to
qualify for the end-user exception from the mandatory clearing requirements for swaps entered to hedge our commercial
risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap
dealers, may change the cost and availability of the swaps that we use for hedging. In addition, for uncleared swaps, the
CFTC or federal banking regulators may require end-users to enter into credit support documentation and/or post initial and
variation margin. Posting of collateral could impact liquidity and reduce cash available to us for capital expenditures,
therefore reducing our ability to execute hedges to reduce risk and protect cash flows. The proposed margin rules are not yet
final, and therefore the impact of those provisions to us is uncertain at this time.

The full impact of the Act and related regulatory requirements upon our business will not be known until the

regulations are implemented and the market for derivatives contracts has adjusted. The Act and new regulations could
significantly increase the cost of derivative contracts or materially alter the terms of derivative contracts, reduce the
availability of derivatives to protect against risks we encounter or reduce our ability to monetize or restructure our existing
derivative contracts. If we reduce our use of derivatives as a result of the Act and regulations implementing the Act, our
results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our
ability to plan for and fund capital expenditures.

Finally, the Act was intended, in part, to reduce the volatility of oil and gas prices, which some legislators attributed to

speculative trading in derivatives and commodity instruments related to oil and gas. Our revenues could therefore be
adversely affected if a consequence of the Act and implementing regulations is to lower commodity prices.

Laws and regulations pertaining to threatened and endangered species could delay or restrict our operations and cause us
to incur substantial costs

Various federal and state statutes prohibit certain actions that adversely affect endangered or threatened species and
their habitats, migratory birds, wetlands and natural resources. These statutes include the ESA, the Migratory Bird Treaty
Act, the CWA and CERCLA. The FWS may designate critical habitat and suitable habitat areas that it believes are necessary
for survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in further
material restrictions to federal land use and private land use and could delay or prohibit land access or oil and gas
development. If harm to species or damages to wetlands, habitat or natural resources occur or may occur, government entities
or, at times, private parties may act to prevent oil and gas exploration or development activities or seek damages for harm to
species, habitat or natural resources resulting from drilling or construction or releases of oil, wastes, hazardous substances or
other regulated materials, and, in some cases, may seek criminal penalties. Moreover, as a result of a settlement approved by
the U.S. District Court for the District of Columbia in September 2011, the FWS is required to consider listing numerous
species as endangered or threatened under the ESA before completion of the agency’s 2017 fiscal year, and in March 2014,
listed the lesser prairie chicken as a threatened species in a five-state region, including Texas, where we have operations. The
29

designation of previously unprotected species as threatened or endangered in areas where we conduct operations could cause
us to incur increased costs arising from species protection measures or could result in limitations on its exploration and
production activities that could have an adverse effect on our ability to develop and produce reserves.

Our business depends on natural gas and oil transportation and NGLs processing facilities, most of which are owned by
others and depends on our ability to contract with those parties

Our ability to sell our natural gas, NGLs and oil production depends in part on the availability, proximity and capacity

of pipeline systems and processing facilities owned by third parties and our ability to contract with those third parties. The
lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or
discontinuance of development plans for properties. Although we have some contractual control over the transportation of
our product, material changes in these business relationships, including the financial condition of these third parties, could
materially affect our operations. In some cases, we do not purchase firm transportation on third party facilities and therefore,
our production transportation can be interrupted by those having firm arrangements. We have entered into firm transportation
arrangements in the Marcellus Shale where we are obligated to pay fees on minimum volumes regardless of actual volume
throughput. We have also entered into long-term agreements with third parties to provide natural gas gathering and
processing services in the Marcellus Shale. In some cases, the capacity of gathering systems and transportation pipelines may
be insufficient to accommodate potential production from existing and new wells. Federal and state regulation of natural gas
and oil production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to
or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport
natural gas, NGLs and oil. If any of these third party pipelines and other facilities become partially or fully unavailable to
transport or process our product, or if the natural gas quality specifications for a natural gas pipeline or facility changes so as
to restrict our ability to transport natural gas on those pipelines or facilities, our revenues could be adversely affected.

The disruption of third-party facilities due to maintenance and/or weather could negatively impact our ability to market

and deliver our products. In particular, the disruption of certain third-party natural gas processing facilities in the Marcellus
Shale could materially affect our ability to market and deliver natural gas production in that area. We have no control over
when or if such facilities are restored and generally have no control over what prices will be charged. A total shut-in of
production could materially affect us due to a lack of cash flow, and if a substantial portion of the production is hedged at
lower than market prices, those financial hedges would have to be paid from borrowings absent sufficient cash flow.

Currently, there is little demand, or facilities to supply the existing demand elsewhere, for ethane in the Appalachian
region. We have announced three ethane agreements wherein we have contracted to either sell or transport ethane from our
Marcellus Shale area, two of which began initial deliveries in late 2013, and the final one expected to begin operations in
mid-2015. We cannot assure you that all these facilities will become or will remain available.

Acquisitions are subject to the risks and uncertainties of evaluating reserves and potential liabilities and may be disruptive
and difficult to integrate into our business

We could be subject to significant liabilities related to our acquisitions. It generally is not feasible to review in detail
every individual property included in an acquisition. Ordinarily, a review is focused on higher-valued properties. However,
even a detailed review of all properties and records may not reveal existing or potential problems in all of the properties, nor
will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do
not always inspect every well we acquire, and environmental problems, such as groundwater contamination, are not
necessarily observable even when an inspection is performed.

In addition, there is intense competition for acquisition opportunities in our industry. Competition for acquisitions may
increase the cost of, or cause us to refrain from, completing acquisitions. Our acquisition strategy is dependent upon, among
other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to pursue
our acquisition strategy may be hindered if we are unable to obtain financing on terms acceptable to us or regulatory
approvals.

Acquisitions often pose integration risks and difficulties. In connection with recent and future acquisitions, the process
of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require
significant management attention and financial resources that would otherwise be available for the ongoing development or
expansion of existing operations. Future acquisitions could result in our incurring additional debt, contingent liabilities,
expenses and diversion of resources, all of which could have a material adverse effect on our financial condition and
operating results.

We may be unable to dispose of nonstrategic assets on attractive terms, and may be required to retain liabilities for certain
matters

We regularly review our property base for the purpose of identifying nonstrategic assets, the disposition of which
would increase capital resources available for other activities and create organizational and operational efficiencies. Various

factors could materially affect our ability to dispose of nonstrategic assets or complete announced dispositions, including the
availability of purchasers willing to purchase the nonstrategic assets at prices acceptable to us. Sellers typically retain certain
liabilities for certain matters. The magnitude of any such retained liability or indemnification obligation may be difficult to
quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third
parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets.
As a result, after a sale, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the
buyer of the assets fails to perform these obligations.

Our success depends on key members of our management and our ability to attract and retain experienced technical and
other professional personnel

Our success is highly dependent on our management personnel and none of them is currently subject to an employment

contract. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore,
competition for experienced technical and other professional personnel remains strong. If we cannot retain our current
personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of
experienced personnel could lead to a loss of technical expertise.

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. We operate approximately 96% of our
wells, as of December 31, 2014. We have limited ability to influence or control the operation or future development of non-
operated properties 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 acquisitions activities and lead to unexpected future costs.

We exist in a litigious environment

Any constituent could bring suit regarding our existing or planned operations or allege a violation of an existing

contract. Any such action could delay when planned operations can actually commence or could cause a halt to existing
production until such alleged violations are resolved by the courts. Not only could we incur significant legal and support
expenses in defending our rights, but halting existing production or delaying planned operations could impact our future
operations and financial condition. Such legal disputes could also distract management and other personnel from their
primary responsibilities.

Our business could be negatively affected by security threats, including cybersecurity threats, and other disruptions

As a natural gas and oil producer, we face various security threats, including cybersecurity threats to gain unauthorized
access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure
or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The
potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on
our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats
and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs.
Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from
occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical
infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial
position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include,
but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches
that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and
corruption of data. These events could damage our reputation and lead to financial losses from remedial actions, loss of
business or potential liability.

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, and explosions of natural gas transmission lines, may lead to
regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines
and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs,
additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable
discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through
intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be
withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.

Conservation measures and technological advances could reduce demand for oil and natural gas

Fuel conservation measures, alternative fuel requirements, governmental requirements for renewable energy resources,

increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy
generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas
services and products may have a material adverse effect on our business, financial condition, results of operations and cash
flows.

Our financial statements are complex

Due to United States generally accepted accounting principles and the nature of our business, our financial statements
continue to be complex, particularly with reference to derivatives, asset retirement obligations, equity awards, deferred taxes
and the accounting for our deferred compensation plans. We expect such complexity to continue and possibly increase.

Risks Related to Our Common Stock

Common stockholders will be diluted if additional shares are issued

In 2005, 2006, 2007 and 2008, we sold 52.7 million shares of common stock to finance acquisitions or pay down our
outstanding bank credit facility. In 2009 and 2010, we issued 1.1 million shares of common stock to purchase acreage in the
Marcellus Shale. In 2014, we issued approximately 4.6 million shares of common stock in a public stock offering with the
proceeds used to redeem our 8% senior subordinated notes due 2019. Our ability to repurchase securities for cash is limited
by our bank credit facility and our senior subordinated note agreements. We also issue restricted stock, stock appreciation
rights and performance share units to our employees and directors as part of their compensation. In addition, we may issue
additional shares of common stock, additional subordinated notes or other securities or debt convertible into common stock,
to extend maturities or fund capital expenditures, including acquisitions. If we issue additional shares of our common stock in
the future, it may have a dilutive effect on our current outstanding stockholders.

Dividend limitations

Limits on the payment of dividends and other restricted payments, as defined, are imposed under our bank credit
facility and under our senior subordinated note agreements. These limitations may, in certain circumstances, limit or prevent
the payment of dividends independent of our dividend policy.

Our stock price may be volatile and you may not be able to resell shares of our common stock at or above the price you
paid

The price of our common stock fluctuates significantly, which may result in losses for investors. The market price of
our common stock has been volatile. From January 1, 2012 to December 31, 2014, the price of our common stock reported
by the New York Stock Exchange ranged from a low of $51.83 per share to a high of $95.41 per share. We expect our stock
to continue to be subject to fluctuations as a result of a variety of factors, including factors beyond our control. These factors
include:

changes in natural gas, NGLs and oil prices;

(cid:121)
(cid:121) variations in quarterly drilling, recompletions, acquisitions and operating results;

(cid:121)

changes in governmental regulation and/or taxation;
changes in financial estimates by securities analysts;
changes in market valuations of comparable companies;
additions or departures of key personnel; or
future sales of our stock and changes in our capital structure.

We may fail to meet expectations of our stockholders or of securities analysts at some time in the future and our stock

price could decline as a result.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

We are the subject of, or party to, a number of pending or threatened legal actions and claims arising in the ordinary

course of our business. While many of these matters involve inherent uncertainty, we believe that the amount of the liability,
if any, ultimately incurred with respect to proceedings or claims will not have a material adverse effect on our consolidated
financial position as a whole or on our liquidity, capital resources or future annual results of operations. We will continue to
evaluate our litigation quarterly and will establish and adjust any litigation reserves as appropriate to reflect our assessment of
the then current status of litigation.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND

ISSUER PURCHASES OF EQUITY SECURITIES

Market for Common Stock

Our common stock is listed on the New York Stock Exchange (“NYSE”) under the symbol “RRC.” During 2014,
trading volume averaged approximately 2.0 million shares per day. The following table shows the quarterly high and low sale
prices and cash dividends declared as reported on the NYSE composite tape for the past two years.

2013:
First quarter
Second quarter
Third quarter
Fourth quarter

2014:
First quarter
Second quarter
Third quarter
Fourth quarter

High

Low

Cash
Dividends
Declared

83.15 $
81.13
85.23
85.49

90.76 $
95.41
87.37
74.64

61.25 $
71.14
74.66
72.54

79.28 $
82.63
66.98
51.83

0.04
0.04
0.04
0.04

Between January 1, 2015 and February 23, 2015, the common stock traded at prices between $44.17 and $55.74 per

share. Our senior subordinated notes are not listed on an exchange, but trade over-the-counter.

Holders of Record

On February 23, 2015, there were approximately 1,139 holders of record of our common stock.

Dividends

The payment of dividends is subject to declaration by the Board of Directors and depends on earnings, capital
expenditures and various other factors. The Board of Directors declared quarterly dividends of $0.04 per common share for
each of the four quarters of 2014, 2013 and 2012. The bank credit facility and our senior subordinated notes allow for the
payment of common and preferred dividends, with certain limitations. The determination of the amount of future dividends,
if any, to be declared and paid is at the sole discretion of our Board of Directors and will depend upon our level of earnings
and capital expenditures and other matters that the board deems relevant. Dividends on Range common stock are limited to
our legally available funds. For more information, see “Item 7. Management’s Discussion and Analysis of Financial
Condition and Results of Operations.”

Stockholder Return Performance Presentation*

The following graph is included in accordance with the SEC’s executive compensation disclosure rules. This historic

stock price performance is not necessarily indicative of future stock performance. The graph compares the change in the
cumulative total return of Range’s common stock, the Dow Jones U.S. Exploration and Production Index, and the S&P 500
Index for the five years ended December 31, 2014. The graph assumes that $100 was invested in the Company’s common
stock and each index on December 31, 2009, and that dividends were reinvested.

Range Resources Corporation
S&P 500 Index
DJ U.S. Expl. & Prod. Index

2009 2010 2011 2012 2013 2014
109
205
139

127 $ 171 $
180
136
156
118

125 $
117
112

91 $
115
117

100 $
100
100

*The performance graph and the information contained in this section is not “soliciting material,” is being “furnished”

not “filed” with the SEC and is not to be incorporated by reference into any of our filings under the Securities Act or the
Exchange Act whether made before or after the date hereof and irrespective of any general incorporation language contained
in such filing.

ITEM 6. SELECTED FINANCIAL DATA AND PROVED RESERVE DATA

The following table shows selected financial information for the five years ended December 31, 2014. Significant
producing property dispositions may affect the comparability of year-to-year financial and operating data. In the first half of
2014, we completed the Conger Exchange where we sold our Conger properties located in Glasscock and Sterling Counties,
Texas in exchange for producing properties and other assets in Virginia and $145.0 million in cash, before closing
adjustments. In the first half of 2013, we sold certain Delaware and Permian Basin properties in Southeast New Mexico and
West Texas for proceeds of $275.0 million. In the first half of 2011, we sold our Barnett Shale properties for proceeds of
$889.3 million, including certain derivative contracts assumed by the buyer and these operations are reflected as discontinued
operations. In the first half of 2010, we sold our Ohio properties for proceeds of $323.0 million. This information should be
read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,”
and our consolidated financial statements and related notes included elsewhere in this report (in thousands except per share or
per mcfe data).

Statements of Operations Data:

Natural gas, NGLs and oil sales
Total revenues and other income
Total costs and expenses
Income from continuing operations
Discontinued operations, net of taxes
Net income (loss)
Income from continuing operations per share:

–Basic
–Diluted

Net income (loss) per share:

–Basic
–Diluted

Costs per mcfe: (a)

Direct operating expense
Production and ad valorem tax expense
General and administrative expense
Interest expense
Depletion, depreciation and amortization expense

Average Daily Production:

Natural gas (mcf)
NGLs (bbls)
Oil (bbls)

Total mcfe (b)

Balance Sheets Data:
Current assets (c)
Current liabilities (d)
Natural gas and oil properties, net
Total assets
Bank debt
Subordinated notes
Stockholders’ equity (e)
Weighted average diluted shares outstanding
Cash dividends declared per common share

Statements of Cash Flows Data:

Net cash provided from operating activities
Net cash used in investing activities
Net cash provided from (used in) financing activities

Proved Reserves Data (at end of period):

Natural gas (Bcf)
NGLs (Mmbbls)
Oil and condensate (Mmbbls)

Total proved reserves (Bcfe)

2014

Year Ended December 31,
2012

2011

2013

1,911,989 $
2,711,695
1,680,810
634,382
⎯
634,382

1,715,676 $
1,862,719
1,713,140
115,722
⎯
115,722

1,351,694 $
1,457,704
1,432,648
13,002
—
13,002

1,173,266 $
1,230,642
1,152,379
42,706
15,320
58,026

3.81 $
3.79

3.81
3.79

0.35 $
0.11
0.50
0.40
1.30
2.66 $

0.71 $
0.70

0.71
0.70

0.37 $
0.13
0.85
0.51
1.44
3.30 $

0.08 $
0.08

0.08
0.08

0.42 $
0.24
0.63
0.61
1.62
3.52 $

0.26 $
0.26

0.36
0.36

0.60 $
0.15
0.80
0.66
1.80
4.01 $

2010

823,290
961,397
821,789
88,698
(327,954)
(239,256)

0.56
0.55

(1.53)
(1.52)

0.69
0.19
1.01
0.65
1.98
4.52

786,099
51,563
11,150
1,162,374

724,735
25,356
10,486
939,786

591,679
19,036
7,790
752,637

397,825
14,664
5,369
518,019

290,815
9,864
5,300
381,800

570,292 $
755,263
7,977,573
8,746,780
723,000
2,350,000
3,457,429
164,403
0.16

248,301 $
495,561
6,758,437
7,299,086
500,000
2,640,516
2,414,452
161,407
0.16

327,614 $
455,143
6,096,184
6,728,735
739,000
2,139,185
2,357,392
160,307
0.16

315,263 $
511,932
5,157,566
5,845,470
187,000
1,787,967
2,392,420
159,441
0.16

1,113,570
443,690
4,084,013
5,511,714
274,000
1,686,536
2,223,761
158,428
0.16

954,135 $

(1,245,456)
291,421

743,538 $
(983,436)
239,994

647,099 $
(1,528,558)
881,619

631,637 $
(547,981)
(86,412)

513,322
(798,858)
287,617

6,923
516
49
10,310

5,666
374
48
8,202

4,793
240
45
6,506

4,010
142
31
5,054

3,567
123
23
4,442

(a) These are costs we believe fluctuate on a unit-of-production, or per mcfe basis.
(b) Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate energy content of oil and natural gas,

which is not indicative of the relationship of oil and natural gas prices.

of derivative assets compared to $4.4 million in 2013, $137.6 million in 2012, $173.9 million in 2011 and $123.3 million in 2010.

(d) 2013 includes $26.2 million of derivative liabilities compared to $352,000 in 2010. 2014 includes $115.6 million deferred tax liability compared

to $37.9 million in 2012, $56.6 million in 2011 and $11.8 million in 2010.

(e) Stockholders’ equity includes other comprehensive income of $6.2 million in 2013 compared to $83.9 million in 2012, $156.6 million in 2011

and $67.5 million in 2010. There was no other comprehensive income in 2014.

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 business and results of operations together with

our present financial condition. Certain sections of Management’s Discussion and Analysis of Financial Condition and
Results of Operations include forward-looking statements concerning trends or events potentially affecting our business.
These statements contain words such as “anticipate,” “believe,” “estimate,” “expect,” “forecast,” “plan,” “project,” “target,”
“could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. In accordance with “safe
harbor” provisions for the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary
language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ
materially from those set forth in the forward-looking statements. Management’s Discussion and Analysis of Financial
Condition and Results of Operations should be read in conjunction with the information under Items 1 and 2. Business and
Properties, Item 1A. Risk Factors, Item 6. Selected Financial Data and Item 8. Financial Statements Data in this report.
Unless otherwise indicated, the information included herein relates to our continuing operations.

Overview of Our Business

We are an independent natural gas, natural gas liquids (“NGLs”) and oil company engaged in the exploration,

development and acquisition of natural gas and crude oil properties in the Appalachian and Midcontinent regions of the
United States. We operate in one segment and have a single company-wide management team that administers all properties
as a whole rather than by discrete operating segments. We track only basic operational data by area. We do not maintain
complete separate financial statement information by area. We measure financial performance as a single enterprise and not
on an area-by-area basis.

Our overarching business objective is to build stockholder value through consistent growth in reserves and production

on a cost-efficient basis. Our strategy to achieve our business objective is to increase reserves and production through
internally generated drilling projects occasionally coupled with complementary acquisitions. Our revenues, profitability and
future growth depend substantially on prevailing prices for natural gas, NGLs, crude oil and condensate and on our ability to
economically find, develop, acquire and produce natural gas, NGLs and oil reserves. Recently natural gas and crude oil prices
have declined significantly. A further or extended decline in commodity prices could materially and adversely affect our
business financial condition and results of operations. Prices for natural gas, NGLs and oil fluctuate widely and affect:

(cid:121)

the amount of cash flows available for capital expenditures;

(cid:121) our ability to borrow and raise additional capital;

(cid:121)

the quantity of natural gas, NGLs and oil we can economically produce; and

revenues and profitability.

We prepare our financial statements in conformity with generally accepted accounting principles, which require us to

make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities
and proved natural gas, NGLs and oil reserves. We use the successful efforts method of accounting for our natural gas, NGLs
and oil activities. Our corporate headquarters is located in Fort Worth, Texas.

Sources of Our Revenues

We derive our revenues from the sale of natural gas, NGLs, oil and condensate that is produced from our properties.

Revenues from product sales are a function of the volumes produced, prevailing market prices, product quality, gas Btu
content and transportation costs. We generally sell natural gas, NGLs and oil under two types of agreements, which are
common in our industry. Both types of agreements include transportation charges. One type of agreement is a netback
agreement, under which we sell natural gas and oil at the wellhead and collect a price, net of transportation incurred by the
purchaser. In this case, we record revenue at the price we receive from the purchaser. In the case of NGLs, we generally
receive a net price from the purchaser (which is net of processing costs) and is also recorded in revenue at the net price we
receive from the purchaser. Under the other type of agreement, we sell natural gas or oil at a specific delivery point, pay
transportation to a third party and receive proceeds from the purchaser with no transportation deduction. In that case, we
record transportation costs as transportation, gathering and compression expense. Also included in natural gas, NGLs and oil
sales revenues and derivative fair value income or loss are the effects of derivative accounting. Derivatives included in
natural gas, NGLs and oil sales reflect settlements on those derivatives that qualify for hedge accounting. Cash settlements of
derivative contracts that are not accounted for as hedges are included in derivative fair value income or loss in the
accompanying statements of operations. Effective March 1, 2013, we elected to de-designate all commodity contracts that
were previously designated as cash flow hedges and elected to discontinue hedge accounting prospectively. For more
information, see Note 10 to our consolidated financial statements. Brokered natural gas, marketing and other revenues
include revenue received from brokered gas or revenue we receive as a result of selling (and buying) natural gas that is not

related to our production, revenue from the release of transportation capacity, marketing fees we receive from third parties,
transportation revenue we receive from gathering lines we own and equity method investments.

Principal Components of Our Cost Structure

(cid:121) Direct operating. These are day-to-day costs incurred to bring hydrocarbons out of the ground along with the
daily costs incurred to maintain our producing properties. Such costs include compensation of our field
employees, maintenance, repairs and workover expenses related to our natural gas and oil properties. The
majority of these costs are expected to remain a function of supply and demand. Direct operating expenses also
include stock-based compensation expense (non-cash) associated with the amortization of restricted stock grants
as part of the compensation of field employees.

(cid:121) Transportation, gathering and compression. Under some of our sales arrangements, we sell natural gas and
NGLs at a specific delivery point, pay transportation, gathering and compression costs to a third party and
receive proceeds from the purchaser with no deduction. Transportation, gathering and compression expense
represents costs paid by Range to third parties under these arrangements.

(cid:121) Production and ad valorem taxes. Production taxes are paid on produced natural gas and oil based on a

percentage of sales revenue (excluding derivatives) or at fixed rates established by the applicable federal, state or
local taxing authorities. Ad valorem taxes are generally based on reserve values at the end of each year. The
Pennsylvania impact fee on unconventional natural gas and oil production, which includes the Marcellus Shale,
is also included in this category.

(cid:121) Brokered natural gas and marketing. These expenses are gas purchases for brokered gas natural gas that we buy
and sell that is not related to our production and overhead, including payroll and benefits for our marketing staff.
Brokered natural gas and marketing also includes stock-based compensation expense (non-cash) associated with
the amortization of restricted stock, stock appreciation rights (“SARs”) and performance share units (“PSUs”)
granted as part of our marketing staff compensation.

(cid:121) Exploration. These are geological and geophysical costs, such as payroll and benefits for the geological and

geophysical staff, seismic costs, delay rentals and the costs of unsuccessful exploratory dry holes. Exploration
expense also includes stock-based compensation expense (non-cash) associated with the amortization of grants of
SARs, PSUs and restricted stock as part of the compensation of our exploration staff.

(cid:121) Abandonment and impairment of unproved properties. This category includes unproved property impairment and

expenses associated with lease expirations.

(cid:121) General and administrative. These costs include overhead, such as payroll and benefits for our corporate staff,
costs of maintaining our headquarters, costs of managing our production and development operations, franchise
taxes, audit and other professional fees, legal compliance and legal settlements. Included in this category are
overhead expense reimbursements we receive from working interest owners of properties, for which we serve as
the operator. These reimbursements are received during both the drilling and operational stages of a property’s
life. General and administrative expense also includes stock-based compensation expense (non-cash) associated
with the amortization of restricted stock, SARs and PSUs granted as part of the compensation of our corporate
staff and our directors.

(cid:121) Deferred compensation plan. These costs relate to the increase or decrease in the value of the liability associated

with our deferred compensation plan. Our deferred compensation plan gives directors, officers and key
employees the ability to defer all or a portion of their salaries and bonuses and invest in our common stock or
make other investments at the individual’s discretion. The assets of this plan are held in a grantor trust, are
funded on the grant date and are available to satisfy the claims of our creditors in the event of bankruptcy or
insolvency.

(cid:121)

Interest expense. We typically finance a portion of our cash requirements with borrowings under our bank credit
facility and with longer-term debt securities. Included here are also administrative fees associated with our bank
credit facility and the amortization of deferred financing costs. As a result, we incur interest expense that is
affected by both fluctuations in interest rates and our financing decisions. We currently have no capitalized
interest.

(cid:121) Depreciation, depletion and amortization. This includes the systematic expensing of the capitalized costs
incurred to acquire, explore and develop natural gas, NGLs and oil. As a successful efforts company, we
capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts,
and apportion these costs to each unit of production through depreciation, depletion and amortization expense.
This expense also includes the systematic, monthly accretion of the future abandonment costs of tangible assets
such as wells, service assets, pipelines, and other facilities.

(cid:121)

Income taxes. We are subject to state and federal income taxes but are currently not in a cash taxpaying position
for federal income taxes, primarily due to the current deductibility and/or accelerated amortization of intangible
drilling costs (“IDC”). At this time, we generally do not pay significant state income taxes due to our state net
operating loss carryovers and our ability to follow the federal treatment of deducting IDC in most of the states in
which we operate. Currently, substantially all of our federal taxes are deferred and we anticipate using all of our
federal net operating loss carryforwards. As of December 31, 2014, we have an $8.8 million valuation allowance
on the portion of our Oklahoma net loss carryforwards which we do not believe are realizable. For more
information, see “Item 1A. Risk Factors-Certain federal income tax deductions currently available with respect
to natural gas and oil exploration and development may be eliminated, and additional state taxes on natural gas
extraction may be imposed, as a result of future legislation.”

Management’s Discussion and Analysis of Results of Operations
Overview of 2014 Results

During 2014, we achieved the following financial and operating results:

(cid:121)

achieved 24% annual production growth;
achieved 26% annual proved reserve growth;
(cid:121)
(cid:121) drilled 239 net wells with a 99% success rate;

(cid:121)

continued expansion of our activities in the Marcellus Shale by growing production, proving up acreage and
acquiring additional unproved acreage;
reduced direct operating expenses per mcfe 5% from the same period of 2013;
reduced our DD&A rate 10% from the same period of 2013;

continued to focus on financial flexibility by redeeming all $300.0 million of 8% senior subordinated notes due
in 2019 and achieved a debt per mcfe of proved reserves of $0.30 compared to $0.38 in 2013;
issued 4.56 million shares of common stock where we received $396.6 million in net proceeds;
entered into additional commodity-based derivative contracts for 2015 and 2016;

received $151.7 million of proceeds from the exchange of our Conger properties in West Texas for producing
properties and other assets in Virginia and $28.8 million of proceeds from the sale of other miscellaneous non-
core oil and gas assets;
realized $954.1 million of cash flow from operating activities;
ended the year with stockholders’ equity of $3.5 billion; and
entered into additional firm transportation commitments and sales agreements.

Operationally, our 2014 performance reflects another year of successfully executing our strategy of growth through

drilling. Our success enabled us to increase proved reserves by approximately 2.1 Tcfe, which is more than 4 times our 2014
production. As evidenced by history and our current industry environment, the prices at which we sell our production are
volatile and we have no control over them. Therefore, to improve our profitability, we focus our efforts on improving
operating efficiency. As reservoirs are depleted and production rates decline, per unit production costs will generally
increase. To lessen this effect, we concentrate our production in core areas where we can achieve economies of scale to help
manage our operating costs.

Acquisitions

During 2014, we spent $226.5 million to acquire unproved acreage compared to $137.5 million in 2013 and $188.8
million in 2012. We continue selective acreage leasing and lease renewals to add to our acreage positions primarily in the
Marcellus Shale play in Pennsylvania. See additional information below regarding our exchange during 2014 of properties in
West Texas for properties, cash and other assets in Virginia.

Divestitures

Texas. In December 2013, we announced our plan to offer for sale certain of our properties in the Permian Basin.
These properties included approximately 73,000 net acres, almost all of which are held by production in Glasscock and
Sterling Counties, Texas. In April 2014, we entered into an exchange agreement with EQT Corporation and certain of its
affiliates (collectively, “EQT”) in which we sold these assets in exchange for producing properties, (including approximately

138,000 net acres) and other EQT assets in Virginia and $145.0 million in cash, before closing adjustments. We closed the
exchange transaction in June 2014 and we recognized a pre-tax gain of $282.7 million related to this exchange. In fourth
quarter 2014, we also sold miscellaneous proved properties in East Texas for proceeds of $5.0 million and recognized a gain
of $467,000.

In December 2012, we announced our plan to offer for sale certain of our Permian and Delaware Basin properties in

West Texas and Southeast New Mexico. In February 2013, we announced we had signed a definitive agreement to sell these
assets for a price of $275.0 million. We closed this disposition in April 2013 and we recorded a pre-tax gain of $79.1 million.
During 2013, we sold miscellaneous unproved and proved property for proceeds of $33.5 million and we recorded a gain of
$8.8 million. In March 2012, we sold 75% of a prospect in East Texas, which included unproved properties and a suspended
exploratory well to a third party for proceeds of $8.6 million and recorded a pre-tax loss of $10.9 million.

In January 2015, we signed a purchase and sale agreement to sell our remaining West Texas properties for cash

proceeds of $10.5 million. The transaction closed in February 2015 with no gain or loss recognized.

Oklahoma. In December 2014, we sold certain oil and gas properties in Western Oklahoma for proceeds of $2.6
million with no gain or loss recognized. In November 2012, we sold certain oil and gas properties in Southern Oklahoma to a
third party for gross proceeds of $135.0 million which resulted in a pretax gain of $55.2 million in the year ended
December 31, 2012.

Pennsylvania. In December 2014, we sold miscellaneous unproved properties for proceeds of $18.8 million and we

recognized a gain of $617,000. In September 2013, we sold our equity method investment in a drilling company for proceeds
of $7.0 million and recognized a gain of $4.4 million. In June 2012, we sold a suspended exploratory well in the Marcellus
Shale for proceeds of $2.5 million and recorded a pre-tax loss of $2.5 million on this transaction.

2015 Outlook

For 2015, the Board of Directors approved an $870.0 million capital budget for natural gas, NGLs, crude oil and
condensate related activities, excluding proved property acquisitions, for which we do not budget. As has been our historical
practice, we will periodically review our capital expenditures throughout the year and may adjust the budget based on
commodity prices, drilling success and other factors. To the extent, our 2015 capital requirements exceed our internally
generated cash flow, proceeds from asset sales, drawing on our committed capacity under our bank credit facility, debt or
equity may be issued to fund these requirements. The prices we receive for our natural gas, NGLs and oil production are
largely based on current market prices, which are beyond our control. The price risk on a portion of our forecasted natural
gas, NGLs and oil production for 2015 is mitigated using commodity derivative contracts and we intend to continue to enter
into these transactions. Recently, natural gas and crude oil prices have dropped significantly. In periods of falling prices, the
demand for drilling rigs, oilfield supplies and drill pipe is expected to decline but such declines tend to lag behind the
declines in natural gas and crude oil prices. In response to the weakened natural gas and crude oil market, we have lowered
our 2015 capital budget, which was originally announced in December 2014 at $1.3 billion to $870 million and we have
announced a plan to close our Oklahoma City divisional office by mid-2015 which will reduce general and administrative
expenses, excluding one-time termination costs. These properties will be operated out of our Fort Worth office.

Market Conditions

Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash
flows. Prices for commodities, such as hydrocarbons, are inherently volatile. Recently, natural gas and crude oil prices have
dropped significantly with the average NYMEX monthly settlement price for natural gas falling to $2.87 per mcf for
February 2015 and crude oil falling to $47.33 per barrel in January 2015. The following table lists average NYMEX prices
for natural gas and oil and the Mont Belvieu NGL composite price for the years ended December 31, 2014, 2013 and 2012.

Average NYMEX prices (a)
Natural gas (per mcf)
Oil (per bbl)

Mont Belvieu NGL composite (per gallon)

(a) Based on average of bid week prompt month prices.

Year Ended December 31,
2013

2012

2014

$
$
$

4.37 $
92.64 $
0.76 $

3.67 $
98.20 $
0.78 $

2.82
93.36
0.89

Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations

Our revenues vary from year to year as a result of changes in realized commodity prices and production volumes. For
more information, see “Source of our Revenues” above. In 2014, natural gas, NGLs and oil sales increased 11% from 2013
with a 24% increase in production partially offset by a 10% decrease in realized prices. In 2013, natural gas, NGLs and oil
sales increased 27% from 2012 with a 25% increase in production and a 2% increase in realized prices. The following table
illustrates the primary components of natural gas, NGLs, crude oil and condensate sales for each of the last three years (in
thousands):

2014

2013

2012

Natural gas, NGLs and Oil sales

Gas wellhead
Gas hedges realized
Total gas revenue
Total NGLs revenue
Oil and condensate wellhead

Oil hedges realized

Total oil and condensate revenue
Combined wellhead
Combined hedges

Total natural gas, NGLs and oil sales

$
$
$

$
$

1,140,989 $
4,686
1,145,675 $
444,152 $
316,625 $
5,537
322,162 $
1,901,766 $
10,223
1,911,989 $

954,673 $
110,948
1,065,621 $
315,272 $
329,182 $
5,601
334,783 $

612,354
238,259
850,613
265,072
237,963
(1,954)
236,009
1,599,127 $ 1,115,389
236,305
1,715,676 $ 1,351,694

116,549

Our production continues to grow through drilling success as we place new wells on production and through additions
from acquisitions partially offset by the natural decline of our natural gas and oil reserves through production and asset sales.
For 2014, our production volumes increased 30% in our Appalachian region and decreased 18% in our Midcontinent region
when compared to 2013. For 2013, our production volumes increased 31% in our Appalachian region and decreased 4% in
our Midcontinent region when compared to 2012. Our production for each of the last three years is set forth in the following
table:

Production (a)

Natural gas (mcf)
NGLs (bbls)
Crude oil and condensate (bbls)

Total (mcfe) (b)
Average daily production (a)

Natural gas (mcf)
NGLs (bbls)
Crude oil and condensate (bbls)

Total (mcfe) (b)

2014

2013

2012

286,926,099 264,528,254 216,554,689
6,967,114
18,820,526
2,851,312
4,069,568
424,266,663 343,022,006 275,465,245

9,254,801
3,827,491

786,099
51,563
11,150
1,162,374

724,735
25,356
10,486
939,786

591,679
19,036
7,790
752,637

(a) Represents volumes sold regardless of when produced.
(b) Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil

and natural gas, which is not indicative of the relationship of oil and natural gas prices.

Our average realized price (including all derivative settlements and third-party transportation costs) received during

2014 was $3.64 per mcfe compared to $4.16 per mcfe in 2013 and $4.35 per mcfe in 2012. Because we record transportation
costs on two separate bases, as required by GAAP, we believe computed final realized prices should include the impact of
transportation, gathering and compression expense. Our average realized price (including all derivative settlements and third-
party transportation costs) calculation also includes all cash settlements for derivatives, whether or not they qualify for hedge
accounting. Average sales prices (wellhead) do not include any derivative settlements or third party transportation costs
which are reported in transportation, gathering and compression expense on the accompanying consolidated statements of
income. Average sales prices (wellhead) do include transportation costs where we receive net proceeds. Average realized
price calculations for each of the last three years are shown below:

Average Prices
Average sales prices (wellhead):
Natural gas (per mcf)
NGLs (per bbl)
Crude oil (per bbl)

Total (per mcfe) (a)

Average realized prices (including derivative settlements that

qualified for hedge accounting):

Natural gas (per mcf)
NGLs (per bbl)
Crude oil (per bbl)

Total (per mcfe) (a)

Average realized prices (including all derivative settlements):
$

Natural gas (per mcf)
NGLs (per bbl)
Crude oil (per bbl)

Total (per mcfe) (a)

Average realized prices (including all derivative settlements

and third party transportation costs paid by Range):

Natural gas (per mcf)
NGLs (per bbl)
Crude oil (per bbl)

Total (per mcfe) (a)

2014

2013

2012

3.98 $
23.60
77.80
4.48

3.99 $
23.60
79.16
4.51

3.79 $
24.31
79.75
4.41

2.80 $
22.04
79.75
3.64

3.61 $
34.07
86.00
4.66

4.03 $
34.07
87.47
5.00

4.00 $
32.71
84.70
4.91

3.08 $
31.29
84.70
4.16

2.83
38.05
83.46
4.05

3.93
38.05
82.77
4.91

3.95
42.60
83.64
5.05

3.11
41.03
83.64
4.35

(a) Oil and NGLs are converted at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural

gas, which is not indicative of the relationship of oil and natural gas prices.

Derivative fair value income (loss) was income of $383.5 million in 2014 compared to a loss of $61.8 million in 2013

and income of $41.4 million in 2012. Through February 28, 2013, some of our derivatives did not qualify for hedge
accounting and were accounted for using the mark-to-market accounting method whereby all realized and unrealized gains or
losses related to these contracts were included in derivative fair value income or loss. Effective March 1, 2013, we
prospectively discontinued hedge accounting for those contracts that qualified for hedge accounting. Since March 1, 2013, all
of our derivatives are accounted for using the mark-to-market accounting method. Mark-to-market accounting treatment
creates volatility in our revenues as unrealized gains and losses from derivatives are included in total revenues. As
commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our
derivatives. Gains on our derivatives generally indicate lower wellhead revenues in the future while losses indicate higher
future wellhead revenues. At December 31, 2014, all of our derivative contracts were recorded at their fair value, which was
a pre-tax asset of $403.4 million, an increase of $416.0 million from the $12.6 million net derivative liability recorded as of
December 31, 2013. We have entered into basis swap agreements to limit volatility caused by changing differentials between
NYMEX and regional prices received. These basis swaps are marked to market and were recognized as a pre-tax gain of $1.7
million as of December 31, 2014.

Brokered natural gas, marketing and other revenue was $130.5 million in 2014 compared to $116.6 million in 2013
and $15.4 million in 2012. The 2014 period includes $123.1 million of revenue from marketing and the sale of brokered gas
and includes revenue of $15.8 million from the release of transportation capacity where we have taken firm transportation
capacity ahead of production volumes. These revenues increased from 2013 due to an increase in brokered natural gas
transactions. The 2013 period includes revenue from marketing and sale of brokered gas of $118.3 million. These revenues
increased significantly from 2012 due to an increase in the purchase (and sale) of natural gas which was used to blend our
rich residue gas from the Southwest Marcellus Shale of $62.8 million and an increase in brokered natural gas transactions.
The 2012 period includes revenue from marketing and the sale of brokered gas of $15.1 million.

Costs and Expenses

We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per mcfe, basis. The

following presents information about certain of our expenses on a per mcfe basis for each of the last three years:

Direct operating expense
Production and ad valorem tax expense
General and administrative expense
Interest expense
Depletion, depreciation and amortization

Year Ended December 31,

2014

2013

Change

%
Change

2013

2012

Change

%
Change

0.35 $
0.11
0.50
0.40

0.37 $
0.13
0.85
0.51

(0.02)
(0.02)
(0.35)
(0.11)

(5%) $
(15%)
(41%)
(22%)

0.37 $
0.13
0.85
0.51

0.42 $
0.24
0.63
0.61

(0.05)
(0.11)
0.22
(0.10)

(12%)
(46%)
35%
(16%)

expense

1.30

1.44

(0.14)

(10

1.44

1.62

(0.18)

(11%)

Direct operating expense was $150.5 million in 2014 compared to $128.1 million in 2013 and $115.9 million in 2012.

We experience increases in operating expenses as we add new wells and manage existing properties. Direct operating
expenses include normally recurring expenses to operate and produce our wells, non-recurring workovers and repairs. On an
absolute basis, our direct operating expenses for 2014 increased 17% from the same period of the prior year due to an
increase in producing wells, higher workovers, water hauling and personnel costs. On an absolute basis, our direct operating
expense for 2013 increased 11% from the same period of the prior year with an increase in producing wells, higher workover
costs, utilities, personnel costs, well insurance, water hauling and nitrogen injection costs, somewhat offset by the sale of
certain non-core assets at the beginning of second quarter 2013. We incurred $11.5 million of workover costs in 2014
compared to $8.6 million of workover costs in 2013 and $4.8 million in 2012.

On a per mcfe basis, operating expense for 2014 decreased $0.02 or 5% from the same period of 2013, with the

decrease consisting of lower well services and nitrogen injection costs. On a per mcfe basis, operating expense for 2013
decreased $0.05 or 12% from the same period of 2012, with the decrease consisting of lower costs for personnel and well
services. We expect to continue to experience lower costs per mcfe as we increase production from our Marcellus Shale wells
due to their lower operating cost relative to our other operating areas somewhat offset by higher operating costs on our
liquids-rich wells. Stock-based compensation expense represents the amortization of restricted stock as part of the
compensation of field employees. The following table summarizes direct operating expenses per mcfe for each of the last
three years:

Year Ended December 31,

2014

2013

Change

%
Change

2013

2012

Lease operating expense
Workovers
Stock-based compensation (non-cash)

Total direct operating expense

0.31 $
0.03
0.01
0.35 $

0.34 $
0.02
0.01
0.37 $

(0.03)
0.01
⎯
(0.02)

(9%) $
50%
⎯
(5%) $

0.34 $
0.02
0.01
0.37 $

Change
(0.05)
⎯
⎯
(0.05)

0.39 $
0.02
0.01
0.42 $

%
Change

(13%)
⎯
⎯
(12%)

Production and ad valorem taxes are paid based on market prices, not hedged prices. This expense category also

includes the Pennsylvania impact fee. In February 2012, the Commonwealth of Pennsylvania enacted an “impact fee” on
unconventional natural gas and oil production which includes the Marcellus Shale. The impact fee is based upon the year a
well is drilled and varies, like a severance tax, based upon natural gas prices. The year ended December 31, 2014 includes
$27.3 million ($0.06 per mcfe) impact fee compared to $28.0 million ($0.08 per mcfe) impact fee in the year ended
December 31, 2013. The year ended December 31, 2012 includes a $25.2 million ($0.09 per mcfe) retroactive impact fee
which covered all wells drilled prior to 2012 and was paid in September 2012. Also included in the year ended December 31,
2012 is a $24.0 million ($0.09 per mcfe) impact fee for wells drilled prior to 2012 and wells drilled in 2012 which was paid
in April 2013. Production and ad valorem taxes (excluding the impact fee) were $17.2 million in both 2014 and 2013 and
$17.9 million in 2012. On a per mcfe basis, production and ad valorem taxes (excluding the impact fee) decreased to $0.04 in
2014 compared to $0.05 in 2013 due to an increase in production volumes not subject to production or ad valorem taxes. On
a per mcfe basis, production and ad valorem taxes decreased to $0.05 in 2013 from $0.06 in 2012 due to an increase in
production volumes not subject to production or ad valorem taxes.

General and administrative expense was $213.4 million for 2014 compared to $291.2 million for 2013 and $173.8

million in 2012. The 2014 decrease of $77.8 million when compared to 2013 is primarily due to lower costs for lawsuit
settlements of $88.9 million partially offset by $5.9 million of fines for water impoundment leaks and other water sourcing
penalties in Pennsylvania and higher salaries and benefits for our employees. The 2013 increase of $117.4 million when
compared to 2012 is primarily due to a legal settlement related to an Oklahoma lawsuit of $87.5 million, higher salary and
benefit expenses of $9.5 million, an increase in stock-based compensation of $11.2 million which includes additional expense
of $10.0 million related to the acceleration of stock-based compensation for our former executive chairman who became a
non-employee director on January 1, 2014, and higher legal, office and other expenses. Our number of general and
administrative employees increased 11% during 2014. Our personnel costs continue to increase as we invest in our technical
teams and other staffing to support our expansion into the Marcellus Shale in Appalachia. Stock-based compensation expense
represents the amortization of PSUs, restricted stock grants and SARs granted to our employees and directors as part of their
compensation. The following table summarizes general and administrative expenses per mcfe for each of the last three years:

General and administrative
Oklahoma legal settlement
Stock-based compensation (non-cash)
Total general and administrative

Year Ended December 31,

2014

2013

Change

%
Change

2013

2012

Change

%
Change

0.37 $
⎯
0.13

0.43 $ (0.06)
(0.26)
0.26
(0.03)
0.16

(14%) $
(100%)
(19%)

0.43 $
0.26
0.16

0.47 $
—
0.16

(0.04)
0.26
—

(9%)
—
—

expense

0.50 $

0.85 $ (0.35)

(41%) $

0.85 $

0.63 $

0.22

35%

Interest expense was $169.0 million for 2014 compared to $176.6 million for 2013 and $168.8 million in 2012. The

following table presents information about interest expense per mcfe for each of the years in the three-year period ended
December 31, 2014:

Bank credit facility
Subordinated notes
Amortization of deferred financing costs and other

Total interest expense per mcfe

0.04 $
0.34
0.02
0.40 $

0.04 $
0.44
0.03
0.51 $

0.04
0.54
0.03
0.61

Year Ended December 31,
2013

2012

2014

The decrease in interest expense for 2014 from the same period of 2013 was primarily due to lower interest rates. The

increase in interest expense for 2013 from the same period of 2012 was primarily due to an increase in outstanding debt
balances partially offset by lower interest rates. In June 2014, we redeemed all $300.0 million of our outstanding 8.0% senior
subordinated notes due 2019. In March 2013, we issued $750.0 million of 5.0% senior subordinated notes due 2023. We used
the proceeds for general corporate purposes and to retire outstanding balances on our bank debt which carries a lower interest
rate. In May 2013, we redeemed all $250.0 million of our 7.25% senior subordinated notes due 2018. In March 2012, we
issued $600.0 million of 5.0% senior subordinated notes due 2022. We used the proceeds for general corporate purposes and
to retire outstanding balances on our bank debt. The 2013 and 2012 note issuances were undertaken to better match the
maturities of our debt with the life of our properties and to give us greater liquidity for the near term. Average debt
outstanding on the bank credit facility for 2014 was $646.6 million compared to $441.0 million for 2013 and $308.0 million
for 2012 and the weighted average interest rate on the bank credit facility was 2.0% for 2014 compared to 2.0% in 2013 and
2.2% in 2012.

Depletion, depreciation and amortization (“DD&A”) was $551.0 million in 2014 compared to $492.4 million in 2013
and $445.2 million in 2012. The increase in 2014 when compared to 2013 is due to a 24% increase in production somewhat
offset by a 10% decrease in depletion rates. The increase in 2013 when compared to 2012 is due to a 25% increase in
production somewhat offset by a 11% decrease in depletion rates.

On a per mcfe basis, DD&A decreased to $1.30 in 2014 compared to $1.44 in 2013 and $1.62 in 2012. Depletion

expense, the largest component of DD&A, was $1.23 per mcfe in 2014 compared to $1.37 per mcfe in 2013 and $1.54 per
mcfe in 2012. We have historically adjusted our depletion rates in the fourth quarter of each year based on the year-end
reserve report and other times during the year when circumstances indicate there has been a significant change in reserves or
costs. We currently expect our DD&A rate to be approximately $1.25 per mcfe in 2015, based on our current production
estimates. In areas where we are actively drilling, such as the Marcellus Shale area, our fourth quarter adjusted 2014
depletion rates were lower than the fourth quarter 2013 and 2012 depletion rates. Depletion rates in new plays tend to be
higher in the beginning as increased initial outlays are amortized over proved reserves based on early stages of evaluations.

The decrease in DD&A per mcfe in 2014 when compared to 2013 and 2012 is due to the mix of our production from our
properties with lower depletion rates. The following table summarizes DD&A expenses per mcfe for each of the last three
years:

Year Ended December 31,

Depletion and amortization
Depreciation
Accretion and other

Total DD&A expenses

1.23 $
0.03
0.04
1.30 $

2014

2013

%
Change

2013

2012

Change
(0.14)
(0.01)
0.01
(0.14)

1.37 $
0.04
0.03
1.44 $

(10%) $
(25%)
33%
(10%) $

1.37 $
0.04
0.03
1.44 $

Change
(0.17)
(0.01)
—
(0.18)

1.54 $
0.05
0.03
1.62 $

%
Change

(11%)
(20%)
—
(11%)

Transportation, gathering and compression expense was $325.3 million in 2014 compared to $256.2 million in 2013

and $192.4 million in 2012. These third party costs are higher in each year due to our production growth in the Marcellus
Shale where we have third party gathering, compression and transportation agreements. The year ended December 31, 2014
also includes the impact of an ethane transportation contract which commenced initial deliveries in late 2013. We have
included these costs in the calculation of average realized prices (including all derivative settlements and third party
transportation expenses paid by Range).

Other Operating Expenses

Our total operating expenses also include other expenses that generally do not trend with production. These expenses
include stock-based compensation, brokered natural gas and marketing, exploration expense, abandonment and impairment
of unproved properties, termination costs, deferred compensation plan expenses, loss on early extinguishment of debt and
impairment of proved properties.

The following table details stock-based compensation that is allocated to functional expense categories for each of the

years in the three-year period ended December 31, 2014 (in thousands):

Direct operating expense
Brokered natural gas and marketing expense
Exploration expense
General and administrative expense
Termination costs

Total stock-based compensation

2014

2013

2012

4,208 $
3,523
4,569
55,382
2,999
70,681 $

2,755 $
1,852
4,025
55,737
—

64,369 $

2,415
1,765
4,049
44,541
—
52,770

Stock-based compensation includes the amortization of restricted stock grants, SARs and PSUs grants. This

amortization increased from 2012 to 2013 primarily due to an additional expense of $10.0 million related to the acceleration
of stock-based compensation for our former executive chairman who became a non-employee director on January 1, 2014.
The year ended December 31, 2014 also includes $6.7 million of awards granted to our former executive chairman for his
service in 2013 while he was a Range officer, which were fully vested upon grant.

Brokered natural gas and marketing was $130.0 million in 2014 compared to $131.8 million in 2013 and $20.4
million in 2012. The decrease in 2014 from 2013 is due to a decrease in the purchase of natural gas used to blend our residue
gas in Pennsylvania offset by higher broker gas transactions, higher marketing staff personnel costs, an increase in
transportation capacity expenses where we have taken firm transportation capacity ahead of production volumes and higher
expenses related to company owned gathering lines. The increase in 2013 from 2012 is due to a $69.8 million increase in the
purchase of natural gas which was used to blend our residue gas from the Southwest Marcellus Shale, an increase in our
marketing staff personnel expenses and an increase in brokered gas transactions. Stock-based compensation included here
represents the amortization of restricted stock, SARs and PSUs as part of the compensation of our marketing staff.

Exploration expense was $63.5 million in 2014 compared to $64.4 million in 2013 and $69.8 million in 2012.
Exploration expense was lower in 2014 when compared to 2013 due to lower seismic costs somewhat offset by higher dry
hole costs and delay rentals. For the year ended December 31, 2014, delay rentals and other includes expense of $7.0 million
related to a suspended exploratory well which was impaired because we were no longer making sufficient progress in gaining
access to transportation facilities to allow the continued capitalization of such costs. Exploration expense was lower in 2013
when compared to 2012 due to lower seismic and delay rental costs partially offset by higher dry hole costs. Stock-based
compensation represents the amortization of restricted stock, PSUs and SARs as part of the compensation of our exploration
staff. The following table details our exploration related expenses for each of the years in the three-year period ended
December 31, 2014 (in thousands):

Year Ended December 31,

Seismic
Delay rentals and other
Personnel expense
Stock-based compensation expense
Exploratory dry hole expense

Total exploration expense

%
Change

2014

2013

Change
$ 19,504 $ 26,872 $ (7,368)
2,519
15,488 12,969
(23)
14,821 14,844
544
4,569 4,025
3,467
9,166 5,699
(861)
$ 63,548 $ 64,409 $

2012

2013

Change
(27%) $ 26,872 $ 33,462 $ (6,590)
19% 12,969 18,286 (5,317)
14,844 13,168 1,676
—
14%
(24)
61%
842 4,857
(1%) $ 64,409 $ 69,807 $ (5,398)

4,025
5,699

4,049

%
Change

(20%)
(29%)
13%
(1%)
577%
(8%)

Abandonment and impairment of unproved properties was $47.1 million in 2014 compared to $51.9 million in 2013
and $125.3 million in 2012. We assess individually significant unproved properties for impairment on a quarterly basis and
recognize a loss where circumstances indicate impairment in value. In determining whether a significant unproved property is
impaired we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable
activity on the property being evaluated and/or adjacent properties, our geologists’ evaluation of the property and the
remaining months in the lease term for the property. Impairment of individually insignificant unproved properties is assessed
and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling
success. As we continue to review our acreage positions and high grade our drilling inventory based on the current price
environment, additional leasehold impairments and abandonments will likely be recorded. In second quarter 2013, we
impaired individually significant unproved properties in East Texas for $5.4 million. In third quarter 2012, we impaired
individually significant unproved properties in the Barnett Shale of North Texas (the last of our unproved properties in the
area) for $19.6 million because we chose to not develop the acreage. Also, due to an unproved property transaction in second
quarter 2012, we impaired individually significant unproved properties in Pennsylvania for $23.1 million because we will not
drill in these areas.

Termination costs in 2014 includes an accrual for estimated severance costs of $5.4 million related to the closing of

our Oklahoma City office which was announced in first quarter 2015 and $3.0 million of non-cash stock compensation
expense related to the accelerated vesting of SARs, restricted stock and PSUs as part of the severance agreement for these
Oklahoma City personnel.

Deferred compensation plan expense was income of $74.6 million in 2014 compared to expense of $55.3 million in

2013 and expense of $7.2 million in 2012. Our stock price decreased to $53.45 at December 31, 2014 compared to $84.31 at
December 31, 2013. Our stock price increased to $84.31 at December 31, 2013 compared to $62.83 at December 31, 2012.
This non-cash item relates to the increase or decrease in value of the liability associated with our common stock that is vested
and held in our deferred compensation plan. The deferred compensation liability is adjusted to fair value by a charge or a
credit to deferred compensation plan expense. Common shares are placed in the deferred compensation plan when granted.

Loss on early extinguishment of debt was $24.6 million in 2014 compared to $12.3 million in 2013 and $11.1 million

in 2012. In June 2014, we redeemed all of our $300.0 million aggregate principal amounts of our 8.0% senior subordinated
notes due 2019 at a price equal to 104.0% of par and we recorded a loss on extinguishment of debt of $24.6 million, which
includes a call premium and expensing of related deferred financing costs on the repurchased debt. In May 2013, we
redeemed all of our $250.0 million aggregate principal amount of our 7.25% senior subordinated notes due 2018 at 103.625%
of par and we recorded a loss on extinguishment of debt of $12.3 million, which includes a call premium, and the expensing
of related deferred financing costs on the repurchased debt. In December 2012, we redeemed our 7.5% senior subordinated
notes due 2017 at a redemption price equal to 103.75% of par. We recorded a loss on extinguishment of debt of $11.1 million
including call premium costs of $9.4 million and expensing of related deferred financing costs on the redeemed debt.

Impairment of proved properties increased to $28.0 million in 2014 compared to $7.8 million in 2013 and $35.6
million in 2012. The year ended December 31, 2014 includes $5.5 million related to our properties in Mississippi, $18.5
million related to certain West Texas properties and $4.0 million to fully impair our remaining North Texas oil and gas
properties. The year ended December 31, 2013 includes $7.0 million impairment related to certain South Texas wells. The
year ended December 31, 2013 also includes $741,000 impairment expense related to surface acreage in North Texas. The

year ended 2012 includes $31.1 million impairment related to our properties in Mississippi, $3.2 million related to our
remaining North Texas assets and $1.3 million related to surface acreage, also in North Texas. Our analysis of these
properties determined that undiscounted cash flows were less than their carrying value. We compared the carrying value to
estimated fair value and recognized an impairment charge. These assets were evaluated for impairment due to declining
reserves, natural gas prices and changes in projected capital spending and, in the case of certain of our North Texas and West
Texas properties, the possibility of a sale. In January 2015, we signed a purchase and sale agreement to sell these West Texas
properties for cash proceeds of $10.5 million, with no gain or loss to be recognized.

Income tax expense was $396.5 million in 2014 compared to $33.9 million in 2013 and $12.1 million in 2012. The
2014 increase in income taxes reflects a 589% increase in income from operations when compared to the same period of
2013. The 2013 increase in income taxes reflects a 497% increase in income from operations when compared to the same
period of 2012. The effective tax rate was 38.5% in 2014 compared to 22.6% in 2013 and 48.1% in 2012. For the year ended
December 31, 2014, the current income tax expense of $1,000 is related to state income taxes. For the year ended December
31, 2013, the current income tax benefit of $143,000 is related to a refund of state income taxes. For the year ended
December 31, 2012 the current income tax benefit of $1.8 million is related to state income taxes and includes favorable
adjustments to reflect state income tax returns as filed. The 2014, 2013 and 2012 effective tax rate was different than the
statutory tax rate due to state income taxes and our tax rates were also affected in 2014 by a decrease in our valuation
allowance related to the deferred tax asset for future deferred compensation plan distributions of senior executives to the
extent their estimated future compensation (including these distributions) would exceed the $1.0 million deductible limit
provided under Section 162(m) of the Internal Revenue Code of 1986, as amended, compared to increases in the valuation
allowance in both 2013 and 2012. Our effective tax rates are also impacted by adjustments to our state apportionment rates
which was a benefit of $2.0 million in 2014 compared to a benefit of $21.2 million in 2013 and a benefit of $736,000 in
2012. For 2012, our effective tax rate was impacted by a $2.0 million valuation allowance related to our Pennsylvania state
net operating loss carryforwards. This valuation allowance was increased to $3.0 million in 2013. In 2014, we reversed our
$3.0 million Pennsylvania state net operating loss carryforward and recorded a $8.8 million valuation allowance related to
our Oklahoma net operating loss carry forward. We estimate our ability to utilize our federal and state loss carryforwards by
forecasting the future reversal of our temporary differences and estimating future federal and state taxable income as
compared to our loss carryforward expiration dates. Uncertainties such as future commodity prices can affect our calculations
and the expiration of loss carryforwards prior to utilization can result in recording a partial as opposed to a full valuation
allowance. We expect our effective tax rate to be approximately 39% for 2015, before any discrete tax items.

Management’s Discussion and Analysis of Financial Condition, Cash Flows, Capital Resources and Liquidity
Cash Flows

Cash flows from operations are primarily affected by production volumes and commodity prices, net of the effects of

settlements of our derivatives. Our cash flows from operations also are impacted by changes in working capital. We generally
maintain low cash and cash equivalent balances because we use available funds to reduce our bank debt. Short-term liquidity
needs are satisfied by borrowings under our bank credit facility. Because of this, and since our principal source of operating
cash flows (proved reserves to be produced in the following year) cannot be reported as working capital, we often have low
or negative working capital. We sell a large portion of our production at the wellhead under floating market contracts. From
time to time, we enter into various derivative contracts to provide an economic hedge of our exposure to commodity price
risk associated with anticipated future natural gas, NGLs and oil production. The production we hedge has and will continue
to vary from year to year depending on, among other things, our expectation of future commodity prices. Since year-end
2014, we have entered into additional natural gas and NGLs hedges for 2015, 2016 and 2017. Any payments due to
counterparties under our derivative contracts should ultimately be funded by prices received from the sale of our production.
Production receipts, however, often lag payments to the counterparties. Any interim cash needs are funded by borrowings
under the bank credit facility. As of December 31, 2014, we have entered into hedging agreements covering 229.7 Bcfe for
2015 and 46.1 Bcfe for 2016.

Net cash provided from continuing operations in 2014 was $954.1 million compared to $743.5 million in 2013 and

$647.1 million in 2012. The increase in cash provided from operating activities from 2013 to 2014 reflects a 24% increase in
production and lower lawsuit settlements partially offset by lower realized prices (a decline of 13%). The increase in cash
provided from operating activities from 2012 to 2013 reflects a 25% increase in production somewhat offset by lower
realized prices (a decline of 4%) and higher operating costs. Net cash provided from continuing operations is also affected by
working capital changes or the timing of cash receipts and disbursements. Changes in working capital (as reflected in our
consolidated statements of cash flows) for 2014 was a negative $31.0 million compared to a negative $42.8 million for 2013
and negative $24.5 million in 2012.

Net cash used in investing activities from continuing operations in 2014 was $1.2 billion compared to $983.4 million

in 2013 and $1.5 billion in 2012.

During 2014, we:

•

•
•

spent $1.2 billion on natural gas and oil property additions associated with our drilling and completion
budget program;
spent $212.0 million on acreage, primarily in the Marcellus Shale; and
received proceeds of $180.5 million, which includes $151.7 million from our Conger Exchange.

During 2013, we:

•

•
•

spent $1.2 billion on natural gas and oil property additions associated with our drilling and completion
capital budget program;

spent $132.1 million on acreage, primarily in the Marcellus Shale; and

received proceeds of $315.5 million, which includes $275.0 million from the sale of our Southeast New
Mexico and certain West Texas properties.

During 2012, we:

•

•
•

spent $1.5 billion on natural gas and oil property additions associated with our drilling and completion
capital budget program;

spent $191.1 million on acreage, primarily in the Marcellus Shale and the Mississippian; and

received proceeds of $168.2 million, which includes $135.0 million from the sale of our Ardmore Woodford
properties in Southern Oklahoma.

Net cash provided from financing activities in 2014 was $291.4 million compared to $240.0 million in 2013 and

$881.6 million in 2012. Historically, sources of financing have been primarily bank borrowings and capital raised through
debt offerings.

During 2014, we:

• borrowed $2.1 billion and repaid $1.9 billion under our credit facility, ending the year with $223.0 million

higher bank debt;

•

redeemed all $300.0 million aggregate principal amount of 8.0% senior subordinated notes due 2019 and
paid additional expenses related to early extinguishment; and

issued 4.56 million shares of common stock where we received proceeds of $396.6 million.

During 2013, we:

• borrowed $1.7 billion and repaid $1.9 billion under our credit facility, ending the year with $239.0 million

lower bank debt;

•
•

issued $750.0 million aggregate principal amount of 5.0% senior subordinated notes due 2023; and

redeemed all $250.0 million aggregate principal amount of 7.25% senior subordinated notes due 2018 and
paid additional expenses related to the early extinguishment.

During 2012, we:

• borrowed $1.8 billion and repaid $1.2 billion under our bank credit facility, ending the year with $552.0

million higher bank debt;

•
•

issued $600.0 million aggregate principal amount of 5.0% senior subordinated notes due 2022; and

redeemed all $250.0 million aggregate principal amount of 7.5% senior subordinated notes due 2017 and
paid additional expenses related to the early extinguishment.

Liquidity and Capital Resources

Our main sources of liquidity and capital resources are internally generated cash flow from operations, a bank credit

facility with uncommitted and committed availability, asset sales and access to the debt and equity capital markets. We must
find new and develop existing reserves to maintain and grow our production and cash flows. We accomplish this primarily

through successful drilling programs which require substantial capital expenditures. Lower prices for natural gas, NGLs and
oil may reduce the amount of natural gas, NGLs and oil we can economically produce and can also affect the amount of cash
flow available for capital expenditures and our ability to borrow or raise additional capital.

We currently believe that net cash generated from operating activities, unused committed borrowing capacity under our
bank credit facility and proceeds from asset sales combined with our natural gas, NGLs and oil derivatives currently in place
will be adequate to satisfy near-term financial obligations and liquidity needs. To the extent our capital requirements exceed
our internally generated cash flow and proceeds from asset sales, debt or equity may be issued to fund these requirements.
Long-term cash flows are subject to a number of variables including the level of production and prices as well as various
economic conditions that have historically affected the natural gas and oil business. Recently, natural gas and crude oil prices
have dropped significantly. Historically, in periods of falling prices, the demand for drilling rigs, oilfield supplies and drill
pipe is also expected to decline but its decline lags significantly behind the declines in natural gas and crude oil prices. We
establish a capital budget at the beginning of each calendar year and review it during the course of the year. Our 2015 capital
budget is $870 million. Actual capital expenditure levels may vary significantly due to many factors, including drilling
results, natural gas, NGLs, crude oil and condensate prices, industry conditions, the prices and availability of goods and
services, the extent to which properties are acquired or non-strategic assets sold.

During 2014, we:

received proceeds from the sale of non-strategic assets of $180.5 million;

issued 4.56 million shares of common stock where we received proceeds of $396.6 million;

•
•
•
•
• we had available borrowing capacity of $1.2 billion under our bank credit facility as of December 31, 2014.

redeemed all $300.0 million aggregate principle amount of 8.0% senior subordinated notes due 2019;

renewed, modified and extended our bank credit facility to a maturity of October 2019; and

Credit Arrangements

Long-term debt at December 31, 2014 totaled $3.1 billion, including $723.0 million of bank credit facility debt and

$2.4 billion of senior subordinated notes. As of December 31, 2014, we maintain a bank credit facility with an initial
borrowing base of $3.0 billion and aggregate lender commitments of $2.0 billion, which we refer to as our bank credit
facility. As of December 31, 2014, we also have $105.3 million of undrawn letters of credit. The bank credit facility is
secured by substantially all of our assets and has a maturity date of October 16, 2019. Availability under the bank credit
facility, during a non-investment grade period, is subject to a borrowing base set by the lenders annually with an option to set
more often in certain circumstances. Availability under the bank credit facility during an investment grade period is limited
to the aggregate lender commitments. The borrowing base is dependent on a number of factors, but primarily the lenders’
assessments of future cash flows. Redeterminations of the borrowing base to maintain or reduce the amount thereof require
approval of two thirds of the lenders; increases require 95% approval.

Our bank credit facility and our subordinated notes impose limitations on the payment of dividends and other restricted

payments (as defined under the debt agreements for our bank debt and our subordinated notes). The debt agreements also
contain customary covenants relating to debt incurrence, liens, investments and financial ratios. We were in compliance with
all covenants at December 31, 2014.

Proved Reserves

To maintain and grow production and cash flow, we must continue to develop existing proved reserves and locate or

acquire new natural gas, NGLs and oil reserves. The following is a discussion of proved reserves, reserve additions and
revisions and future net cash flows from proved reserves.

Proved Reserves:

Beginning of year

Reserve additions
Reserve revisions
Purchases
Sales
Production

End of year

Proved Developed Reserves:

Beginning of year
End of year

Year End December 31,
2013

2012

2014

(Mmcfe)

8,202,274
2,398,709
90,822
262,813
(220,122)
(424,267)

10,310,229

6,505,570
5,053,961
1,732,944 1,767,202
448,898
109,036
⎯
⎯
(142,116 )
(149,153)
(275,476)
(343,022 )
8,202,274 6,505,570

4,192,666
5,349,761

2,401,274
3,457,502
4,192,666 3,457,502

Our proved reserves at year-end 2014 were 10.3 Tcfe compared to 8.2 Tcfe at year-end 2013 and 6.5 Tcfe at year-end

2012. Natural gas comprised approximately 67%, 69% and 74% of our proved reserves at year-end 2014, 2013 and 2012.

Reserve Additions and Revisions. During 2014, we added approximately 2.4 Tcfe of proved reserves from drilling
activities and evaluation of proved areas primarily in the Marcellus Shale. Approximately 58% of 2014 reserve additions was
attributable to natural gas. Included in 2014 proved reserves is a total of 1,170 Bcfe of ethane reserves (264.3 Mmbbls) in the
Marcellus Shale. Revisions of previous estimates of a net 91 Bcfe includes positive performance revisions and unproved
recovery primarily for our Marcellus Shale natural gas properties and positive price revisions, somewhat offset by reserves of
611 Bcfe reclassified to unproved as we continue to see success from drilling longer laterals, increasing the number of frac
stages and better lateral targeting caused some previously planned wells to not be drilled within the original five-year
development horizon.

During 2013, we added 1.7 Tcfe of proved reserves from drilling activities and evaluation of proved areas, primarily in
the Marcellus Shale. Approximately 49% of the 2013 reserve additions was attributable to natural gas. Revisions of previous
estimates of 449 Bcfe for the year ended December 31, 2013 consists of positive performance revisions, positive price
revisions and improved recovery, partially offset by reserves reclassified to unproved because of a slower pace of
development activity beyond the five-year development horizon. We added 369 Bcfe of incremental ethane reserves under
additional ethane contracts in Appalachia.

During 2012, we added 1.8 Tcfe of proved reserves from drilling activities and evaluations of proved areas, primarily

in the Marcellus Shale. Approximately 56% of the 2012 reserve additions was attributable to natural gas. We added 307 Bcfe
(or 17% of the 2012 reserve additions) of incremental ethane reserves in Appalachia (51.2 Mmbls) as part of NGLs proved
reserves associated with initial ethane deliveries under contracts commencing in 2013. Revisions of previous estimates of 109
Bcfe for the year ended December 31, 2012 consist of positive performance revisions for our properties somewhat offset by
negative pricing revisions and reserves reclassified to unproved because of a slower pace of development activity beyond the
five-year development horizon.

Purchases. In 2014, we purchased 262.8 Bcfe of reserves primarily related to the Conger Exchange where we received

producing properties in Virginia.

Sales. In 2014, we sold 220.1 Bcfe of reserves primarily related to the sale of our Conger properties in Glasscock and

Sterling Counties, Texas. In 2013, we sold 142.1 Bcfe of reserves related to the sale of certain of our Permian Basin and New
Mexico properties. In 2012, we sold approximately 149.2 Bcfe of reserves primarily related to the sale of our Ardmore
Woodford properties in Southern Oklahoma.

Future Net Cash Flows. At December 31, 2014, the present value (discounted at 10%) of estimated future net cash

flows from our proved reserves was $10.1 billion. The present value of our estimated future net cash flows at December 31,
2013 was $7.9 billion. This present value was calculated based on the unweighted average first-day-of-the-month oil and gas
prices for the prior twelve months held flat for the life of the reserves. At December 31, 2014, the after-tax present value of
estimated future net cash flows from our proved reserves was $7.6 billion compared to $5.9 billion at December 31, 2013.

The present value of future net cash flows does not purport to be an estimate of the fair market value of our proved
reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and
costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time
value of money to the evaluating party and the perceived risks inherent in producing oil and gas.

Capitalization and Dividend Payments

As of December 31, 2014 and 2013, our total debt and capitalization were as follows (in thousands):

Bank debt
Senior subordinated notes

Total debt

Stockholders’ equity

Total capitalization
Debt to capitalization ratio

2014

2013

$ 723,000 $ 500,000
2,640,515
2,350,000
3,140,515
3,073,000
3,457,429
2,414,452
$6,530,429 $ 5,554,967

47.1%

56.5%

The amount of future dividends is subject to declaration by the Board of Directors and primarily depends on earnings,

capital expenditures and various other factors. In 2014, we paid $26.6 million in dividends to our common shareholders
($0.04 per share each quarter). In 2013, we paid $26.1 million in dividends to our common shareholders ($0.04 per share
each quarter). In 2012, we paid $26.0 million in dividends to our common shareholders ($0.04 per share each quarter).
Cash Contractual Obligations

Our contractual obligations include long-term debt, operating leases, drilling commitments, derivative obligations,

asset retirement obligations and transportation and gathering commitments. As of December 31, 2014, we do not have any
capital leases or any significant off-balance sheet debt or other such unrecorded obligations and we have not guaranteed any
debt of any unrelated party. As of December 31, 2014, we had a total of $105.3 million of letters of credit outstanding under
our bank credit facility. The table below provides estimates of the timing of future payments that we are obligated to make
based on agreements in place at December 31, 2014. In addition to the contractual obligations listed on the table below, our
balance sheet at December 31, 2014 reflects accrued interest payable on our bank debt of $862,000 which is payable in first
quarter 2015. We expect to make interest payments of $33.8 million per year on our 6.75% senior subordinated notes, $28.8
million per year on our 5.75% senior subordinated notes and $67.5 million per year on our 5.0% senior subordinated notes.

The following summarizes our contractual financial obligations at December 31, 2014 and their future maturities. We
expect to fund these contractual obligations with cash generated from operating activities, borrowings under our bank credit
facility, additional debt issuances and proceeds from asset sales (in thousands).

2015

2016

2017

2018
and 2019

Thereafter

Total

Payment due by period

Debt:

Bank debt due 2019 (a)
6.75% senior subordinated notes due 2020
5.75% senior subordinated notes due 2021
5.0% senior subordinated notes due 2022
5.0% senior subordinated notes due 2023

⎯ $
⎯
⎯
⎯
⎯

723,000 $
⎯
⎯
⎯
⎯

⎯ $
500,000
500,000
600,000
750,000

723,000
500,000
500,000
600,000
750,000

Other obligations:

Operating leases
Transportation and gathering commitments
Hydraulic fracturing services
Other purchase obligations
Asset retirement obligation liability (b)
Total contractual obligations (c)

16,557
342,204
12,000
408
15,067
$ 386,236 $

12,700
366,836
⎯
283
134
379,953 $

10,059

12,830

7,292
356,789
⎯
199
⎯

59,438
639,012 1,842,410 3,547,251
12,000
890
287,464
364,280 $ 1,372,169 $ 4,477,405 $ 6,980,043

⎯
⎯
272,165

⎯
⎯
98

(a) Due at termination date of our bank credit facility. Interest paid on our bank credit facility would be approximately $14.3 million each

year assuming no change in the interest rate or outstanding balance.

(b) The ultimate settlement amount and timing cannot be precisely determined in advance. See Note 8 to our consolidated financial

statements.

(c) This table excludes the liability for the deferred compensation plans since these obligations will be funded with existing plan assets.

In addition to the amounts included in the above table, we have entered into additional transportation and gathering

agreements which are contingent on certain pipeline and gathering line modifications and/or construction. These agreements
51

range between five-year and twenty-year terms which are expected to begin mid-2015 through late 2017. Based on these
contracts, we will have additional gathering and transportation obligations for natural gas volumes from 7,000 mcf per day to
400,000 mcf per day, ethane volumes of 20,000 bbls per day and propane volumes of 20,000 bbls per day through the end of
the contract terms.

Delivery Commitments

We have various volume delivery commitments that are primarily related to our Midcontinent and Marcellus Shale

areas. We may purchase third party volumes to satisfy our commitments or pay demand fees for commitment shortfalls,
should they occur. As of December 31, 2014, our delivery commitments through 2028 were as follows:

Year Ending
December
31,

Natural Gas
(mmbtu per day)

Ethane
(bbls per day)

2015

2016

2017

2018
2019
2020
2021

2022 - 2028

313,180

268,055

139,840

30,000
30,000
30,000
30,000

⎯

15,000

15,000
15,000
15,000
15,000

In addition to the amounts included in the above table, we have contracted with several pipeline companies through
2033 to deliver ethane production volumes from our Marcellus Shale wells. These agreements and related fees, which are
contingent upon pipeline construction and/or modification, are for 10,000 bbls per day starting in mid-2015, increasing to
20,000 bbls per day in late 2015, increasing to 30,000 bbls per day in 2017 and 45,000 bbls per day in 2018 through the end
of the term.

Other

We lease acreage that is generally subject to lease expiration if initial wells are not drilled within a specified period,

generally between three to five years. We do not expect to lose significant lease acreage because of failure to drill due to
inadequate capital, equipment or personnel. However, based on our evaluation of prospective economics, including the cost
of infrastructure to connect production, we have allowed acreage to expire and will allow additional acreage to expire in the
future. To date, our expenditures to comply with environmental or safety regulations have not been a significant component
of our cost structure and are not expected to be significant in the future. However, new regulations, enforcement policies,
claims for damages or other events could result in significant future costs.

Hedging – Natural Gas, Oil and NGLs Prices

We use commodity-based derivative contracts to manage exposures to commodity price fluctuations. We do not enter

into these arrangements for speculative or trading purposes. We do not utilize complex derivatives as we typically utilize
commodity swaps and collars to (1) reduce the effect of price volatility on the commodities we produce and sell and
(2) support our annual capital budget and expenditure plans. In addition, we may utilize basis contracts to hedge the
differential between NYMEX and those of our physical pricing points. For more discussion of our derivative activities, see
“Management’s Discussion of Critical Accounting Estimates – Natural Gas and Oil Derivatives” below and “Item 7A.
Quantitative and Qualitative Disclosures about Market Risk – Commodity Price Risk” and “Other Commodity Risk.” For
more information regarding the accounting for our derivatives, see the discussion and tables in Notes 2, 10 and 11 to our
consolidated financial statements. While there is a risk that the financial benefit of rising natural gas, NGLs and oil prices
may not be captured, we believe the benefits of stable and predictable cash flow are more important. Among these benefits
are a more efficient utilization of existing personnel and planning for future staff additions, the flexibility to enter into long-
term projects requiring substantial committed capital, smoother and more efficient execution of our ongoing development
drilling and production enhancement programs, more consistent returns on invested capital, and better access to bank and
other credit markets.

Interest Rates

At December 31, 2014, we had $3.1 billion of debt outstanding. Of this amount, $2.4 billion bears interest at fixed rates

averaging 5.5%. Bank debt totaling $723.0 million bears interest at floating rates, which averaged 2.0% at year-end 2014.
The 30-day LIBO rate on December 31, 2014 was 0.2%. A 1% increase in short-term interest rates on the floating-rate debt
outstanding at December 31, 2014 would cost us approximately $7.2 million in additional annual interest expense.

Off-Balance Sheet Arrangements

We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance our liquidity or

capital resources position. However, as is customary in the oil and gas industry, we have various contractual work
commitments which are described above under cash contractual obligations.

Inflation and Changes in Prices

Our revenues, the value of our assets and our ability to obtain bank loans or additional capital on attractive terms have

been and will continue to be affected by changes in natural gas, NGLs and oil prices and the costs to produce our reserves.
Natural gas, NGLs and oil prices are subject to significant fluctuations that are beyond our ability to control or predict.
Although certain of our costs and expenses are affected by general inflation, inflation does not normally have a significant
effect on our business. We expect costs in 2015 to continue to be a function of supply and demand. Recently, natural gas and
oil prices have declined significantly. Historically, the demand for drilling rigs, oilfield supplies and drill pipe is expected to
decline with falling commodity prices but such decline tends to lag behind the declines in natural gas, NGLs and oil prices.

Management’s Discussion of Critical Accounting Estimates

Our discussion and analysis of our financial condition and results of operations are based upon consolidated financial
statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The
preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of
assets and liabilities, the disclosure of contingent assets and liabilities at year-end, the reported amounts of revenues and
expenses during the year and proved natural gas and oil reserves. Some accounting policies involve judgments and
uncertainties to such an extent there is a reasonable likelihood that materially different amounts could have been reported
under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular
basis. We base our estimates on historical experience and various other assumptions that we believe are reasonable under the
circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that
are not readily apparent from other sources. Actual results could differ from the estimates and assumptions used.

Certain accounting estimates are considered to be critical if (a) the nature of the estimates and assumptions is material

due to the level of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such
matters to changes; and (b) the impact of the estimates and assumptions on financial condition or operating performance is
material. Actual results could differ from the estimates and assumptions used.

Natural Gas and Oil Properties

We use the successful efforts method of accounting for natural gas and oil producing activities as opposed to the
alternate acceptable full cost method. We believe that net assets and net income are more conservatively measured under the
successful efforts method of accounting than under the full cost method, particularly during periods of active exploration.
One difference between the successful efforts method of accounting and the full cost method is under the successful efforts
method all exploratory dry holes and geological and geophysical costs are charged against earnings during the periods they
occur; whereas, under the full cost method of accounting, such costs are capitalized as assets, pooled with the costs of
successful wells and charged against earnings of future periods as a component of depletion expense. Under the successful
efforts method of accounting, successful exploration drilling costs and all development costs are capitalized and these costs
are systematically charged to expense using the units of production method based on proved developed natural gas and oil
reserves as estimated by our engineers and audited by independent engineers. Costs incurred for exploratory wells that find
reserves that cannot yet be classified as proved are capitalized on our balance sheet if (a) the well has found a sufficient
quantity of reserves to justify its completion as a producing well and (b) we are making sufficient progress assessing the
reserves and the economic and operating viability of the project. Proven property leasehold costs are amortized to expense
using the units of production method based on total proved reserves. Properties are assessed for impairment as circumstances
warrant (at least annually) and impairments to value are charged to expense. The successful efforts method inherently relies
upon the estimation of proved reserves, which includes proved developed and proved undeveloped volumes.

Proved reserves are defined by the SEC as those volumes of natural gas, NGLs, condensate and crude oil that

geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs
under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered through
existing wells with existing equipment and operating methods. Although our engineers are knowledgeable of and follow the

guidelines for reserves established by the SEC, including the rule revisions designed to modernize the oil and gas company
reserves reporting requirements which we adopted effective December 31, 2009, the estimation of reserves requires engineers
to make a significant number of assumptions based on professional judgment. Reserve estimates are updated at least annually
and consider recent production levels and other technical information. Estimated reserves are often subject to future
revisions, which could be substantial, based on the availability of additional information, including: reservoir performance,
new geological and geophysical data, additional drilling, technological advancements, price and cost changes and other
economic factors. Changes in natural gas, NGLs and oil prices can lead to a decision to start up or shut in production, which
can lead to revisions to reserve quantities. Reserve revisions in turn cause adjustments in our depletion rates. We cannot
predict what reserve revisions may be required in future periods. Reserve estimates are reviewed and approved by our Senior
Vice President of Reservoir Engineering and Economics who reports directly to our Chairman, President and Chief Executive
Officer. For additional discussion, see “Proved Reserves,” in Items 1 and 2 of this report. To further ensure the reliability of
our reserve estimates, we engage independent petroleum consultants to audit our estimates of proved reserves. Estimates
prepared by third parties may be higher or lower than those included herein. Independent petroleum consultants audited
approximately 96% of our reserves in 2014 compared to 96% in 2013 and 93% in 2012. Historical variances between our
reserve estimates and the aggregate estimates of our consultants have been less than 5%. The reserves included in this report
are those reserves estimated by our petroleum engineering staff.

Depletion rates are determined based on reserve quantity estimates and the capitalized costs of producing properties.
As the estimated reserves are adjusted, the depletion expense for a property will change, assuming no change in production
volumes or the capitalized costs. While total depletion expense for the life of a property is limited to the property’s total cost,
proved reserve revisions result in a change in the timing of when depletion expense is recognized. Downward revisions of
proved reserves may result in an acceleration of depletion expense, while upward revisions tend to lower the rate of depletion
expense recognition. Based on proved reserves at December 31, 2014, we estimate that a 1% change in proved reserves
would increase or decrease 2015 depletion expense by approximately $5.0 million (based on current production estimates).
Estimated reserves are used as the basis for calculating the expected future cash flows from property asset groups, which are
used to determine whether that property may be impaired. Reserves are also used to estimate the supplemental disclosure of
the standardized measure of discounted future net cash flows relating to natural gas and oil producing activities and reserve
quantities in Note 18 to our consolidated financial statements. Changes in the estimated reserves are considered a change in
estimate for accounting purposes and are reflected on a prospective basis. It should not be assumed that the standardized
measure is the current market value of our estimated proved reserves.

We monitor our long-lived assets recorded in natural gas and oil properties in our consolidated balance sheets to ensure

they are fairly presented. We must evaluate our properties for potential impairment when circumstances indicate that the
carrying value of an asset could exceed its fair value. A significant amount of judgment is involved in performing these
evaluations since the results are based on estimated future events. Such events include a projection of future natural gas,
NGLs and oil prices, an estimate of the ultimate amount of recoverable natural gas, NGLs and oil reserves that will be
produced from the property asset groups future production, future production costs, future abandonment costs, and future
inflation. The need to test a property asset group for impairment can be based on several factors, including a significant
reduction in sales prices for natural gas, NGLs and/or oil, unfavorable adjustments to reserves, physical damage to production
equipment and facilities, a change in costs, or other changes to contracts or environmental regulations. Our natural gas and oil
properties are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are
largely independent of other groups of assets which is the level at which depletion is calculated. The review is done by
determining if the historical cost of proved properties less the applicable accumulated depreciation, depletion and
amortization is less than the estimated undiscounted future net cash flows. We estimate prices based upon market-related
information including published futures prices. The estimated future level of production, which is based on proved and risk
adjusted probable and possible reserves, has assumptions surrounding the future levels of prices and costs, field decline rates,
market demand and supply and the economic and regulatory climates. In certain circumstances, we also consider potential
sales of properties to third parties in our estimates of future cash flows. When the carrying value exceeds the sum of future
net cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by
discounted future net cash flows using a discount rate similar to that used by market participants) and the carrying value of
the asset. We cannot predict whether impairment charges may be required in the future. Our recorded impairment of
producing properties was $28.0 million in 2014, $7.0 million in 2013 and $34.3 million in 2012. In 2014, an impairment of
$5.5 million was recorded on our Mississippi properties due to lower reserves, an impairment of $18.5 million was recorded
on certain West Texas properties due to lower reserves which also considered the possibility of a sale of these properties and
an impairment of $4.0 million to fully write-down our remaining oil and natural gas properties in North Texas. In 2013, an
impairment of $7.0 million was recorded on certain South Texas properties due to lower reserves and we also recorded a
$741,000 impairment of remaining surface acreage in North Texas. In 2012, an impairment was recorded on our Mississippi
properties of $31.1 million due to lower reserves and lower natural gas prices, an impairment of $3.2 million was recorded on
our remaining North Texas Barnett assets (due to lower natural gas prices and including the possibility of sale) and we also
recorded a $1.3 million impairment of remaining surface acreage on the Barnett. We believe that a sensitivity analysis
regarding the effect of changes in assumptions on estimated impairment is impractical to provide because of the number of

assumptions and variables involved which have interdependent effects on the potential outcome. If natural gas, NGLs and oil
prices decrease or drilling efforts are unsuccessful, we may be required to record additional impairments.

We evaluate our unproved property investment periodically for impairment. The majority of these costs generally relate

to the acquisition of leaseholds. The costs are capitalized and evaluated (at least quarterly) as to recoverability, based on
changes brought about by economic factors and potential shifts in business strategy employed by management. Impairment
of a significant portion of our unproved properties is assessed and amortized on an aggregate basis based on our average
holding period, expected forfeiture rate and anticipated drilling success. Potential impairment of individually significant
unproved property is assessed on a property-by-property basis considering a combination of time, geologic and engineering
factors. We have recorded abandonment and impairment expense related to unproved properties of $47.1 million in 2014
compared to $51.9 million in 2013 and $125.3 million in 2012.

Fair Value Estimates

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction

between market participants at the measurement date. There are three approaches for measuring the fair value of assets and
liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation
techniques. The market approach uses prices and other relevant information generated by market transactions involving
identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by
converting future amounts, such as cash flows or earnings, into a single present value, or range of present values, using
current market expectations about those future amounts. The cost approach is based on the amount that would currently be
required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach
assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset
of comparable utility, adjusted for obsolescence.

The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair
value and do not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs
used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to
make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value
hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:

• Level 1- Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets
as of the measurement date. Active markets are those in which transactions for the asset or liability occur in
sufficient frequency and volume to provide pricing information on an ongoing basis.

• Level 2- Observable market-based inputs or unobservable inputs that are corroborated by market data. These are
inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly
observable as of the measurement date.

• Level 3-Unobservable inputs that are not corroborated by market data and may be used with internally developed

methodologies that result in management’s best estimate of fair value.

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in

their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of
the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets
and liabilities within the levels of the fair value hierarchy. See Note 11 to the consolidated financial statements for
disclosures regarding our fair value measurements.

impairment assessments of long-lived assets;

Significant uses of fair value measurements include:
•
•
•

recorded value of derivative instruments.

allocation of the purchase price paid to acquire businesses as to the assets acquired and liabilities assumed; and

Natural Gas and Oil Derivatives

All derivative instruments are recorded on our consolidated balance sheets as either an asset or a liability measured at

its fair value. Fair value measurements for all of our derivatives are based on observable market-based inputs that are
corroborated by market data and are discussed in Note 10 to the consolidated financial statements. Additional information
about derivatives and their valuation may be found in “Item 7A. Quantitative and Qualitative Disclosures About Market
Risk.”

Asset Retirement Obligations

We have significant obligations to remove tangible equipment and restore the surface at the end of natural gas and oil

production operations. Removal and restoration obligations are primarily associated with plugging and abandoning wells.
Estimating the future asset removal costs is difficult and requires us to make estimates and judgments because most of the
removal obligations are many years in the future and contracts and regulations often have vague descriptions of what
constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political,
environmental, safety and public relations considerations.

Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate retirement costs,
inflation factors, credit-adjusted discount rates, timing of retirement, and changes in the legal, regulatory, environmental and
political environments. To the extent future revisions to these assumptions impact the present value of the existing asset
retirement obligation (“ARO”), a corresponding adjustment is made to the natural gas and oil property balance. For example,
as we analyze actual plugging and abandonment information, we may revise our estimate of current costs, the assumed
annual inflation of the costs and/or the assumed productive lives of our wells. During 2014, we increased our existing ARO
by $48.3 million or approximately 21% of the ARO at December 31, 2013. This increase was due to an increase in the
estimated costs to plug and abandon our wells. During 2013, we increased our existing estimated ARO by $67.6 million or
approximately 46% of the asset retirement obligation at December 31, 2012 due to an increase in estimated costs to plug and
abandon our wells and a decrease in the production life of certain of our natural gas properties due to declining prices. See
Note 8 to the consolidated financial statements for disclosures regarding our asset retirement obligation estimates. In
addition, increases in the discounted ARO resulting from the passage of time are reflected as accretion expense, a component
of depletion, depreciation and amortization in the accompanying consolidated statements of income. Because of the
subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary
significantly from prior estimates. An estimate of the sensitivity to net income of other assumptions that had been used in
recording these liabilities is not practical because of the number of obligations that must be assessed, the number of
underlying assumptions and the wide range of possible assumptions.

Income Taxes

We are subject to income and other taxes in all areas in which we operate. When recording income tax expense, certain

estimates are required because income tax returns are generally filed many months after the close of a calendar year, tax
returns are subject to audit, which can take years to complete, and future events often impact the timing of when income tax
expenses and benefits are recognized. We have recorded deferred tax assets and liabilities for temporary differences between
book basis and tax basis and operating loss carryforwards. We have deferred tax assets relating to tax operating loss
carryforwards and other deductible differences. We routinely evaluate deferred tax assets to determine the likelihood of
realization and, in certain jurisdictions, we must estimate our expected future taxable income to complete this assessment.
Numerous assumptions are inherent in the estimation of future taxable income, including assumptions about the timing and
realization of deferred tax items, future operating conditions (particularly related to prevailing natural gas, NGLs and oil
prices) and the overall financial condition of the markets we operate in. The estimates or assumptions used in determining
future taxable income are consistent with those used in our internal budgets and forecasts. A valuation allowance is
recognized on deferred tax assets when we believe that certain of these assets are more likely than not to be realized. We do
not currently have a valuation allowance on our federal net operating loss carryforwards. During 2014, we increased our
valuation allowance we had against our state net operating loss carryforwards from $3.0 million to $8.8 million.

We may be challenged by taxing authorities over the amount and/or timing of recognition of revenues and deductions
in our various income tax returns. Although we believe that we have adequately provided for all taxes, gains or losses could
occur in the future due to changes in estimates or resolution of outstanding tax matters.

Contingent Liabilities

A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and

the cost or range of cost can be reasonably estimated. Judgment is often required to determine when expenses should be
recorded for legal, environmental and contingent matters. In addition, we often must estimate the amount of such losses. In
many cases, our judgment is based on the input of our legal advisors and on the interpretation of laws and regulations, which
can be interpreted differently by regulators and/or the courts. Actual costs can differ from estimates for many reasons. We
monitor known and potential legal, environmental and other contingent matters and make our best estimate of when to record
losses for these matters based on available information. Although we continue to monitor all contingencies closely,
particularly our outstanding litigation, we currently have no material accruals for contingent liabilities.

Revenue Recognition

Natural gas, NGLs and oil sales are recognized when we deliver our production to the customer and collectability is

reasonably assured. We use the sales method to account for gas imbalances, recognizing revenue based on gas delivered
rather than our working interest share of gas produced. We generally sell natural gas, NGLs and oil under two types of

agreements, which are common in our industry. Both types of agreements include transportation charges. We report our
gathering and transportation costs in accordance with FASB 605-45-05 of Subtopic 605-45 for Revenue Recognition. One
type of agreement is a netback arrangement, under which we sell natural gas and oil at the wellhead and collect a price, net of
transportation incurred by the purchaser. In this case, we record revenue at the net price we received from the purchaser. In
the case of NGLs, we receive a net price from the purchaser (which is net of processing costs) which is recorded in revenue at
the net price. Under the other arrangement, we sell natural gas or oil at a specific delivery point, pay transportation, gathering
and compression to a third party and receive proceeds from the purchaser with no deduction. In that case, we recorded
revenue at the price received from the purchaser and record these third party costs as transportation, gathering and
compression expense.

Stock-based Compensation Arrangements

The fair value of performance share unit awards is estimated on the date of grant using the Monte Carlo simulation

method. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the
market condition stipulated in the award grant. The fair value of stock-settled stock appreciation rights is estimated on the
date of grant using the Black-Scholes-Merton option-pricing model. The models employ various assumptions, based on
management’s best estimates at the time of the grant, which impact the fair value calculated and ultimately, the expense that
is recognized over the life of the award. We have utilized historical data and analyzed current information to reasonably
support these assumptions. The fair value of restricted stock awards is determined based on the fair market value of our
common stock on the date of grant. The fair value of restricted stock grants is determined based on the fair market value of
our common stock on the date of grant.

We recognize stock-based compensation expense on a straight-line basis over the requisite service period for the entire

award. The expense we recognize is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience
and adjust it as circumstances warrant. See Note 12 to our consolidated financial statements for more information.

Accounting Standards Not Yet Adopted

In May 2014, an accounting standards update was issued for “Revenue from Contracts with Customers,” which

supersedes the revenue recognition requirements in “Topic 605, Revenue Recognition” and requires entities to recognize
revenue in a way that depicts 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. The new guidance will be
effective for us for the reporting period beginning January 1, 2017, with early application not permitted. Entities have the
option of using either a full retrospective or modified approach to adopt this new standard. We are evaluating our existing
revenue recognition policies to determine whether any contracts will be affected by the new requirements.

In August 2014, the Financial Accounting Standards Board (“FASB”) issued an update that requires management to

assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are
currently in U.S. auditing standards. This standard will be effective for us in first quarter 2017 and early adoption is
permitted. We do not expect the adoption of this standard to have any impact on our consolidated results of operations,
financial position or cash flows.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative

information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from
adverse changes in natural gas, NGLs and oil prices and interest rates. The disclosures are not meant to be precise indicators
of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides
indicators of how we view and manage our ongoing market-risk exposure. All of our market-risk sensitive instruments were
entered into for purposes other than trading. All accounts are U.S. dollar denominated.

Market Risk

We are exposed to market risks related to the volatility of natural gas, NGLs and oil prices. We employ various

strategies, including the use of commodity derivative instruments, to manage the risks related to these price fluctuations.
These derivative instruments apply to a varying portion of our production and provide only partial price protection. These
arrangements limit the benefit to us of increases in prices but offer protection in the event of price declines. Further, if our
counterparties defaulted, this protection might be limited as we might not receive the benefits of the derivatives. Realized
prices are primarily driven by worldwide prices for oil and spot market prices for North American natural gas production.
Natural gas and oil prices have been volatile and unpredictable for many years. Natural gas prices affect us more than oil
prices because approximately 67% of our December 31, 2014 proved reserves are natural gas. We are also exposed to market
risks related to changes in interest rates. These risks did not change materially from December 31, 2013 to December 31,
2014.

Commodity Price Risk

We use commodity-based derivative contracts to manage exposures to commodity price fluctuations. We do not enter

into these arrangements for speculative or trading purposes. We do not utilize complex derivatives such as swaptions,
knockouts or extendable swaps. At times, certain of our derivatives are swaps where we receive a fixed price for our
production and pay market prices to the counterparty. Our derivatives program may also include collars, which establishes a
minimum floor price and a predetermined ceiling price. At December 31, 2014, our derivatives program includes swaps and
collars. These contracts expire monthly through December 2016. Their fair value, represented by the estimated amount that
would be realized upon immediate liquidation as of December 31, 2014, approximated a net unrealized pre-tax gain of $401.7
million compared to a pre-tax loss of $16.5 million at December 31, 2013. This change is primarily related to the settlements
of derivative contracts during 2014 and to the natural gas, NGLs and oil futures prices as of December 31, 2014, in relation to
the new commodity derivative contracts we entered into during 2014 for 2015 and 2016. At December 31, 2014, the
following commodity derivative contracts were outstanding:

Period

Contract Type

Volume Hedged

Weighted
Average
Hedge Price

Fair
Market
Value
(in thousands)

Natural Gas
2015
2015
2016

Crude Oil
2015
2016

NGLs (C3 - Propane)
2015

NGLs (C5 - Natural Gasoline)
2015 – First Quarter

Collars
Swaps
Swaps

Swaps
Swaps

Swaps

145,000 Mmbtu/day
412,390 Mmbtu/day
120,000 Mmbtu/day

$ 4.07–$ 4.56
$ 4.15
$ 4.15

9,626 bbls/day
1,000 bbls/day

$ 90.57
$ 91.43

$
$
$

$
$

57,460
168,641
30,099

118,364
10,215

2,245 bbls/day

$ 0.95/gallon

14,727

500 bbls/day

$ 2.14/gallon

2,170

We expect our NGLs production to continue to increase. In our Marcellus Shale operations, propane is a large product
component of our NGLs production and we believe NGLs prices are somewhat seasonal. Therefore, the percentage of NGLs
prices to NYMEX WTI (or West Texas Intermediate) will vary due to product components, seasonality and geographic
supply and demand. We sell NGLs in several regional markets.

Currently, there is little demand, or facilities to supply the existing demand, elsewhere, for ethane in the Appalachian

region. We have previously announced three ethane agreements wherein we have contracted to either sell or transport ethane
from our Marcellus Shale area, two of which began operations in late 2013. The remaining facility is expected to begin
operations in mid-2015. We cannot assure you that these facilities will become or remain available. If we are not able to sell a
portion of our ethane, we may be required to curtail production which will adversely affect our revenues. However, as we
have done in the past, we also may be able to purchase gas to blend with our rich residue gas from the Southwest Marcellus
Shale.

Other Commodity Risk

We are impacted by basis risk, caused by factors that affect the relationship between commodity futures prices

reflected in derivative commodity instruments and the cash market price of the underlying commodity. Natural gas
transaction prices are frequently based on industry reference prices that may vary from prices experienced in local markets. If
commodity price changes in one region are not reflected in other regions, derivative commodity instruments may no longer
provide the expected hedge, resulting in increased basis risk. In addition to the collars and swaps above, we have entered into
basis swap agreements. The price we receive for our gas production can be more or less than the NYMEX price because of
adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into basis swap
agreements that effectively lock in the basis adjustments. The fair value of the basis swaps was a gain of $1.7 million at
December 31, 2014, the volumes are for 35,164 Mmbtu/day and they expire monthly through October 2015.

Commodity Sensitivity Analysis

The following table shows the fair value of our collars, swaps and basis swaps and the hypothetical change in fair value

that would result from a 10% and a 25% change in commodity prices at December 31, 2014. We remain at risk for possible
changes in the market value of commodity derivative instruments; however, such risks should be mitigated by price changes
in the underlying physical commodity (in thousands):

Collars
Swaps
Basis swaps

Hypothetical Change
in Fair Value
Increase in
Commodity Price of
Fair Value
25%
10%
$ 57,460 $ (14,557) $ (35,240 ) $ 15,067 $ 38,345
344,216 (115,335) (211,693 ) 84,676 211,686
1,930

Hypothetical Change
in Fair Value
Decrease in
Commodity Price of

(1,931 )

1,687

(772)

772

10%

25%

Our commodity-based contracts expose us to the credit risk of non-performance by the counterparty to the contracts.

Our exposure is diversified among major investment grade financial institutions and we have master netting agreements with
the majority of our counterparties that provide for offsetting payables against receivables from separate derivative contracts.
Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. At
December 31, 2014, our derivative counterparties include fifteen financial institutions, of which all but one are secured
lenders in our bank credit facility. Counterparty credit risk is considered when determining the fair value of our derivative
contracts. While counterparties are major investment grade financial institutions, the fair value of our derivative contracts
have been adjusted to account for the risk of non-performance by certain of our counterparties, which was immaterial.
Interest Rate Risk

We are exposed to interest rate risk on our bank debt. We attempt to balance variable rate debt, fixed rate debt and debt
maturities to manage interest costs, interest rate volatility and financing risk. This is accomplished through a mix of fixed rate
senior subordinated debt and variable rate bank debt. At December 31, 2014, we had $3.1 billion of debt outstanding. Of this
amount, $2.4 billion bears interest at a fixed rate averaging 5.5%. Bank debt totaling $723.0 million bears interest at floating
rates, which was 2.0% on that date. On December 31, 2014, the 30-day LIBO rate was 0.2%. A 1% increase in short-term
interest rates on the floating-rate debt outstanding at December 31, 2014 would cost us approximately $7.2 million in
additional annual interest expense.

The fair value of our subordinated debt is based on year-end December 2014 quoted market prices. The following table

presents information on these fair values (in thousands):

Fixed rate debt:

Senior Subordinated Notes due 2020

(The interest rate is fixed at a rate of 6.75%)

Senior Subordinated Notes due 2021

(The interest rate is fixed at a rate of 5.75%)

Senior Subordinated Notes due 2022

(The interest rate is fixed at a rate of 5.00%)

Senior Subordinated Notes due 2023

(The interest rate is fixed at a rate of 5.00%)

Carrying
Value

Fair
Value

500,000 $

523,125

500,000

520,000

600,000

601,500

750,000

754,688

2,350,000 $

2,399,313

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

For financial statements required by Item 8, see Item 15 in Part IV of this report.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND

FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures. As required by Rule 13a-15(b) under the Exchange Act, we have

evaluated, under the supervision and with the participation of our management, including our principal executive officer and
principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined
in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-K. Our
disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by
us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our
principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required
disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of
the SEC. Based upon the evaluation, our principal executive officer and principal financial officer concluded that our
disclosure controls and procedures were effective as of December 31, 2014 at the reasonable assurance level.

Changes in Internal Controls over Financial Reporting. There have been no changes in our system of internal control

over financial reporting (such as term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter
ended December 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over
financial reporting.

Management’s Annual Report on Internal Control over Financial Reporting. See “Management’s Report on Internal

Control over Financial Reporting” and “Report of Independent Registered Public Accounting Firm on Internal Control Over
Financial Reporting” which appear on pages F-2 and F-3, respectively, under “Item 15. Exhibits, Financial Statements
Schedules.”

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The officers and directors are listed below with a description of their experience and certain other information. Each
director was elected for a one-year term at the 2014 annual stockholders’ meeting. Officers are appointed by our Board of
Directors.

Anthony V. Dub
V. Richard Eales
Allen Finkelson
James M. Funk
Christopher A. Helms
Jonathan S. Linker
Mary Ralph Lowe
Kevin S. McCarthy
John H. Pinkerton
Jeffrey L. Ventura
Roger S. Manny
Ray N. Walker, Jr.
John K. Applegath
Alan W. Farquharson
Dori A. Ginn
David P. Poole
Chad L. Stephens
Rodney L. Waller

Position

2014

Officer
Age
Since
65 1995 Director
78 2001 Lead Independent Director
68 1994 Director
65 2008 Director
Director
60
66 2002 Director
68 2013 Director
55 2005 Director
60 1990 Director
57 2003 Chairman, President and Chief Executive Officer
57 2003 Executive Vice President – Chief Financial Officer
57 2010 Executive Vice President – Chief Operating Officer
66
57 2007 Senior Vice President – Reservoir Engineering & Economics
57
52 2008 Senior Vice President – General Counsel and Corporate Secretary
59 1990 Senior Vice President – Corporate Development
65 1999 Senior Vice President and Assistant Secretary

Senior Vice President – Southern Marcellus Shale

Senior Vice President – Controller and Principal Accounting Officer

2014

2009

Anthony V. Dub became a director in 1995. Mr. Dub is Chairman of Indigo Capital, LLC, a financial advisory firm

based in New York. Before forming Indigo Capital in 1997, he served as an officer of Credit Suisse First Boston (“CSFB”).
Mr. Dub joined CSFB in 1971 and was named a Managing Director in 1981. Mr. Dub led a number of departments during his
26 year career at CSFB including the Investment Banking Department. After leaving CSFB, Mr. Dub became Vice Chairman
and a director of Capital IQ, Inc. until its sale to Standard & Poor’s in 2004. Capital IQ is a leader in helping organizations
capitalize on synergistic integration of market intelligence, institutional knowledge and relationships. Mr. Dub received a
Bachelor of Arts degree, magna cum laude, from Princeton University.

V. Richard Eales became a director in 2001 and was elected as Lead Independent Director in 2008. Mr. Eales has over

45 years of experience in the energy, technology and financial industries. He is currently retired, having been a financial
consultant serving energy and information technology businesses from 1999 through 2002. Mr. Eales was employed by
Union Pacific Resources Group Inc. from 1991 to 1999 serving as Executive Vice President from 1995 through 1999. Before
1991, Mr. Eales served in various financial capacities with Butcher & Singer and Janney Montgomery Scott, investment
banking firms, as CFO of Novell, Inc., a technology company, and in the treasury department of Mobil Oil Corporation.
Mr. Eales received his Bachelor of Chemical Engineering degree from Cornell University and his Master’s degree in
Business Administration from Stanford University.

Allen Finkelson became a director in 1994. Mr. Finkelson was a partner at Cravath, Swaine & Moore LLP from 1977

to 2011, with the exception of the period 1983 through 1985, when he was a managing director of Lehman Brothers Kuhn
Loeb Incorporated. Mr. Finkelson joined Cravath, Swaine & Moore LLP in 1971. Mr. Finkelson earned a Bachelor of Arts
from St. Lawrence University and a J.D. from Columbia University School of Law.

James M. Funk became a director in December 2008. Mr. Funk is an independent consultant and producer with over 30

years of experience in the energy industry. Mr. Funk served as Sr. Vice President of Equitable Resources and President of
Equitable Production Co. from June 2000 until December 2003 and has been an independent consultant and oil and gas
producer since that time. Previously, Mr. Funk was employed by Shell Oil Company for 23 years in senior management and
technical positions. Mr. Funk has previously served on the boards of Westport Resources (2000 to 2004) and Matador
Resources Company (2003 to 2008). Mr. Funk currently serves as a Director of Superior Energy Services, Inc., a public oil
field services company headquartered in New Orleans, Louisiana. Mr. Funk received a B.A. degree in Geology from
Wittenberg University, a M.S. in Geology from the University of Connecticut, and a PhD in Geology from the University of
Kansas. Mr. Funk is a Certified Petroleum Geologist.

Christopher A. Helms became a director in July 2014. Mr. Helms is an independent consultant with over 36 years of
experience in the energy industry, principally in the midstream sector. He is the founder and prior to his retirement in 2012,
he was the Chief Executive Officer of US Shale Energy Advisors LLC. Prior to his retirement from US Shale Energy
Advisors LLC, Mr. Helms was Executive Vice President and Group Chief Executive Officer of NiSource Inc. From 2005 to
2011, he served as Chief Executive Officer and Executive Director of NiSource Gas Transmission and Storage. Prior to
joining NiSource, from 1999 to 2003, Mr. Helms was the President and Chief Executive Officer of CMS Panhandle
Companies, wholly-owned by CMS Energy Corporation. From 1990 to 1999, Mr. Helms held various positions with Duke
Energy Corporation and predecessors PanEnergy Corp. and Associated Natural Gas Inc. Mr. Helms serves as a director of
MPLX GP LLC, a publicly traded midstream crude oil and refined products pipeline; Questar Corporation, an integrated
natural gas company that develops, produces and delivers natural gas and Coskata, Inc, a renewable energy company. Mr.
Helms is a member of the University of Houston Board of Visitors. He has previously served on the boards of the
Millennium Pipeline Company LLC and Centennial Pipeline Company LLC and as a director of the Marcellus Shale
Coalition, the Commonwealth of Pennsylvania Marcellus Shale Advisory Commission and as Vice Chair of the Interstate
Natural Gas Association of America and Chair of the Southern Gas Association. Mr. Helms received a Bachelor of Arts
from Southern Illinois University and a Juris Doctor from Tulane University School of Law.

Jonathan S. Linker became a director in 2002. Mr. Linker previously served as a director of Range from 1998 to 2000.

He has been active in the energy industry for over 37 years. Mr. Linker joined First Reserve Corporation in 1988 and was a
Managing Director of the firm from 1996 through 2001. Mr. Linker is currently Manager of Houston Energy Advisors LLC,
an investment advisor providing management and investment services to two private equity funds. Mr. Linker has been
President and a director of IDC Energy Corporation since 1987, a director and officer of Sunset Production Corporation since
1991 serving currently as Chairman. Mr. Linker is also on the board of Flex Energy, Inc., and a Manager of Crescent Energy
Services and Stonegate Production Company, LLC. Mr. Linker received a Bachelor of Arts in Geology from Amherst
College, a Masters in Geology from Harvard University and an MBA from Harvard Graduate School of Business
Administration.

Mary Ralph Lowe became a director in 2013. Ms. Lowe has been president and chief executive officer of Maralo, LLC,
(formerly Maralo, Inc.), an independent oil and gas exploration and production company, and ranching operation, since 1973,
and a member of its board of directors since 1975. Ms. Lowe was appointed by the Company as a director effective April 1,
2013. Ms. Lowe also serves on the Board of Trustees of Texas Christian University, the Board of the Performing Arts Center
of Fort Worth, the Board of the National Cowgirl Museum and Hall of Fame, and the Board of The Modern Art Museum of
Fort Worth. Ms. Lowe previously served on the Board of Apache Corporation, a large oil and gas exploration company.

Kevin S. McCarthy became a director in 2005. Mr. McCarthy is Chairman, Chief Executive Officer and President of

Kayne Anderson MLP Investment Company, Kayne Anderson Energy Total Return Fund, Inc., Kayne Anderson
Midstream/Energy Fund, Inc. and Kayne Anderson Energy Development Company, which are each NYSE listed closed-end
investment companies. Mr. McCarthy joined Kayne Anderson Capital Advisors as a Senior Managing Director in 2004 from
UBS Securities LLC where he was global head of energy investment banking. In this role, he had senior responsibility for all
of UBS’ energy investment banking activities, including direct responsibilities for securities underwriting and mergers and
acquisitions in the energy industry. From 1995 to 2000, Mr. McCarthy led the energy investment banking activities of Dean
Witter Reynolds and then PaineWebber Incorporated. He began his investment banking career in 1984. He is also on the
board of directors of Emerge Energy Services, L.P. He earned a Bachelor of Arts in Economics and Geology from Amherst
College and an MBA in Finance from the University of Pennsylvania’s Wharton School.

John H. Pinkerton, became a director in 1988 and was elected Chairman of the Board of Directors in 2008. Mr.
Pinkerton previously served as Non-Executive Chairman until January 1, 2015. He joined Range as President in 1990 and
was appointed Chief Executive Officer in 1992. Previously, Mr. Pinkerton was employed by Snyder Oil Corporation, serving
in numerous capacities, the last of which was Senior Vice President. Mr. Pinkerton currently serves on the Board of Trustees
of Texas Christian University. Mr. Pinkerton received his Bachelor of Arts in Business Administration from Texas Christian
University and a Master’s degree from the University of Texas at Arlington.

Jeffrey L. Ventura, Chairman, President and Chief Executive Officer, joined Range in 2003 as Chief Operating Officer

and became a director in 2005. Mr. Ventura was named President effective May, 2008, Chief Executive Officer effective
January 1, 2012 and named Chairman of the Board on January 1, 2015. Previously, Mr. Ventura served as President and
Chief Operating Officer of Matador Petroleum Corporation which he joined in 1997. Prior to his service at Matador,
Mr. Ventura spent eight years at Maxus Energy Corporation where he managed various engineering, exploration and
development operations and was responsible for coordination of engineering technology. Previously, Mr. Ventura was with
Tenneco Oil Exploration and Production, where he held various engineering and operating positions. Mr. Ventura holds a
Bachelor of Science degree in Petroleum and Natural Gas Engineering from the Pennsylvania State University. Mr. Ventura
is also on the Board of America’s Natural Gas Alliance and is a member of the Society of Petroleum Engineers, American
Association of Petroleum Geologists and the Texas Society of Professional Engineers.

Roger S. Manny, Executive Vice President – Chief Financial Officer. Mr. Manny joined Range in 2003. Previously,
Mr. Manny served as Executive Vice President and Chief Financial Officer of Matador Petroleum Corporation from 1998
until joining Range. Before 1998, Mr. Manny spent 18 years at Bank of America and its predecessors where he served as
Senior Vice President in the energy group. Mr. Manny holds a Bachelor of Business Administration degree from the
University of Houston and a Masters of Business Administration from Houston Baptist University.

Ray N. Walker, Jr., Executive Vice President – Chief Operating Officer, joined Range in 2006 and was elected to his
current position in January 2014. Previously, Mr. Walker served as Senior Vice President – Chief Operating Officer, Senior
Vice President-Environment, Safety and Regulatory and Senior Vice President-Marcellus Shale where he led the
development of the Company’s Marcellus Shale division. Mr. Walker is a Petroleum Engineer with more than 35 years of oil
and gas operations and management experience having previously been employed by Halliburton in various technical and
management roles, Union Pacific Resources and several private companies in which Mr. Walker served as an officer.
Mr. Walker has a Bachelor of Science degree in Agricultural Engineering from Texas A&M University.

John K. Applegath, Senior Vice President – Southern Marcellus Shale, joined Range in 2008 and was elected to his

current position in January 2014. Mr. Applegath previously served as Vice President – Southern Marcellus Shale Division.
Mr. Applegath has over 38 years of industry experience with Exxon, Champlin Petroleum, Union Pacific Resources, and has
served as President and Chief Operating Officer of Basic Resources and Division Operations Manager with Anadarko
Petroleum. Mr. Applegath served our country in the United States Army as a Chief Warrant Officer II while a helicopter pilot
in Vietnam. Mr. Applegath earned a Bachelor of Science degree in Chemical Engineering from the University of Houston.

Alan W. Farquharson, Senior Vice President – Reservoir Engineering & Economics, joined Range in 1998.

Mr. Farquharson has held the positions of Manager and Vice President of Reservoir Engineering before being promoted to
Senior Vice President –Reservoir Engineering in February 2007 and his current position in January 2012 with his assumption
of additional responsibilities for strategic allocation of capital. Previously, Mr. Farquharson held positions with Union Pacific
Resources including Engineering Manager Business Development – International. Before that, Mr. Farquharson held various
technical and managerial positions at Amoco and Hunt Oil. He holds a Bachelor of Science degree in Electrical Engineering
from the Pennsylvania State University.

Dori A. Ginn, Senior Vice President – Controller and Principal Accounting Officer, joined Range in 2001 and was

previously Vice President, Controller and Principal Accounting Officer. Ms. Ginn has held the positions of Financial
Reporting Manager, Vice President and Controller before being elected to Principal Accounting Officer in September 2009.
Prior to joining Range, she held various accounting positions with Doskocil Manufacturing Company and Texas Oil and Gas
Corporation. Ms. Ginn received a Bachelor of Business Administration in Accounting from the University of Texas at
Arlington. She is a certified public accountant.

David P. Poole, Senior Vice President – General Counsel and Corporate Secretary, joined Range in June 2008.
Mr. Poole has over 23 years of legal experience. From May 2004 until March 2008 he was with TXU Corp., serving last as
Executive Vice President – Legal, and General Counsel. Prior to joining TXU, Mr. Poole spent 16 years with Hunton &
Williams LLP and its predecessor, where he was a partner and last served as the Managing Partner of the Dallas office.
Mr. Poole graduated from Texas Tech University with a B.S. in Petroleum Engineering and received a J.D. magna cum laude
from Texas Tech University School of Law.

Chad L. Stephens, Senior Vice President – Corporate Development, joined Range in 1990. Before 2002, Mr. Stephens

held the position of Senior Vice President – Southwest. Previously, Mr. Stephens was with Duer Wagner & Co., an
independent oil and gas producer for approximately two years. Before that, Mr. Stephens was an independent oil operator in
Midland, Texas for four years. From 1979 to 1984, Mr. Stephens was with Cities Service Company and HNG Oil Company.
Mr. Stephens holds a Bachelor of Arts degree in Finance and Land Management from the University of Texas.

Rodney L. Waller, Senior Vice President and Assistant Secretary, joined Range in 1999. Mr. Waller served as
Corporate Secretary from 1999 until 2008. Previously, Mr. Waller was Senior Vice President of Snyder Oil Corporation.
Before joining Snyder, Mr. Waller was with Arthur Andersen. Mr. Waller is a certified public accountant and petroleum land
man. Mr. Waller received a summa cum laude Bachelor of Arts degree in Accounting from Harding University.

Section 16(a) Beneficial Ownership Reporting Compliance

See the material appearing under the heading “Section 16(a) Beneficial Ownership Reporting Compliance” in the

Range Proxy Statement for the 2015 Annual Meeting of Stockholders which is incorporated herein by reference.
Section 16(a) of the Exchange Act requires our directors, officers (including a person performing a principal policy-making
function) and persons who own more than 10% of a registered class of our equity securities to file with the SEC initial reports
of ownership and reports of changes in ownership of our common stock and other equity securities. Directors, officers and
10% holders are required by SEC regulations to send us copies of all of the Section 16(a) reports they file. Based solely on a
review of the copies of the forms sent to us and the representations made by the reporting persons to us, we believe that,
during the fiscal year ended December 31, 2014, our directors, officers and 10% holders complied with all filing

requirements under Section 16(a) of the Exchange Act., with the following exception: Mr. Pinkerton had a delinquent Form 4
filing on April 10, 2014 for a transaction occurring on January 1, 2014.

Code of Ethics

Code of Ethics. We have adopted a Code of Ethics that applies to our principal executive officer, principal financial

officer, principal accounting officer, or persons performing similar functions (as well as our directors and all other
employees). A copy is available on our website, www.rangeresources.com and a copy in print will be provided to any person
without charge, upon request. Such requests should be directed to the Corporate Secretary, 100 Throckmorton Street, Suite
1200, Fort Worth, Texas 76102 or by calling (817) 870-2601. We intend to disclose any amendments to or waivers of the
Code of Ethics on behalf of our President and Chief Executive Officer, Chief Financial Officer, Controller and persons
performing similar functions on our website, under the Corporate Governance caption, promptly following the date of such
amendment or waiver.

Identifying and Evaluating Nominees for Directors

See “Identifying and Evaluating Nominees for Directors, including Diversity Considerations” in the Range Proxy

Statement for the 2015 Annual Meeting of Stockholders, which is incorporated herein by reference.

Audit Committee

See the material under the heading “Audit Committee” in the Range Proxy Statement for the 2015 Annual Meeting of

Stockholders, which is incorporated herein by reference.

NYSE 303A Certification

The President and Chief Executive Officer of Range Resources Corporation made an unqualified certification to the

NYSE with respect to the Company’s compliance with the NYSE Corporate Governance listing standards on May 20, 2014.

ITEM 11. EXECUTIVE COMPENSATION

Information required by this item is incorporated by reference to such information as set forth in the Range Proxy

Statement for the 2015 Annual Meeting of Stockholders.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND

RELATED STOCKHOLDER MATTERS

Information required by this item is incorporated by reference to such information as set forth in the Range Proxy

Statement for the 2015 Annual Meeting of Stockholders.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Information required by this item is incorporated by reference to such information as set forth in the Range Proxy

Statement for the 2015 Annual Meeting of Stockholders.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information required by this item is incorporated by reference to such information as set forth in the Range Proxy

Statement for the 2015 Annual Meeting of Stockholders.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Documents filed as part of the report:

Financial Statements:

Page
Number

Index to Consolidated Financial Statements ............................................................................................................ F–1

Managements’ Report on Internal Control Over Financial Reporting ..................................................................... F–2

Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting ........... F–3

Report of Independent Registered Public Accounting Firm .................................................................................... F–4

Consolidated Balance Sheets as of December 31, 2014 and 2013 ........................................................................... F–5

Consolidated Statements of Income for the Years Ended December 31, 2014, 2013 and 2012 .............................. F–6

Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2014, 2013 and
2012 .....................................................................................................................................................................

F–7

Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012 ....................... F–8

Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2014, 2013 and 2012 ........ F–9

Notes to Consolidated Financial Statements ............................................................................................................ F–10

All other schedules are omitted because they are not applicable, not required, or because the required information is
included in the financial statements or related notes.

Exhibits:

(a) See Index of Exhibits on page 67 for a description of the exhibits filed as a part of this report.

GLOSSARY OF CERTAIN DEFINED TERMS

The terms defined in this glossary are used in this report.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volumes, used herein in reference to crude oil or other liquid
hydrocarbons.

Bcf. One billion cubic feet of gas.

Bcfe. One billion cubic feet of natural gas equivalents, based on a ratio of 6 mcf for each barrel of oil or NGLs, which reflects
relative energy content.

Btu. One British thermal unit.

development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic
horizon known to be productive.

dry hole. A well found to be incapable of producing oil or natural gas in sufficient economic quantities.

exploratory well. A well drilled to find oil or gas in an unproved area, to find a new reservoir in an existing field previously
found to be productive of oil and gas in another reservoir or to extend a known reservoir.

gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Mbbl. One thousand barrels of crude oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet of gas.

Mcf per day. One thousand cubic feet of gas per day.

Mcfe. One thousand cubic feet of natural gas equivalents, based on a ratio of 6 mcf for each barrel of oil or NGLs, which
reflects relative energy content.

Mmbbl. One million barrels of crude oil or other liquid hydrocarbons.

Mmbtu. One million British thermal units. A British thermal unit is the heat required to raise the temperature of one pound of
water from 58.5 to 59.5 degrees Fahrenheit.

Mmcf. One million cubic feet of gas.

Mmcfe. One million cubic feet of gas equivalents.

NGLs. Natural gas liquids.

net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells.

present value (PV). The present value of future net cash flows, using a 10% discount rate, from estimated proved reserves,
using constant prices and costs in effect on the date of the report (unless such prices or costs are subject to change pursuant to
contractual provisions). The after tax present value is the Standardized Measure.

productive well. A well that is producing oil or gas or that is capable of production.

proved developed non-producing reserves. Reserves that consist of (i) proved reserves from wells which have been
completed and tested but are not producing due to lack of market or minor completion problems which are expected to be
corrected and (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to
both the well log characteristics and analogous production in the immediate vicinity of the wells.

proved developed reserves. Proved 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 extracting equipment and infrastructure operational at the time of the reserve estimate if
the extraction is by means not involving a well.

proved reserves. The quantities of crude oil, natural gas and NGLs that geological and engineering data can estimate with
reasonable certainty to be economically producible within a reasonable time from known reservoirs under existing economic,
operating and regulatory conditions prior to the time at which contracts providing the right to operate expire, unless evidence
indicates that renewal is reasonably certain.

proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required for recompletion.

recompletion. The completion for production an existing well bore in another formation from that in which the well has been
previously completed.

reserve life. Proved reserves at a point in time divided by the then production rate (annually or quarterly).

royalty acreage. Acreage represented by a fee mineral or royalty interest which entitles the owner to receive free and clear of
all production costs a specified portion of the oil and gas produced or a specified portion of the value of such production.

royalty interest. An interest in an oil and gas property entitling the owner to a share of oil and natural gas production free of
costs of production.

Standardized Measure. The present value, discounted at 10%, of future net cash flows from estimated proved reserves after
income taxes, calculated holding prices and costs constant at amounts in effect on the date of the report (unless such prices or
costs are subject to change pursuant to contractual provisions) and otherwise in accordance with the Commission’s rules for
inclusion of oil and gas reserve information in financial statements filed with the Commission.

Tcfe. One trillion cubic feet of natural gas equivalents, with one barrel of NGLs or crude oil being equivalent to 6,000 cubic
feet of natural gas.

Unproved properties. Properties with no proved reserves.

working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the
property and a share of production, subject to all royalties, overriding royalties and other burdens, and to all costs of
exploration, development and operations, and all risks in connection therewith.

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 or other special recovery processes in order to achieve economic flow rates.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly

caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

SIGNATURES

RANGE RESOURCES CORPORATION

By:

/s/ JEFFREY L. VENTURA

Jeffrey L. Ventura
Chairman of the Board, President and
Chief Executive Officer
(principal executive officer)

Dated: February 24, 2015

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the

following persons on behalf of the registrant and in the capacity and on the dates indicated.

Signature

Capacity

Date

/s/ JEFFREY L. VENTURA
Jeffrey L. Ventura

Chairman of the Board, President and Chief Executive Officer February 24, 2015

(principal executive officer)

/s/ ROGER S. MANNY
Roger S. Manny

Executive Vice President and Chief Financial Officer
(principal financial officer)

February 24, 2015

/s/ DORI A. GINN
Dori A. Ginn

Senior Vice President, Controller and
Principal Accounting Officer

/s/ ANTHONY V. DUB
Anthony V. Dub

Director

February 24, 2015

Lead Independent Director

February 24, 2015

/s/ V. RICHARD EALES
V. Richard Eales

/s/ ALLEN FINKELSON
Allen Finkelson

/s/ JAMES M. FUNK
James M. Funk

Director

/s/ CHRISTOPHER A. HELMS
Christopher A. Helms

Director

/s/ JONATHAN S. LINKER
Jonathan S. Linker

Director

/s/ MARY RALPH LOWE
Mary Ralph Lowe

/s/ KEVIN S. MCCARTHY
Kevin S. McCarthy

/s/ JOHN H. PINKERTON
John H. Pinkerton

Director

February 24, 2015

RANGE RESOURCES CORPORATION

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Page
Number

Management’s Report on Internal Control Over Financial Reporting .................................................................... F–2

Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting .......... F–3

Report of Independent Registered Public Accounting Firm .................................................................................. F–4

Consolidated Balance Sheets as of December 31, 2014 and 2013 .......................................................................... F–5

Consolidated Statements of Income for the Years Ended December 31, 2014, 2013 and 2012 ............................. F–6

F–7

Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012 ...................... F–8

Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2014, 2013 and 2012 ....... F–9

Notes to Consolidated Financial Statements ........................................................................................................... F–10

F-1

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

To the Stockholders of
Range Resources Corporation:

Management is responsible for establishing and maintaining adequate internal control over financial reporting (as

defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Our internal control over financial reporting is
designed to provide reasonable assurance to management and the Board of Directors regarding the preparation and fair
presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting
may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to
the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate. Therefore, even those systems determined to be effective can provide only reasonable
assurance with respect to financial statement preparation and presentation. Management assessed the effectiveness of our
internal control over financial reporting as of December 31, 2014. In making this assessment, management used the criteria
set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control –
Integrated Framework (2013). Based on our assessment, we believe that, as of December 31, 2014, our internal control over
financial reporting is effective based on those criteria.

Ernst and Young, LLP, the independent registered public accounting firm that audited our financial statements included
in this annual report, has issued an attestation report on our internal control over financial reporting as of December 31, 2014.
This report appears on the following page.

By: /s/ JEFFREY L. VENTURA

By: /s/ ROGER S. MANNY

Jeffrey L. Ventura
Chairman, President and Chief Executive Officer

Roger S. Manny
Executive Vice President and Chief Financial Officer

Fort Worth, Texas
February 24, 2015

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC

ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Board of Directors and Stockholders of
Range Resources Corporation:

We have audited Range Resources Corporation’s internal control over financial reporting as of December 31, 2014,

based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (2013 framework) (the COSO criteria). Range Resources Corporation’s
management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the
effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal
Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial
reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United

States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material respects. Our audit included obtaining an
understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and
evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other
procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our
opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding

the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and
procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that
receipts and expenditures of the company are being made only in accordance with authorizations of management and
directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.

Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may
deteriorate.

In our opinion, Range Resources Corporation maintained, in all material respects, effective internal control over

financial reporting as of December 31, 2014 based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States), the consolidated balance sheets of Range Resources Corporation as of December 31, 2014 and 2013 and the related
consolidated statements of income, comprehensive income (loss), cash flows and stockholders’ equity, for each of the three
years in the period ended December 31, 2014 of Range Resources Corporation and our report dated February 24, 2015
expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Fort Worth, Texas
February 24, 2015

F-3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders of
Range Resources Corporation:

We have audited the accompanying consolidated balance sheets of Range Resources Corporation (the “Company”) as

of December 31, 2014 and 2013, and the related consolidated statements of income, comprehensive income (loss), cash flows
and stockholders’ equity for each of the three years in the period ended December 31, 2014. These financial statements are
the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements
based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts
and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated
financial position of Range Resources Corporation at December 31, 2014 and 2013, and the consolidated results of its
operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with U.S.
generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States), Range Resources Corporation’s internal control over financial reporting as of December 31, 2014, based on criteria
established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (2013 framework) and our report dated February 24, 2015 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Fort Worth, Texas
February 24, 2015

F-4

RANGE RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)

Assets
Current assets:

Cash and cash equivalents
Accounts receivable, less allowance for doubtful accounts of $2,719 and $2,494
Derivative assets
Deferred tax assets
Inventory and other

Total current assets

Derivative assets
Equity method investments
Natural gas and oil properties, successful efforts method

Accumulated depletion and depreciation

Other property and equipment

Accumulated depreciation and amortization

Other assets

Total assets

Liabilities
Current liabilities:

Accounts payable
Asset retirement obligations
Accrued liabilities
Accrued interest
Derivative liabilities
Deferred tax liabilities

Total current liabilities

Bank debt
Subordinated notes
Deferred tax liabilities
Derivative liabilities
Deferred compensation liabilities
Asset retirement obligations and other liabilities

Total liabilities

Commitments and contingencies

Stockholders' Equity
Preferred stock, $1 par 10,000,000 shares authorized, none issued and outstanding
Common stock, $0.01 par 475,000,000 shares authorized, 168,711,131 issued at
December 31, 2014 and 163,441,414 issued at December 31, 2013
Common stock held in treasury, 82,954 shares at December 31, 2014 and 98,520 shares
at December 31, 2013
Additional paid-in capital
Retained earnings
Accumulated other comprehensive income

Total stockholders' equity
Total liabilities and stockholders' equity

See accompanying notes.

F-5

December 31,

2014

2013

448 $
188,941
363,049
—
17,854
570,292
40,314
—
10,567,971
(2,590,398 )
7,977,573
127,808
(90,227 )
37,581
121,020
$ 8,746,780 $

348
179,667
4,421
51,414
12,451
248,301
9,233
129,034
9,032,881
(2,274,444)
6,758,437
118,625
(85,841)
32,784
121,297
7,299,086

396,942 $
15,067
187,973
39,695
—
115,587
755,264
723,000
2,350,000
997,494
—
178,599
284,994
5,289,351

258,431
5,037
161,520
44,375
26,198
—
495,561
500,000
2,640,516
771,980
25
247,537
229,015
4,884,634

—

1,687

1,634

(3,088 )
2,400,475
1,058,355
—
3,457,429
$ 8,746,780 $

(3,637)
1,959,636
450,583
6,236
2,414,452
7,299,086

RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per share data)

Revenues and other income:

Natural gas, NGLs and oil sales
Derivative fair value income (loss)
Gain on the sale of assets
Brokered natural gas, marketing and other

Total revenues and other income

Costs and expenses:
Direct operating
Transportation, gathering and compression
Production and ad valorem taxes
Brokered natural gas and marketing
Exploration
Abandonment and impairment of unproved properties
General and administrative
Termination costs
Deferred compensation plan
Interest expense
Loss on early extinguishment of debt
Depletion, depreciation and amortization
Impairment of proved properties and other assets

Total costs and expenses

Income before income taxes
Income tax expense (benefit):

Current
Deferred

Net income

Net income per common share:

Basic
Diluted

Weighted average common shares outstanding:

Basic
Diluted

Year Ended December 31,
2013

2012

2014

1,911,989 $ 1,715,676 $
(61,825 )
92,291
116,577
1,862,719

383,520
285,638
130,548
2,711,695

1,351,694
41,437
49,132
15,441
1,457,704

150,483
325,289
44,555
129,980
63,548
47,079
213,426
8,371
(74,550)
168,977
24,596
551,032
28,024
1,680,810

128,091
256,242
45,240
131,786
64,409
51,918
291,171
—
55,296
176,557
12,280
492,397
7,753
1,713,140

115,905
192,445
67,120
20,434
69,807
125,278
173,813
—
7,203
168,798
11,063
445,228
35,554
1,432,648

1,030,885

149,579

25,056

1
396,502
396,503

(143 )
34,000
33,857

(1,778)
13,832
12,054

634,382 $

115,722 $

13,002

3.81 $
3.79 $

0.71 $
0.70 $

0.08
0.08

163,625
164,403

160,438
161,407

159,431
160,307

$
$

See accompanying notes.

F-6

RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)

Net income
Other comprehensive income:

December 31,

2014
634,382 $

2013
115,722 $ 13,002

2012

Realized gain on hedge derivative contract settlements reclassified into natural gas,

NGLs and oil sales from other comprehensive income, net of taxes (1)

De-designated hedges reclassified into natural gas, NGLs and oil sales, net of taxes (2)
De-designated hedges reclassified to derivative fair value, net of taxes (3)
Change in unrealized deferred hedging (losses) gains, net of taxes (4)

Total comprehensive income (loss)

—
(6,236 )
—
—
628,146 $

(14,840) (144,434)
—
(56,254)
—
(2,376)
(4,203)
71,716
38,049 $ (59,716)

(1) Amounts are net of income tax benefit of $9,488 for the year ended December 31, 2013 compared to $91,871 for the year ended

December 31, 2012.

(2) Amounts are net of income tax benefit of $3,986 for the year ended December 31, 2014 compared to $35,968 for the year ended

December 31, 2013.

(3) Amounts relate to transactions not probable of occurring and are presented net of income tax benefit of $1,517 for the year ended

December 31, 2013.

(4) Amounts are net of income tax benefit of $2,687 for the year ended December 31, 2013 compared to income tax expense of $47,466 for

the year ended December 31, 2012.

See accompanying notes.

F-7

RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)

Operating activities:
Net income
Adjustments to reconcile net income to net cash provided from operating activities:

Loss (gain) from equity method investments, net of distributions
Deferred income tax expense
Depletion, depreciation and amortization and impairment
Exploration dry hole and impairment costs
Abandonment and impairment of unproved properties
Derivative fair value (income) loss
Cash settlements on derivative financial instruments that do not qualify for
hedge accounting
Allowance for bad debt
Amortization of deferred financing costs, loss on extinguishment of debt and other
Deferred and stock-based compensation
Gain on the sale of assets
Changes in working capital:
Accounts receivable
Inventory and other
Accounts payable
Accrued liabilities and other

Net cash provided from operating activities

Investing activities:

Additions to natural gas and oil properties
Additions to field service assets
Acreage purchases
Equity method investments
Proceeds from disposal of assets
Purchases of marketable securities held by the deferred compensation plan
Proceeds from the sales of marketable securities held by the deferred

compensation plan

Net cash used in investing activities

Financing activities:

Borrowings on credit facilities
Repayments on credit facilities
Issuance of subordinated notes
Repayment of subordinated notes
Dividends paid
Debt issuance costs
Issuance of common stock
Change in cash overdrafts
Proceeds from the sales of common stock held by the deferred compensation plan

Net cash provided from financing activities

Increase in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year

2014

Year Ended December 31,
2013

2012

634,382 $

115,722 $

13,002

3,095
396,502
579,056
16,145
47,079
(383,520)

(42,634)
250
24,694
(4,295)
(285,638)

(5,329)
(4,521)
(1,023)
(20,108)
954,135

(2,973 )
34,000
500,150
5,699
51,918
61,825

(31,256 )
250
23,866
119,398
(92,291 )

(21,212 )
3,785
(13,555 )
(11,788 )
743,538

5,670
13,832
480,782
841
125,278
(41,437)

38,700
750
23,165
60,136
(49,132)

(38,017)
(7,376)
13,654
7,251
647,099

(1,200,419)
(11,863)
(211,971)
1,103
180,508
(30,898)

(1,159,252 )
(5,925 )
(132,145 )
3,799
315,522
(36,136 )

(1,498,628)
(4,762)
(191,065)
—
168,219
(60,406)

28,084
(1,245,456)

30,701
(983,436 )

58,084
(1,528,558)

2,107,000
(1,884,000)
—
(312,000)
(26,610)
(8,866)
396,562
3,371
15,964
291,421
100
348
448 $

1,684,000
(1,923,000 )
750,000
(259,063 )
(26,129 )
(12,448 )
343
5,610
20,681
239,994
96
252
348 $

1,773,000
(1,221,000)
600,000
(259,375)
(25,981)
(12,605)
2,073
(1,126)
26,633
881,619
160
92
252

See accompanying notes.

F-8

RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands, except per share data)

Common stock

Shares Par value

Common stock
held in
treasury

Additional paid- Retained
earnings

in capital

Accumulated
other

comprehensive
income (loss)

Total

1,866,554 $
20,251
30,405

373,969 $
—
—

156,627 $ 2,392,420
20,264
30,405

—
—

—

(25,981 )

—

(25,981)

(1,583)
—
—
1,915,627
9,281
35,851

—
—
13,002
360,990
—
—

—
(72,718)
—

—
(72,718)
13,002
83,909 2,357,392
9,289
35,851

—
—

—

(26,129 )

—

(26,129)

(1,123)
—
—
1,959,636
398,554
42,834

—
—
115,722
450,583
—
—

—
(77,673)
—

—
(77,673)
115,722
6,236 2,414,452
398,607
42,834

—
—

—

(26,610 )

—

(26,610)

(549)
—
—
2,400,475 $

—
—
634,382
1,058,355 $

—
—
(6,236)
(6,236)
—
634,382
— $ 3,457,429

Balance as of December 31, 2011

Issuance of common stock
Stock-based compensation expense
Common dividends declared ($0.16 per
share)
Treasury stock issuance
Other comprehensive loss

Net income

Balance as of December 31, 2012

Issuance of common stock
Stock-based compensation expense
Common dividends declared ($0.16 per
share)
Treasury stock issuance
Other comprehensive loss

Net income

Balance as of December 31, 2013

Issuance of common stock
Stock-based compensation expense
Common dividends declared ($0.16 per
share)
Treasury stock issuance
Other comprehensive loss

Net income

Balance as of December 31, 2014

161,303 $
1,339
—

1,613 $
13
—

—

—
—
—
162,642
799
—

—
—
—
1,626
8
—

—

—
—
—
163,441
5,270
—

—
—
—
1,634
53
—

—

—
—
—
168,711 $

—
—
—
1,687 $

(6,343) $
—
—

—

1,583
—
—
(4,760)
—
—

—

1,123
—
—
(3,637)
—
—

—

549
—
—
(3,088) $

See accompanying notes.

F-9

RANGE RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) SUMMARY OF ORGANIZATION AND NATURE OF BUSINESS

Range Resources Corporation (“Range,” “we,” “us,” or “our”) is a Fort Worth, Texas-based independent natural gas,

NGLs and oil company primarily engaged in the exploration, development and acquisition of natural gas and oil properties in
the Appalachian and Midcontinent regions of the United States. Our objective is to build stockholder value through consistent
growth in reserves and production on a cost-efficient basis. Range is a Delaware corporation with our common stock listed
and traded on the New York Stock Exchange under the symbol “RRC.”

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation and Principles of Consolidation

The accompanying consolidated financial statements include the accounts of all of our subsidiaries. Investments in

entities over which we have significant influence, but not control, are accounted for using the equity method of accounting
and are carried at our share of net assets plus loans and advances. Income from equity method investments represents our
proportionate share of income generated by equity method investees and is included in brokered natural gas, marketing and
other revenues in the accompanying consolidated statements of income. As of June 16, 2014, we no longer have income or
loss from equity method investments. All material intercompany balances and transactions have been eliminated.

Use of Estimates

The preparation of financial statements in accordance with generally accepted accounting principles in the United
States requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure
of contingent assets and liabilities as of the date of the consolidated financial statements, and the reported amounts of
revenues and expenses during the reporting periods. Actual results could differ from these estimates and changes in these
estimates are recorded when known.

Business Segment Information

We have evaluated how we are organized and managed and have identified only one operating segment, which is the

exploration and production of natural gas, NGLs and oil in the United States. We consider our gathering, processing and
marketing functions as ancillary to our natural gas and oil producing activities. Operating segments are defined as
components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate
operational financial information is available and this information is regularly evaluated by the chief operating decision
maker for the purpose of allocating resources and assessing performance.

We have a single company-wide management team that administers all properties as a whole rather than by discrete

operating segments. We track only basic operational data by area. We do not maintain complete separate financial statement
information by area. We measure financial performance as a single enterprise and not on an area-by-area basis. Throughout
the year, we allocate capital resources on a project-by-project basis, across our entire asset base to maximize profitability
without regard to individual areas.

Revenue Recognition, Accounts Receivable and Gas Imbalances

Natural gas, NGLs and oil sales are recognized when we deliver our production to the customer and collectability is
reasonably assured. We generally sell natural gas, NGLs and oil under two types of agreements, which are common in our
industry. Both types of agreements include transportation charges. We are reporting our gathering and transportation costs in
accordance with Financial Accounting Standard Board (“FASB”) Section 605-45-05 of Subtopic 605-45 for Revenue
Recognition. One type of agreement is a netback arrangement, under which we sell natural gas and oil at the wellhead and
collect a price, net of transportation incurred by the purchaser. In this case, we record revenue at the price we received from
the purchaser. In the case of NGLs, we receive a price from the purchaser (which is net of processing costs) which is
recorded in revenue at the net price we receive. Under the other arrangement, we sell natural gas or oil at a specific delivery
point, pay transportation, gathering and compression expenses to a third party and receive proceeds from the purchaser with
no deduction. In that case, we record revenue at the price received from the purchaser and record the expenses we incur as
transportation, gathering and compression expense.

We realize brokered margins as a result of buying and selling natural gas utilizing separate purchase and sale
transactions, typically with separate counterparties, whereby Range or the counterparty takes titles to the natural gas
purchased or sold. Revenues and expenses related to brokering natural gas are reported gross as part of revenue and expense
in accordance with applicable accounting standards. In 2013, we purchased (and sold) natural gas which was used to blend

F-10

our rich residue gas from the Southwest Marcellus Shale. In 2014, we also reported a margin from the release of
transportation capacity where we have taken firm transportation ahead of our production volumes. Our brokered margin was
a gain of $9.4 million in 2014 compared to a loss of $5.7 million in 2013. The amount of brokered margin was immaterial in
2012.

Although receivables are concentrated in the oil and gas industry, we do not view this as an unusual credit risk. We
provide for an allowance for doubtful accounts for specific receivables judged unlikely to be collected based on the age of the
receivable, our experience with the debtor, potential offsets to the amount owed and economic conditions. In certain
instances, we require purchasers to post stand-by letters of credit. Many of our receivables are from joint interest owners of
properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment
of joint interest billings. We have allowances for doubtful accounts relating to exploration and production receivables of $2.7
million at December 31, 2014 compared to $2.5 million at December 31, 2013. We recorded bad debt expense of $250,000 in
both the year ended December 31, 2014 and 2013 compared to $750,000 in 2012.

Revenues from the production of natural gas, NGLs and oil on properties in which we have joint ownership are
recorded under the sales method. Under the sales method, we and other joint owners may sell more or less than our entitled
share of production. Should our sales exceed our share of remaining reasonable reserves, a liability is recorded. At
December 31, 2014, we had recorded a net liability of $52,000 for those wells where it was determined that there were
insufficient reserves to recover the imbalance.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with
maturities of three months or less. Outstanding checks in excess of funds on deposit are included in accounts payable on the
consolidated balance sheets and the change in such overdrafts are classified as financing activities on the consolidated
statements of cash flows.

Marketable Securities

Investments in unaffiliated equity securities held in our deferred compensation plans qualify as trading securities and

are recorded at fair value. Investments held in the deferred compensation plans consist of various publicly-traded mutual
funds. These funds include equity securities and money market instruments.

Inventory

Inventories were comprised of $11.8 million of materials and supplies at December 31, 2014 compared to $9.6 million

at December 31, 2013. Inventories consist primarily of tubular goods used in our operations and are stated at the lower of
specific cost of each inventory item or market, on a first-in, first-out basis. Our material and supplies inventory is primarily
acquired for use in future drilling operations or repair operations. At December 31, 2014, we also had propane and ethane
commodity inventory of $2.0 million, which is carried at lower of average cost or market, on a first-in, first-out basis. We had
no commodity inventory as of December 31, 2013.

Natural Gas and Oil Properties
Property Acquisition Costs

We use the successful efforts method of accounting for natural gas and oil producing activities. Costs to drill

exploratory wells that do not find proved reserves, geological and geophysical costs, delay rentals and costs of carrying and
retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves that cannot yet be
classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a
producing well and (b) we are making sufficient progress assessing the reserves and the economic and operating viability of
the project. The status of suspended well costs is monitored continuously and reviewed not less than quarterly. We capitalize
successful exploratory wells and all developmental wells, whether successful or not. Due to the capital-intensive nature and
the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an
exploration project and the economics associated with making a determination on its commercial viability. In these instances,
the project’s feasibility is not contingent upon price improvements or advances in technology, but rather our ongoing efforts
and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to
other companies’ production data in the area, transportation or processing facilities and/or obtaining partner approval to drill
additional appraisal wells. These activities are ongoing and are being pursued constantly. Consequently, our assessment of
suspended exploratory well costs is continuous until a decision can be made that the project has found proved reserves to
sanction the project or is noncommercial and is charged to exploration expense. For more information regarding suspended
exploratory well costs, see Note 6.

F-11

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization of proved producing properties, including other property and equipment such

as gathering lines related to natural gas and oil producing activities, is provided on the units of production method.
Historically, we have adjusted our depletion rates in the fourth quarter of each year based on the year-end reserve report and
at other times during the year when circumstances indicate there has been a significant change in reserves or costs.

Impairments

Our proved natural gas and oil properties are reviewed for impairment periodically as events or changes in

circumstances indicate that the carrying amount of an asset may not be recoverable. These assets are reviewed for potential
impairment at the lowest level for which there are identifiable cash flows that are largely independent of other groups of
assets which is the level at which depletion is calculated. The review is done by determining if the historical cost of proved
properties less the applicable accumulated depreciation, depletion and amortization is less than the estimated expected
undiscounted future net cash flows. The expected future net cash flows are estimated based on our plans to produce and
develop reserves. Expected future net cash inflow from the sale of produced reserves is calculated based on estimated future
prices and estimated operating and development costs. We estimate prices based upon market-related information including
published futures prices. The estimated future level of production, which is based on proved and risk adjusted probable and
possible reserves, has assumptions surrounding the future levels of prices and costs, field decline rates, market demand and
supply, and the economic and regulatory climate. In certain circumstances, we also consider potential sales of properties to
third parties in our estimates of cash flows. When the carrying value exceeds the sum of undiscounted future net cash flows,
an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted
future net cash flows using a discount rate similar to that used by market participants) and the carrying value of the asset. A
significant amount of judgment is involved in performing these evaluations since the results are based on estimated future
events. Such events include a projection of future natural gas and oil prices, an estimate of the ultimate amount of recoverable
natural gas and oil reserves that will be produced from an asset group, the timing of future production, future production
costs, future abandonment costs and future inflation. We cannot predict whether impairment charges may be required in the
future. If natural gas, NGLs and oil prices decrease or drilling efforts are unsuccessful, we may be required to record
additional impairments. For additional information regarding proved property impairments, see Note 11.

We evaluate our unproved property investment periodically for impairment. The majority of these costs generally relate

to the acquisition of leasehold costs. The costs are capitalized and evaluated (at least quarterly) as to recoverability, based on
changes brought about by economic factors and potential shifts in business strategy employed by management. Impairment
of a significant portion of our unproved properties is assessed and amortized on an aggregate basis based on our average
holding period, expected forfeiture rate and anticipated drilling success. Impairment of individually significant unproved
property is assessed on a property-by-property basis considering a combination of time, geologic and engineering factors.
Unproved properties had a net book value of $943.2 million as of December 31, 2014 compared to $807.0 million in 2013.
We have recorded abandonment and impairment expense related to unproved properties of $47.1 million in the year ended
December 31, 2014 compared to $51.9 million in 2013 and $125.3 million in 2012.

Dispositions

Proceeds from the disposal of natural gas and oil producing properties that are part of an amortization base are credited

to the net book value of the amortization group with no immediate effect on income. However, gain or loss is recognized if
the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization
base.

Acquisitions

Acquisitions of proved properties are accounted for as business combinations and, accordingly, the results of
operations are included in the accompanying consolidated statements of income from the closing date of the acquisition.
Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at the time of the
acquisition. In the past, acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and
equity securities.

Other Property and Equipment

Other property and equipment includes such as buildings, furniture and fixtures, field equipment, leasehold
improvements and data processing and communication equipment. These items are generally depreciated by individual
components on a straight-line basis over their economic useful life, which is generally from three to ten years. Leasehold
improvements are amortized over the lesser of their economic useful lives or the underlying terms of the associated leases.

F-12

Depreciation expense was $12.9 million in the year ended December 31, 2014 compared to $13.2 million in both 2013 and
2012.

Other Assets

The expenses of issuing debt are capitalized and included in other assets in the accompanying consolidated balance
sheets. These costs are amortized over the expected life of the related instruments. When debt is retired before maturity or
modifications significantly change the cash flows, the related unamortized costs are expensed. Other assets at December 31,
2014 include $42.2 million of unamortized debt issuance costs, $68.5 million of marketable securities held in our deferred
compensation plans and $10.3 million of other investments including surface acreage. Other assets at December 31, 2013
include $44.5 million of unamortized debt issuance costs, $67.8 million of marketable securities held in our deferred
compensation plans and $9.0 million of other investments including surface acreage.
Stock-based Compensation Arrangements

The fair value of performance share unit awards (“PSUs”) is estimated on the date of grant using the Monte Carlo
simulation method. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of
satisfying the market condition stipulated in the award grant. The fair value of stock-settled stock appreciation rights
(“SARs”) is estimated on the date of grant using the Black-Scholes-Merton option-pricing model. The models employ
various assumptions, based on management’s best estimates at the time of the grant, which impact the fair value calculated
and ultimately, the expense that is recognized over the life of the awards. We have utilized historical data and analyzed
current information to reasonably support these assumptions. The fair value of restricted stock awards (“Liability Awards”)
and restricted stock unit awards (“Equity Awards”) is determined based on the fair market value of our common stock on the
date of grant.

We recognize stock-based compensation expense on a straight-line basis over the requisite service period for the entire

award. The expense we recognize is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience
and adjust it as circumstances warrant. Substantially all Liability Awards are deposited in our deferred compensation plans at
the time of grant and are classified as a liability due to the fact that these awards are expected to be settled wholly or partially
in cash. The fair value of the Liability Awards is updated at each balance sheet date with changes in the fair value of the
vested portion of the awards recorded as increases or decreases to deferred compensation plan expense in the accompanying
consolidated statements of income.

Derivative Financial Instruments and Hedging

All of our derivative instruments are issued to manage the price risk attributable to our expected natural gas, NGLs and
oil production. While there is risk that the financial benefit of rising natural gas, NGLs and oil prices may not be captured, we
believe the benefits of stable and predictable cash flow are more important. Among these benefits are more efficient
utilization of existing personnel and planning for future staff additions, the flexibility to enter into long-term projects
requiring substantial committed capital, smoother and more efficient execution of our ongoing development drilling and
production enhancement programs, more consistent returns on invested capital and better access to bank and other capital
markets. All unsettled derivative instruments are recorded in the accompanying consolidated balance sheets as either an asset
or a liability measured at its fair value. In most cases, our derivatives are reflected on our consolidated balance sheets on a net
basis by brokerage firm, when they are governed by master netting agreements. Changes in a derivative’s fair value are
recognized in earnings unless specific hedge accounting criteria are met. Cash flows from derivative contract settlements are
reflected in operating activities in the accompanying consolidated statements of cash flows.

Effective March 1, 2013, we elected to discontinue hedge accounting prospectively. For more information, see Note

10. The effective portions of the discontinued deferred hedges as of March 1, 2013 were included in accumulated other
comprehensive income (“AOCI”) and were transferred to earnings during the same periods in which the forecasted
transactions were recognized in earnings. During 2014, the remaining AOCI hedging gains were transferred to earnings.
Since discontinuing hedge accounting, all realized and unrealized gains and losses on derivatives are accounted for using the
mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in
each period in derivative fair value in the accompanying consolidated statements of income. At times, we have also entered
into basis swap agreements, which do not qualify for hedge accounting and are marked to market. The price we receive for
our gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative
quality and other factors; therefore, we have entered into basis swap agreements that effectively fix our basis adjustments.

From time to time, we may enter into derivative contracts and pay or receive premium payments at the inception of the
derivative contract which represent the fair value of the contract at its inception. These amounts would be included within the
net derivative asset or liability on our consolidated balance sheets. The amounts paid or received for derivative premiums
reduce or increase the amounts of gains and losses that are recorded in the earnings each period as the derivative contracts

F-13

settle. We have not acquired any hedges through a business combination and have not modified any existing derivative
contracts.

Concentrations of Credit Risk

As of December 31, 2014, our primary concentrations of credit risk are the risks of collecting accounts receivable and
the risk of counterparties’ failure to perform under derivative contracts. Most of our receivables are from a diverse group of
companies, including major energy companies, pipeline companies, local distribution companies, financial institutions and
end-users in various industries and are generally unsecured. To manage risks of collecting accounts receivable, we monitor
our counterparties financial strength and/or credit ratings and where we deem necessary, obtain parent company guaranties,
prepayments, letters of credit or other credit enhancements to reduce risk of loss. Our allowance for uncollectible receivables
was $2.7 million at December 31, 2014 compared to $2.5 million at December 31, 2013.

For the year ended December 31, 2014, we had four customers that accounted for 10% or more of total natural gas,

NGLs and oil sales. For the year ended December 31, 2013, we had four customers that accounted for 10% or more of total
natural gas, NGLs and oil sales. For the year ended December 31, 2012, we had two customers that accounted for 10% or
more of total natural gas, NGLs and oil sales. We believe that the loss of any one customer would not have an adverse effect
on our ability to sell our natural gas, NGLs and oil production.

We have executed International Swap Dealers Association Master Agreements (“ISDA Agreements”) with

counterparties for the purpose of entering into derivative contracts. To manage counterparty risk associated with our
derivatives, we select and monitor counterparties based on assessment of their financial strength and/or credit ratings. We
may also limit the level of exposure with any single counterparty. Additionally, the terms of our ISDA Agreements provide
us and our counterparties with netting rights such that we may offset payables against receivables with a counterparty under
separate derivative contracts. Our ISDA Agreements also generally contain set-off rights such that, upon the occurrence of
defined acts of default by either us or a counterparty to a derivative contract, the non-defaulting party may set off receivables
owed under all derivative contracts against payables from other agreements with that counterparty. None of our derivative
contracts have margin requirements or collateral provisions that would require Range to fund or post additional collateral
prior to the scheduled cash settlement date.

At December 31, 2014, our derivative counterparties included fifteen financial institutions, of which all but one are
secured lenders in our bank credit facility. At December 31, 2014, our net derivative asset includes a receivable from the
counterparty not included in our bank credit facility totaling $30.3 million. In determining fair value of derivative assets, we
evaluate the risk of non-performance and incorporate factors such as amounts owed under other agreements permitting set
off, as well as pricing of credit default swaps for the counterparty. Net derivative liabilities are determined in part by using
our market based credit spread to incorporate Range’s theoretical risk of non-performance.

Asset Retirement Obligations

The fair value of asset retirement obligations is recognized in the period they are incurred, if a reasonable estimate of

fair value can be made. Asset retirement obligations primarily relate to the abandonment of natural gas and oil producing
facilities and include costs to dismantle and relocate or dispose of production platforms, gathering systems, wells and related
structures. Estimates are based on historical experience of plugging and abandoning wells, estimated remaining lives of those
wells based on reserve estimates, external estimates of the cost to plug and abandon the wells in the future and federal and
state regulatory requirements. We are required to operate and maintain our natural gas pipeline systems and intend to do so as
long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, these assets have
indeterminate lives. Depreciation of capitalized asset retirement costs will generally be determined on a units-of-production
basis while accretion to be recognized will escalate over the life of the producing assets.

Environmental Costs

Environmental expenditures are capitalized if the costs mitigate or prevent future contamination or if the costs improve

environmental safety or efficiency of the existing assets. Expenditures that relate to an existing condition caused by past
operations that have no future economic benefits are expensed.

Deferred Taxes

Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the
differences between the financial statement carrying amounts of assets and liabilities and their tax bases as reported in our
filings with the respective taxing authorities. Deferred tax assets are recorded when it is more likely than not that they will be
realized. The realization of deferred tax assets is assessed periodically based on several interrelated factors. These factors
include our expectation to generate sufficient taxable income in the periods before tax credits and operating loss

F-14

carryforwards expire. We do not recognize a deferred tax asset for excess tax benefits on equity compensation that have not
been realized due to our net operating loss tax position for federal or state tax purposes.

Accumulated Other Comprehensive Income

The following details the components of AOCI and related tax effects for the three years ended December 31, 2014.
Amounts included in AOCI exclusively relate to our derivative activity. See footnote 10 for additional information on the
discontinuance of hedge accounting (in thousands).

Accumulated other comprehensive income at December 31, 2011

Contract settlements reclassified to income
Change in unrealized deferred hedging gains

Gross

Tax Effect

Net of Tax

254,678 $
(236,305)
119,182

(98,051 ) $
91,871
(47,466 )

156,627
(144,434)
71,716

Accumulated other comprehensive income at December 31, 2012

Contract settlements reclassified to income
Change in unrealized deferred hedging losses

137,555
(120,443)
(6,890)

(53,646 )
46,973
2,687

83,909
(73,470)
(4,203)

Accumulated other comprehensive income at December 31, 2013

Contract settlements reclassified to income

10,222
(10,222)

(3,986 )
3,986

6,236
(6,236)

Accumulated other comprehensive income at December 31, 2014

⎯ $

⎯

Accounting Pronouncements Implemented
Recently Adopted

In February 2013, an accounting standards update was issued to provide guidance for the recognition, measurement,

and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the
obligation is fixed at the reporting date, except for obligations such as asset retirement and environmental obligations,
contingencies, guarantees, income taxes and retirement benefits, which are separately addressed within U.S. GAAP. An
entity is required to measure obligations resulting from joint and several liability arrangements for which the total amount of
the obligation is fixed at the reporting date as the sum of (1) the amount the entity agreed to pay on the basis of its
arrangement among its co-obligors and (2) any amount the entity expects to pay on behalf of its co-obligors. Disclosure of
the nature of the obligation, including how the liability arose, the relationship with other co-obligors and the terms and
conditions of the arrangement is required. In addition, the total outstanding amount under the arrangement, not reduced by
the effect of any amounts that may be recoverable from other entities, plus the carrying amount of any liability or receivable
recognized must be disclosed. This accounting standards update is effective for us beginning in first quarter 2014 and should
be applied retrospectively for those in-scope obligations resulting from joint and several liability arrangements that exist at
the beginning of 2014. Early adoption was permitted and we adopted this new standard in first quarter 2014 which did not
have an impact on our consolidated results of operations, financial position or cash flows.

In April 2014, an accounting standards update was issued that raised the threshold for a disposal to qualify as a

discontinued operation and requires new disclosures of both discontinued operations and certain other material disposal
transactions that do not meet the revised definition of a discontinued operation. Under the updated standard, a disposal of a
component or group of components of an entity is required to be reported as discontinued operations if the disposal
represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the
component or group of components of the entity (1) has been disposed of by a sale, (2) has been disposed of other than by
sale or (3) is classified as held for sale. This accounting standards update is effective for annual periods beginning on or after
December 15, 2014 and is applied prospectively. Early adoption is permitted but only for disposals (or classifications that are
held for sale) that have not been reported in financial statements previously issued or available for use. We adopted this new
standard in first quarter 2014 and, as a result, the Conger Exchange defined and described in more detail below, is not
reported as a discontinued operation.

Accounting Pronouncements Not Yet Adopted

In May 2014, an accounting standards update was issued for “Revenue from Contracts with Customers,” which

F-15

using either a full retrospective or modified approach to adopt this new standard. We are evaluating our existing revenue
recognition policies to determine whether any contracts will be affected by the new requirements.

In August 2014, the Financial Accounting Standards Board (“FASB”) issued an update that requires management to

assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are
currently in United States auditing standards. This standard is effective for us in first quarter 2017 and early adoption is
permitted. We do not expect the adoption of this standard to have any impact on our consolidated results of operations,
financial position or cash flows.

(3) ACQUISITIONS AND DISPOSITIONS

Conger Exchange Transaction

In April 2014, we entered into an exchange agreement with EQT Corporation and certain of its affiliates (collectively,
“EQT”) in which we sold our Conger assets in Glasscock and Sterling Counties, Texas in exchange for producing properties
and other EQT assets in Virginia and $145.0 million in cash, before closing adjustments (the “Conger Exchange”). We closed
the exchange transaction on June 16, 2014. The assets exchanged met the definition of a business under accounting standards
and was recorded at fair value. We recognized a pre-tax gain of $272.7 million related to this exchange, after selling expenses
of $5.0 million, which is recognized as a gain on sale of assets in our consolidated statements of income for the year ended
December 31, 2014. For the period from January 1, 2014 through June 16, 2014, we recognized $21.9 million of field net
operating net income (defined as natural gas, oil and NGLs sales and net brokered margin, less direct operating expenses,
production and ad valorem taxes and transportation expenses), compared to $48.7 million in the year ended December 31,
2013 and $40.2 million in the year ended December 31, 2012 for our Conger assets. The combined carrying amount of our
Conger assets prior to the exchange was $271.8 million. The following table presents the fair value of assets acquired and
liabilities assumed in the transaction (in thousands):

Consideration
Fair value of net assets transferred

Fair value of assets acquired and liabilities assumed

Cash
Working capital – Nora Gathering, LLC
Natural gas and oil properties
Transportation and field assets
Other liabilities-firm transportation contract
Asset retirement obligations

Fair value of net assets acquired and liabilities assumed

Conger
Exchange

550,273

151,675
12,731
402,176
7,793
(12,175)
(11,927)
550,273

In connection with the Conger Exchange, we acquired the remaining 50% interest held by EQT in Nora Gathering,

LLC (“NGLLC”), a natural gas gathering operation, which we had previously accounted for using the equity method of
accounting. As of June 16, 2014, we have consolidated NGLLC into our consolidated financial statements. Our previous 50%
membership interest in NGLLC was remeasured to fair value of $134.8 million on the acquisition date, resulting in a gain of
$10.0 million which is recognized in gain on sale of assets in our consolidated statements of income for the year ended
December 31, 2014. We assumed trade receivables as part of the acquisition of NGLLC of $5.5 million, all of which we
collected.

For the period from June 16, 2014 through December 31, 2014, we recognized $33.8 million of natural gas, oil and

NGLs sales and we recognized $25.7 million of field net operating income (defined as natural gas, oil and NGLs sales less
direct operating expenses, production and ad valorem taxes and transportation expenses) from the property interests acquired
in the Conger Exchange.

Conger Exchange Fair Value

Accounting standards define fair value as the price that would be received to sell an asset or paid to transfer a liability
in an orderly transaction between market participants at the measurement date (often referred to as the “exit price”). The fair
value measurement is based on the assumptions of market participants and not those of the reporting entity. Therefore, entity-
specific intentions do not impact the measurement of fair value unless those assumptions are consistent with market
participant views.

F-16

The fair value of the Conger Exchange described above was based on an income approach which was supplemented by

a market approach. For the natural gas and oil properties, the income approach uses significant inputs not observable in the
market, which are Level 3 inputs. The significant inputs assumed include future production, costs and capital, commodity
prices, risk-adjusted discount rates, natural gas and oil pricing differentials, and projected reserve recovery factors. The
market approach uses inputs such as recent market transactions in a similar geographic region and with similar production.
The income approach for the natural gas gathering operations was based on a discounted future net cash flow model, which
uses Level 3 inputs and was supplemented by a market approach.

Dispositions

We recognized an aggregate gain on the sale of assets of $285.6 million in the year ended December 31, 2014
compared to $92.3 million in 2013 and $49.1 million in 2012. The following describes the significant divestitures that are
included in income from operations:

(cid:121) As detailed above, we completed the Conger Exchange in June 2014 and we recognized a pre-tax gain of $287.7
million, before selling expenses of $5.0 million, which includes a $10.0 million gain on the remeasurement of our
membership interest in NGLLC.

(cid:121)

In April 2013, we completed the sale of our Delaware and Permian Basin properties in southeast New Mexico
and West Texas for a price of $275.0 million and we recognized a pre-tax gain of $83.3 million, before selling
expenses of $4.2 million.

In November 2012, we completed the sale of our Ardmore Woodford properties in Southern Oklahoma for cash
proceeds of $135.0 million and we recognized a pre-tax gain of $55.2 million related to this sale.

(cid:121) During 2014, 2013 and 2012, we sold miscellaneous proved and unproved oil and gas properties, inventory, and
other property and equipment and recorded a pre-tax gain of $2.9 million in 2014, compared to a pre-tax gain of
$13.2 million in 2013 and a pre-tax loss of $6.1 million in 2012.

(4) INCOME TAXES

Our income tax expense was $396.5 million for the year ended December 31, 2014 compared to $33.9 million in 2013

and $12.1 million in 2012. Reconciliation between the statutory federal income tax rate and our effective income tax rate is as
follows:

Year Ended December 31,
2013

2012

2014

Federal statutory tax rate
State
State apportionment rate change
Non-deductible executive compensation
Valuation allowances
Other

Consolidated effective tax rate

35.0%
3.1
(0.2)
0.2
0.2
0.2
38.5%

35.0 %
(2.3 )
(14.9 )
0.7
3.5
0.6
22.6 %

35.0%
0.7
⎯
1.4
8.8
2.2
48.1%

Income tax expense (benefit) attributable to income before income taxes consists of the following (in thousands):

2014

2013

2012

U.S. federal
U.S. state and local

Total

Current Deferred
$ ⎯ $ 361,152 $361,152 $ ⎯ $ 58,527 $ 58,527 $ — $ 11,873 $ 11,873
(143) (24,527) (24,670) (1,778 ) 1,959
181
(143) $ 34,000 $ 33,857 $ (1,778 ) $ 13,832 $ 12,054

1 35,350 35,351
1 $ 396,502 $396,503 $

Current Deferred

Total

F-17

Significant components of deferred tax assets and liabilities are as follows:

Deferred tax assets:

Current

Deferred compensation
Current portion of asset retirement obligation
Cumulative mark-to-market loss
Net operating loss carryforward
Other

Total current

Non-current

Net operating loss carryforward
Deferred compensation
Equity compensation
AMT credits and other credits
Non-current portion of asset retirement obligation
Cumulative mark-to-market loss
Other
Valuation allowance
Total non-current

Deferred tax liabilities:

Current

Net gain in AOCI related to hedge derivatives
Other
Cumulative mark-to-market gain

Total current

Non-current

Depreciation, depletion and investments
Cumulative mark-to-market gain
Other

Total non-current

Net deferred tax liability

December 31,

2014

2013

(in thousands)

9,286 $
5,745
584
—
9,921
25,536

176,812
64,656
25,833
4,447
104,063
65
987
(16,599 )
360,264

—
(2,350 )
(138,773 )
(141,123 )

9,128
1,854
15,193
23,079
7,936
57,190

57,266
91,094
22,800
4,122
86,126
⎯
1,116
(14,781)
247,743

(3,987)
(1,789)
⎯
(5,776)

(1,342,039 )
(15,410 )
(310 )
(1,357,759 )
(1,113,082 ) $

(1,010,757)
(6,424)
(2,542)
(1,019,723)
(720,566)

At December 31, 2014, deferred tax liabilities exceeded deferred tax assets by $1.1 billion. As of December 31, 2014,
we have a $7.8 million valuation allowance on the deferred tax asset related to our deferred compensation plan for planned
future distributions to certain executives to the extent that their estimated future compensation plus distribution amounts
would exceed the $1.0 million deductible limit provided under I.R.C. Section 162(m). We also have an $8.8 million valuation
allowance on our Oklahoma net operating loss carryforwards.

At December 31, 2014, we had regular net operating loss (“NOL”) carryforwards of $641.4 million and alternative

minimum tax (“AMT”) NOL carryforwards of $557.3 million that expire between 2018 and 2034. Our federal deferred tax
asset related to regular NOL carryforwards at December 31, 2014 was $130.8 million, which is net of the Accounting
Standards Codification 718, “Stock Compensation” reduction for unrealized benefits, related to NOL’s created by excess tax
deductions that have not generated current tax benefits. At December 31, 2014, we have AMT credit carryforwards of
$665,000 that are not subject to limitation or expiration.

We file consolidated tax returns in the United States federal jurisdiction. We file separate company state income tax

returns in Louisiana, Mississippi, Pennsylvania and Virginia and file consolidated or unitary state income tax returns in
Oklahoma, Texas and West Virginia. We are subject to U.S. Federal income tax examinations for the years 2011 and after
and we are subject to various state tax examinations for years 2010 and after. We have not extended the statute of limitation
period in any income tax jurisdiction. Our policy is to recognize interest related to income tax expense in interest expense and
penalties in general and administrative expense. We do not have any accrued interest or penalties related to tax amounts as of
December 31, 2014. Throughout 2014, our unrecognized tax benefits were not material.

F-18

(5) NET INCOME PER COMMON SHARE

Basic income or loss per share attributable to common shareholders is computed as (i) income or loss attributable to

common shareholders (ii) less income allocable to participating securities (iii) divided by weighted average basic shares
outstanding. Diluted income or loss per share attributable to common stockholders is computed as (i) basic income or loss
attributable to common shareholders (ii) plus diluted adjustments to income allocable to participating securities (iii) divided
by weighted average diluted shares outstanding. The following table sets forth a reconciliation of net income or loss to basic
income or loss attributable to common shareholders and to diluted income or loss attributable to common shareholders (in
thousands except per share amounts):

Net income, as reported

Participating basic earnings (a)

Basic net income attributed to common shareholders

Reallocation of participating earnings (a)

Diluted net income attributed to common shareholders
Net income per common share:

Basic
Diluted

$
$

2014

Year Ended December 31,
2013
115,722

634,382 $
(10,725)
623,657
48

623,705 $

(1,975 )

113,747
9
113,756

2012

13,002
(460)
12,542
—
12,542

3.81 $
3.79 $

0.71
0.70

$
$

0.08
0.08

(a) Restricted stock Liability Awards represent participating securities because they participate in nonforfeitable dividends or distributions

with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings
attributable to the participating securities. Participating securities, however, do not participate in undistributed net losses.

The following table provides a reconciliation of basic weighted average common shares outstanding to diluted

weighted average common shares outstanding (in thousands):

Denominator:
Weighted average common shares outstanding – basic
Effect of dilutive securities:

Year Ended December 31,
2013

2012

2014

163,625

160,438

159,431

Director and employee SARs and restricted stock Equity Awards

Weighted average common shares outstanding – diluted

778
164,403

969
161,407

876
160,307

Weighted average common shares – basic excludes 2.8 million shares of restricted stock Liability Awards held in our
deferred compensation plans (although all awards are issued and outstanding upon grant) for both periods ending December
31, 2014 and December 31, 2013 and 2.9 million shares for the period ending December 31, 2012. SARs of 1,900 for the
year ended December 31, 2014 compared to 226,000 in 2013 and 854,000 in 2012 were outstanding but not included in the
computations of diluted net income per share because the grant prices of the SARs were greater than the average market price
of the common shares and would be anti-dilutive to the computations.

(6) SUSPENDED EXPLORATORY WELL COSTS

We capitalize exploratory well costs until a determination is made that the well has either found proved reserves or that

it is impaired. Capitalized exploratory well costs are presented in natural gas and oil properties in the accompanying
consolidated balance sheets. If an exploratory well is determined to be impaired, the well costs are charged to exploration
expense in the accompanying consolidated statements of income. The following table reflects the changes in capitalized
exploratory well costs for the years ended December 31, 2014, 2013 and 2012 (in thousands, except for number of projects):

F-19

Balance at beginning of period

Additions to capitalized exploratory well costs pending the

2014

2013

2012

6,964 $

57,360 $

93,388

determination of proved reserves

18,747

39,832

153,250

Reclassifications to wells, facilities and equipment based on

determination of proved reserves

Divested wells
Capitalized exploratory well costs charged to expense

Balance at end of period

Less exploratory well costs that have been capitalized for a

period of one year or less

Capitalized exploratory well costs that have been capitalized for a

period greater than one year

Number of projects that have exploratory well costs that have

been capitalized for a period greater than one year

(15,735)
⎯
(6,980)
2,996

(2,996)

⎯ $

⎯

(84,840 )
⎯
(5,388 )
6,964

(184,298)
(4,980)
—
57,360

⎯

(45,965)

6,964 $

11,395

(7) INDEBTEDNESS

We had the following debt outstanding as of the dates shown below (bank debt interest rate at December 31, 2014 is

shown parenthetically) (in thousands). No interest was capitalized during 2014, 2013, and 2012.

Bank debt (2.0%)

Senior subordinated notes:

December 31,

2014

2013

723,000 $

500,000

8.00% senior subordinated notes due 2019, net of $9,484 discount
6.75% senior subordinated notes due 2020
5.75% senior subordinated notes due 2021
5.00% senior subordinated notes due 2022
5.00% senior subordinated notes due 2023

Total debt

⎯
500,000
500,000
600,000
750,000

290,516
500,000
500,000
600,000
750,000
$ 3,073,000 $ 3,140,516

Bank Debt

On October 16, 2014, we entered into an amended and restated revolving bank facility, which we refer to as our bank

debt or our bank credit facility, which is secured by substantially all of our assets. The bank credit facility has a maximum
facility amount of $4.0 billion and an initial borrowing base of $3.0 billion. On December 31, 2014, bank commitments
totaled $2.0 billion. The bank credit facility provides for a borrowing base subject to redeterminations annually each May and
for event-driven unscheduled redeterminations. Our current bank group is comprised of twenty-nine financial institutions,
with no one bank holding more than 6% of the total facility. The borrowing base may be increased or decreased based on our
request and sufficient proved reserves, as determined by the bank group. The commitment amount may be increased to the
borrowing base, subject to payment of a mutually acceptable commitment fee to those banks agreeing to participate in the
facility increase. The commitment matures on October 16, 2019. As of December 31, 2014, the outstanding balance under the
bank credit facility was $723.0 million with $105.3 million of undrawn letters of credit leaving $1.2 billion of borrowing
capacity available under the commitment amount. During a non-investment grade period, borrowings under the bank facility
can either be at the alternate base rate (“ABR,” as defined) plus a spread ranging from 0.25% to 1.25% or LIBOR borrowings
at the Adjusted LIBO Rate (as defined) plus a spread ranging from 1.25% to 2.25%. The applicable spread is dependent upon
borrowings relative to the borrowing base. We may elect, from time to time, to convert all or any part of our LIBOR loans to
ABR loans or to convert all or any of the ABR loans to LIBOR loans. The weighted average interest rate was 2.0% for each
of the years ended December 31, 2014 and 2013 and 2.2% for the year ended December 31, 2012. A commitment fee is paid
on the undrawn balance based on an annual rate of 0.30% to 0.375%. At December 31, 2014, the commitment fee was
0.30%, the interest rate margin was 1.5% on our LIBOR loans and 0.5% on our base rate loans.

At any time during which we have an investment grade debt rating from Moody’s Investors Service, Inc. or Standard &
Poor’s Ratings Services and we have elected, at our discretion, to effect the investment grade rating period, certain collateral
security requirements, including the borrowing base requirement and restrictive covenants will cease to apply, certain other

F-20

restrictive covenants will become less restrictive and an additional financial covenant (as defined in the bank credit facility)
will be temporarily imposed. During the investment grade period, borrowings under the bank credit facility can either be at
the ABR plus a spread ranging from 0.125% to 0.75% or LIBOR borrowings plus a spread ranging from 1.125% to 1.75%
depending on our debt rating. The commitment fee paid on the undrawn balance ranges from 0.15% to 0.30%.

Senior Subordinated Notes

If we experience a change of control, bondholders may require us to repurchase all or a portion of all of our senior

subordinated notes at 101% of the principal amount plus accrued and unpaid interest, if any. All of the senior subordinated
notes and the guarantees by our subsidiary guarantors are general, unsecured obligations and are subordinated to our bank
debt and will be subordinated to future senior debt that we or our subsidiary guarantors are permitted to incur under the bank
credit facility and the indentures governing the subordinated notes.

Early Extinguishment of Debt

In 2014, we announced a call for the redemption of $300.0 million of our outstanding 8.0% senior subordinated notes
due 2019 at 104.0% of par plus accrued and unpaid interest which were redeemed on June 26, 2014. In second quarter 2014,
we recognized a $24.6 million loss on extinguishment of debt, including transaction call premium costs as well as expensing
of the remaining deferred financing costs on the repurchased debt.

In 2013, we announced a call for the redemption of $250.0 million of our outstanding 7.25% senior subordinated notes
due 2018 at 103.625% of par which were redeemed on May 2, 2013. In second quarter 2013, we recognized a $12.3 million
loss on extinguishment of debt, including transaction call premium costs as well as expensing of the remaining deferred
financing costs on the repurchased debt.

In 2012, we called our 7.5% senior subordinated notes due 2017 at 103.75% of par which we redeemed on
December 28, 2012. In fourth quarter 2012, we recognized an $11.1 million loss on extinguishment of debt, including
transaction call premium costs as well as expensing of the remaining deferred financing cost on repurchased debt.

Guarantees

Range Resources Corporation is a holding company which owns no operating assets and has no significant operations
independent of its subsidiaries. The guarantees by our wholly owned subsidiaries, which are directly or indirectly owned by
Range, of our senior subordinated notes and our bank credit facility are full and unconditional and joint and several, subject
to certain customary release provisions. A subsidiary guarantor may be released from its obligations under the guarantee:

•

in the event of a sale or other disposition of all or substantially all of the assets of the subsidiary guarantor or a
sale or other disposition of all the capital stock of the subsidiary guarantor, to any corporation or other person
(including an unrestricted subsidiary of Range) by way of merger, consolidation, or otherwise; or

if Range designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance
with the terms of the indenture.

Debt Covenants and Maturity

Our bank credit facility contains negative covenants that limit our ability, among other things, to pay cash dividends,

incur additional indebtedness, sell assets, enter into certain hedging contracts, change the nature of our business or
operations, merge, consolidate, or make certain investments. In addition, we are required to maintain a ratio of debt to
EBITDAX (as defined in the credit agreement) of no greater than 4.25 to 1.0 and a current ratio (as defined in the credit
agreement) of no less than 1.0 to 1.0. During an investment grade period in which Range has only one investment grade
rating, an additional covenant is imposed whereby the ratio of the present value of proved reserves (as defined in the credit
agreement) to total debt must be equal to or greater than 1.5 to 1.0. We were in compliance with applicable covenants under
the bank credit facility at December 31, 2014.

The indentures governing our senior subordinated notes contain various restrictive covenants that are substantially

identical to each other and may limit our ability to, among other things, pay cash dividends, incur additional indebtedness,
sell assets, enter into transactions with affiliates, or change the nature of our business. At December 31, 2014, we were in
compliance with these covenants.

F-21

The following is the principal maturity schedule for our long-term debt outstanding as of December 31, 2014 (in

thousands):

2015
2016
2017
2018
2019
Thereafter

Year Ended
December 31,
—
$
—
—
—
723,000
2,350,000
$ 3,073,000

(8) ASSET RETIREMENT OBLIGATIONS

Our asset retirement obligations primarily represent the estimated present value of the amounts we will incur to plug,
abandon and remediate our producing properties at the end of their productive lives. Significant inputs used in determining
such obligations include estimates of plugging and abandonment costs, estimated future inflation rates and well life. The
inputs are calculated based on historical data as well as current estimated costs. A reconciliation of our liability for plugging
and abandonment costs for the years ended December 31, 2014 and 2013 are as follows (in thousands):

Beginning of period

Liabilities incurred
Acquisitions
Liability released
Liabilities settled
Disposition of wells
Accretion expense
Change in estimate

End of period

Less current portion

2014

2013

230,077
8,602
11,927
(8,309)
(4,442)
(13,951)
15,226
48,333
287,463

146,478
8,731
⎯
⎯
(424 )
(3,129 )
10,778
67,643
230,077

(15,067)

(5,037 )

Long-term asset retirement obligations

272,396

225,040

Accretion expense is recognized as an increase to depreciation, depletion and amortization expense in the

accompanying consolidated statements of income.

(9) CAPITAL STOCK

We have authorized capital stock of 485.0 million shares, which includes 475.0 million shares of common stock and
10.0 million shares of preferred stock. The following is a schedule of changes in the number of common shares outstanding
since the beginning of 2012:

Beginning balance
Equity offering
Stock options/SARs exercised
Restricted stock grants
Restricted stock units vested
Treasury shares

Ending balance

2014

Year Ended December 31,
2013

2012

163,342,894
4,560,000
195,242
270,062
244,413
15,566
168,628,177

162,514,098
(cid:237)
278,916
401,122
119,480
29,278
163,342,894

161,131,547
(cid:237)
926,425
354,674
57,824
43,628
162,514,098

F-22

Common Stock Dividends

The Board of Directors declared quarterly dividends of $0.04 per common share for each of the four quarters of 2014,
2013 and 2012. The determination of the amount of future dividends, if any, to be declared and paid is at the sole discretion
of the Board of Directors and will depend on our financial condition, earnings and cash flow from operations, level of capital
expenditures, our future business prospects and other matters our Board of Directors deem relevant. Our bank credit facility
and our senior subordinated notes allow for the payment of common dividends, with certain limitations. Dividends are
limited to our legally available funds.

(10) DERIVATIVE ACTIVITIES

We use commodity-based derivative contracts to manage exposure to commodity price fluctuations. We do not enter

into these arrangements for speculative or trading purposes. We do not utilize complex derivatives as we typically utilize
commodity swap or collar contracts to (1) reduce the effect of price volatility of the commodities we produce and sell and
(2) support our annual capital budget and expenditure plans. Their fair value, represented by the estimated amount that would
be realized upon termination, based on a comparison of the contract price and a reference price, generally NYMEX,
approximated a net unrealized pre-tax gain of $401.7 million at December 31, 2014. These contracts expire monthly through
December 2016. The following table sets forth the derivative volumes by year as of December 31, 2014:

Period

Contract Type

Volume Hedged

Weighted
Average Hedge Price

Natural Gas

2015

2016

Crude Oil
2015
2016

NGLs (C3 - Propane)
2015

NGLs (C5 - Natural Gasoline)
2015-First Quarter

Collars

Swaps

Swaps
Swaps

145,000
Mmbtu/day
412,390
Mmbtu/day
120,000
Mmbtu/day

9,626 bbls/day
1,000 bbls/day

$4.07–$4.56

$4.15

$90.57
$91.43

Swaps

2,245 bbls/day

$0.95/gallon

Swaps

500 bbls/day

$2.14/gallon

Every derivative instrument is required to be recorded on the balance sheet as either an asset or a liability measured at

its fair value. Through February 28, 2013, changes in the fair value of our derivatives that qualified for hedge accounting
were recorded as a component of AOCI in the stockholders’ equity section of the accompanying consolidated balance sheets,
which were later transferred to natural gas, NGLs and oil sales when the underlying physical transaction occurred and the
hedging contract was settled. Due to the discontinuance of hedge accounting in early 2013, all remaining AOCI hedging
gains were transferred to earnings in 2014. See additional discussion below regarding the discontinuance of hedge
accounting. If the derivative does not qualify as a hedge or is not designated as a hedge, changes in fair value of these non-
hedge derivatives are recognized in earnings in derivative fair value income or loss.

For those derivative instruments that qualified for hedge accounting, settled transaction gains and losses were
determined monthly and were included as increases or decreases to natural gas, NGLs and oil sales in the period the hedged
production was sold. Through February 28, 2013, we had elected to designate our commodity instruments that qualified for
hedge accounting as cash flow hedges. Natural gas, NGLs and oil sales include $10.2 million of gains in 2014 compared to
$116.5 million in 2013 and $236.3 million in 2012 related to settled hedging transactions. Any ineffectiveness associated
with these hedge derivatives are reflected in derivative fair value income or loss in the accompanying consolidated statements
of income. The ineffective portion is calculated as the difference between the changes in fair value of the derivative and the
estimated change in future cash flows from the item hedged. Derivative fair value for the year ended December 31, 2014
includes no ineffective gains or losses compared to ineffective loss of $2.9 million in the year ended December 31, 2013 and
gains of $1.1 million in the year ended December 31, 2012.

F-23

Discontinuance of Hedge Accounting

Effective March 1, 2013, we elected to de-designate all commodity contracts that were previously designated as cash

flow hedges and elected to discontinue hedge accounting prospectively. AOCI included gains of $103.6 million ($63.2
million after tax) as of February 28, 2013. As a result of discontinuing hedge accounting, the marked-to-market values
included in AOCI as of the de-designation date were frozen and were reclassified into earnings in natural gas, NGLs and oil
sales in future periods as the underlying hedged transactions occurred. As of December 31, 2014, all frozen values have been
reclassified to earnings.

With the election to de-designate hedging instruments, all of our derivative instruments continue to be recorded at fair

value with all changes in fair value recognized immediately in earnings rather than in AOCI. These marked-to-market
adjustments will produce a degree of earnings volatility that can be significant from period to period, but such adjustments
will have no cash flow impact relative to changes in market prices. The impact to cash flow occurs upon settlement of the
underlying contract.

Basis Swap Contracts

At December 31, 2014, we had natural gas basis swap contracts that are not designated for hedge accounting, which
lock in the differential between NYMEX and certain of our physical pricing points in Appalachia. These contracts are for
35,164 Mmbtu/day and settle monthly through October 2015. The fair value of these contracts was a gain of $1.7 million on
December 31, 2014.

Derivative assets and liabilities

The combined fair value of derivatives included in the accompanying consolidated balance sheets as of December 31,

2014 and 2013 is summarized below. As of December 31, 2014, we are conducting derivative activities with fifteen financial
institutions, of which all but one are secured lenders in our bank credit facility. We believe all of these institutions are
acceptable credit risks. At times, such risks may be concentrated with certain counterparties. The credit worthiness of our
counterparties is subject to periodic review. The assets and liabilities are netted where derivatives with both gain and loss
positions are held by a single counterparty and we have master netting arrangements (in thousands).

Gross Amounts of
Recognized Assets

December 31, 2014
Gross Amounts
Offset in the
Balance Sheet

Net Amounts of
Assets Presented in the
Balance Sheet

Derivative assets:

Natural gas –swaps
–collars
–basis swaps
–swaps
–C3 swaps
–C5 swaps

Crude oil
NGLs

198,740 $
57,460
2,442
128,578
14,727
2,171
404,118 $

⎯ $
⎯
(755)
⎯
⎯
⎯
(755) $

198,740
57,460
1,687
128,578
14,727
2,171
403,363

Derivative (liabilities):

Natural gas –basis swaps

Gross Amounts of
Recognized (Liabilities)

December 31, 2014
Gross Amounts
Offset in the
Balance Sheet

Net Amounts of
(Liabilities) Presented in the
Balance Sheet

$
$

(755) $
(755) $

755 $
755 $

(cid:237)
(cid:237)

F-24

Gross Amounts of
Recognized Assets

December 31, 2013
Gross Amounts
Offset in the
Balance Sheet

Net Amounts of
Assets Presented in the
Balance Sheet

Derivative assets:

Natural gas –swaps
–collars
–basis swaps
–swaps
–C3 swaps
–C4 swaps
–C5 swaps

Crude oil
NGLs

4,240 $
16,057
7,686
3,567
826
863
121
33,360 $

(1,218) $
(7,671)
(7,686)
(1,321)
(826)
(863)
(121)
(19,706) $

3,022
8,386
⎯
2,246
⎯
⎯
⎯
13,654

Derivative (liabilities):
Natural gas –swaps
–collars
–basis swaps
–swaps
–collars
–C3 swaps
–C4 swaps
–C5 swaps

Crude oil

NGLs

Gross Amounts of
Recognized (Liabilities)

December 31, 2013
Gross Amounts
Offset in the
Balance Sheet

Net Amounts of
(Liabilities) Presented in the
Balance Sheet

(4,790) $
(13,345)
(3,756)
(4,711)
(398)
(18,172)
(757)
⎯
(45,929) $

1,218 $
7,671
7,686
1,321
⎯
826
863
121
19,706 $

(3,572)
(5,674)
3,930
(3,390)
(398)
(17,346)
106
121
(26,223)

The effects of our cash flow hedges (or those derivatives that qualified for hedge accounting) on AOCI in the

accompanying consolidated balance sheets is summarized below (in thousands):

Swaps
Collars
Income taxes

Year Ended December 31,

Change in Hedge
Derivative Fair Value
2013
2014

Realized Gain
Reclassified from OCI
Into Revenue (a)

2014

2013

⎯ $
⎯
⎯
⎯ $

125 $
(7,015)
2,687
(4,203) $

4,544 $
5,678
(3,986 )
6,236 $

15,171
105,272
(46,973)
73,470

(a) For gains upon contract settlement, the reduction in AOCI is offset by an increase in natural gas, NGLs and oil sales. For losses upon

contract settlement, the increase in AOCI is offset by a decrease in natural gas, NGLs and oil sales.

F-25

The effects of our non-hedge derivatives (or those derivatives that do not qualify or are not designated for hedge
accounting) and the ineffective portion of our hedge derivatives on our consolidated statements of income are summarized
below (in thousands):

Gain (Loss) Recognized in
Income (Non-hedge Derivatives)
2012
2013
2014

Swaps

$ 367,484 $ (48,492 ) $ 11,601 $

Re-purchased swaps

Collars

Call options

Put options

Basis swaps

Total

⎯
42,836
⎯
⎯
(26,800 )

1,323

9,313

(15,166 )
⎯
⎯
3,440

5,126

13,178

(30)

1,124

$ 383,520 $ (58,895 ) $ 40,312 $

2014

2012

Year Ended December 31,
Gain (Loss) Recognized in
Income (Ineffective Portion)
2013
⎯ $ (2,034) $
⎯
⎯
⎯
(896)
⎯
⎯
⎯
⎯
⎯
⎯
⎯ $ (2,930) $

Derivative Fair Value
Income (Loss)
2013

2012

2014

(657) $ 367,484 $ (50,526) $ 10,944
⎯
1,782

1,323

6,908

9,313

⎯
42,836
⎯
⎯
(26,800 )

—

(16,062)
⎯
⎯
3,440

13,178

(30)

1,124

1,125 $ 383,520 $ (61,825) $ 41,437

(11) FAIR VALUE MEASUREMENTS

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction

between market participants at the measurement date. There are three approaches for measuring the fair value of assets and
liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation
techniques. The market approach uses prices and other relevant information generated by market transactions involving
identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by
converting future amounts, such as cash flows or earnings, into a single present value amount using current market
expectations about those future amounts. The cost approach is based on the amount that would currently be required to
replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that
the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of
comparable utility, adjusted for obsolescence.

The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair
value and do not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs
used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to
make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value
hierarchy, while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:
• Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active

markets as of the reporting date. Active markets are those in which transactions for the asset or liability occur in
sufficient frequency and volume to provide pricing information on an ongoing basis.

• Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are
inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly
observable as of the reporting date.

• Level 3 – Unobservable inputs that are not corroborated by market data and may be used with internally

developed methodologies that result in management’s best estimate of fair value.

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in

F-26

Fair Values-Recurring

We use a market approach for our recurring fair value measurements and endeavor to use the best information
available. Accordingly, valuation techniques that maximize the use of observable impacts are favored. The following tables
present the fair value hierarchy table for assets and liabilities measured at fair value, on a recurring basis (in thousands):

Fair Value Measurements at December 31, 2014 Using:
Total
Carrying
Value as of
December 31,
2014

Significant
Unobservable
Inputs
(Level 3)

Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)

Significant
Other
Observable
Inputs

(Level 2)

Trading securities held in the deferred compensation plans $
Derivatives –swaps
–collars
–basis swaps

68,454 $

⎯ $
⎯ 344,216
⎯
57,460
⎯
1,687

⎯ $
⎯
⎯
⎯

68,454
344,216
57,460
1,687

Fair Value Measurements at December 31, 2013 Using:
Total
Carrying
Value as of
December 31,
2013

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)

Trading securities held in the deferred compensation plans $
Derivatives

–swaps
–collars
–basis swaps

67,776 $
—
—
—

— $
(18,813)
2,314
3,382

— $
—
—
548

67,766
(18,813)
2,314
3,930

Our trading securities in Level 1 are exchange-traded and measured at fair value with a market approach using

December 31, 2014 market values. Derivatives in Level 2 are measured at fair value with a market approach using third-party
pricing services, which have been corroborated with data from active markets or broker quotes. As of December 31, 2013, we
had four natural gas basis swaps categorized as Level 3 due to the forward price curve being unavailable for the regional sales
point. As of December 31, 2014, we have no natural gas basis swaps categorized as Level 3. The following is a reconciliation
of the net beginning and ending balances for derivative instruments classified as Level 3 in the fair value hierarchy (in
thousands):

Beginning balance

Changes in fair value of derivative instruments
Settlements received

Ending balance

2014

548
2,979
(3,527 )
—

Our trading securities held in the deferred compensation plan are accounted for using the mark-to-market accounting
method and are included in other assets in the accompanying consolidated balance sheets. We elected to adopt the fair value
option to simplify our accounting for the investments in our deferred compensation plan. Interest, dividends, and mark-to-
market gains/losses are included in deferred compensation plan expense in the accompanying consolidated statements of
income. For the year ended December 31, 2014, interest and dividends were $911,000 and mark-to-market was a loss of $2.4
million. For the year ended December 31, 2013, interest and dividends were $1.2 million and mark-to-market was a gain of
$3.9 million. For the year ended December 31, 2012, interest and dividends were $1.4 million and mark-to-market was a gain
of $4.7 million.

F-27

Fair Values-Non recurring

Due to declines in commodity prices and estimated reserves over the last three years, there were indications that the

carrying values of certain of our natural gas and oil properties may be impaired and undiscounted future cash flows attributed
to these assets indicated their carrying amounts were not expected to be recovered. Their fair value was measured using an
income approach based upon internal estimates of future production levels, prices, drilling and operating costs and discount
rates, which are Level 3 inputs. In some cases, we also considered the potential sale of certain of these properties. We
recorded non-cash charges during the year ended 2014 of $5.5 million related to natural gas and oil properties in Mississippi,
$18.5 million related to properties in West Texas and $4.0 million to fully impair our remaining oil and natural gas properties
in North Texas. We recorded non-cash charges during the year ended 2013 of $7.0 million related to Gulf Coast onshore oil
and gas properties. We recorded non-cash charges during the year ended 2012 of $31.1 million related to our Mississippi
natural gas and oil properties and $3.2 million related to our remaining oil and natural gas properties in North Texas. Also in
2013 and 2012, we evaluated certain surface property we own which included a consideration for the potential sale of the
assets and we recognized impairment charges of $741,000 in 2013 and $1.3 million in 2012. The following table presents the
value of these assets measured at fair value on a nonrecurring basis at the time impairment was recorded (in thousands):

2014

Year Ended December 31,
2013
Fair Value Impairment Fair Value Impairment Fair Value Impairment
34,273
1,281

7,012 $ 12,604 $
6,269

$ 15,605 $
⎯

28,024 $
⎯

500 $
5,550

741

2012

Natural gas and oil properties
Surface property

Fair Values - Reported

The following table presents the carrying amounts and the fair values of our financial instruments as of December 31,

2014 and 2013 (in thousands):

December 31, 2014
Fair
Value

Carrying
Value

December 31, 2013
Fair
Value

Carrying
Value

Assets:

Commodity swaps, collars and basis swaps
Marketable securities(a)

Liabilities:

Commodity swaps, collars and basis swaps
Bank credit facility(b)
Deferred compensation plan(c)
8.00% senior subordinated notes due 2019(b)
6.75% senior subordinated notes due 2020(b)
5.75% senior subordinated notes due 2021(b)
5.00% senior subordinated notes due 2022(b)
5.00% senior subordinated notes due 2023(b)

$ 403,363 $ 403,363 $ 13,654 $ 13,654
67,766

68,454

67,766

68,454

⎯
(723,000)
(203,433)
⎯
(500,000)
(500,000)
(600,000)
(750,000)

⎯

(26,223 )
(723,000 ) (500,000 )
(203,433 ) (271,738 )
⎯ (290,516 )
(523,125 ) (500,000 )
(520,000 ) (500,000 )
(601,500 ) (600,000 )
(754,688 ) (750,000 )

(26,223)
(500,000)
(271,738)
(319,500)
(541,250)
(530,625)
(588,750)
(732,188)

(a) Marketable securities are held in our deferred compensation plans that are actively traded on major exchanges.
(b) The book value of our bank debt approximates fair value because of its floating rate structure. The fair value of our senior subordinated

notes is based on end of period market quotes, which are Level 2 inputs.

Our current assets and liabilities contain financial instruments, the most significant of which are trade accounts
receivables and payables. We believe the carrying values of our current assets and liabilities approximate fair value. Our fair
value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments and (2) our
historical incurrence of and expected future insignificance of bad debt expense.

F-28

(12) STOCK-BASED COMPENSATION PLANS
Description of the Plans

The 2005 Equity Based Compensation Plan (the “2005 Plan”) authorizes the Compensation Committee of the Board of

Directors to grant, among other things, stock options, stock appreciation rights (“SARs”), performance share unit awards
(“PSUs”) and restricted stock awards to employees and directors. The 2004 Non-Employee Director Stock Option Plan (the
“Director Plan”) allows such grants to our non-employee directors of our Board of Directors. The 2005 Plan was approved by
stockholders in May 2005 and replaced our 1999 Stock Option Plan. Since then, no new grants have been made from the
1999 Stock Option Plan. The number of shares that may be issued under the 2005 Plan is equal to (i) 5.6 million shares plus
(ii) the number of shares subject to 1999 Stock Option Plan awards outstanding at May 18, 2005 that subsequently lapse or
terminate without the underlying shares being issued plus (iii) subsequent shares approved by the shareholders. The Director
Plan, which expired at the end of 2014, was approved by stockholders in May 2004 with no more than 450,000 shares of
common stock to be issued under the Director Plan.

Stock-Based Awards

Stock options represent the right to purchase shares of stock in the future at the fair value of the stock on the date of
grant. Most stock options granted under our stock option plans vest over a three-year period and expire five years from the
date they were granted. Beginning in 2005, we began granting SARs to reduce the dilutive impact of our equity plans.
Similar to stock options, SARs represent the right to receive a payment equal to the excess of the fair market value of shares
of common stock on the date the right is exercised over the value of the stock on the date of grant. All SARs granted under
the 2005 Plan will be settled in shares of stock, vest over a three-year period and have a maximum term of five years from the
date they are granted. Beginning in first quarter 2011, the Compensation Committee of our Board of Directors began granting
restricted stock units under our equity-based stock compensation plans. These restricted stock units, which we refer to as
restricted stock Equity Awards, vest over a three-year period. In first quarter 2014, the Compensation Committee began
granting PSU awards under our 2005 Plan. The number of shares to be issued is determined by our total shareholder return
compared to the total shareholder return of a predetermined group of peer companies over the performance period. The PSU
awards vest at the end of three years. The grant date fair value of the PSU awards is determined using a Monte Carlo
simulation and is recognized as stock-based compensation expense over the three-year performance period. All awards
granted have been issued at prevailing market prices at the time of grant and the vesting of these shares is based upon an
employee’s continued employment with us.

The Compensation Committee also grants restricted stock to certain employees and non-employee directors of the
Board of Directors as part of their compensation. Compensation expense is recognized over the balance of the vesting period,
which is typically three years for employee grants and immediate vesting for non-employee directors. All restricted stock
awards are issued at prevailing market prices at the time of the grant and the vesting is based upon an employee’s continued
employment with us. Prior to vesting, all restricted stock awards have the right to vote such stock (by the trustee) and receive
dividends thereon. Upon grant of these restricted shares, which we refer to as restricted stock Liability Awards, the majority
of these shares are placed in our deferred compensation plan and, upon vesting, withdrawals are allowed in either cash or in
stock. These Liability Awards are classified as a liability and are remeasured at fair value each reporting period. This mark-
to-market amount is reported in deferred compensation plan expense in the accompanying consolidated statements of income.
Historically, we have used authorized but unissued shares of stock when restricted stock is granted. However, we also utilize
treasury shares when available.

Total Stock-Based Compensation Expense

Stock-based compensation represents amortization of restricted stock, PSUs and SARs grants. The following table

details the amount of stock-based compensation that is allocated to functional expense categories (in thousands):

Operating expense
Brokered natural gas and marketing expense
Exploration expense
General and administrative expense
Termination costs
Total

2014

2013

2012

4,208 $
3,523
4,569
55,382
2,999

70,681 $

2,755 $
1,852
4,025
55,737
⎯
64,369 $

2,415
1,765
4,049
44,541
⎯
52,770

F-29

Unlike the other forms of stock-based compensation mentioned above, the mark-to-market of the liability related to the

vested restricted stock held in our deferred compensation plans is directly tied to the change in our stock price and not
directly related to the functional expenses and therefore, is not allocated to the functional categories. The increase in the year
ended 2013 stock-based compensation from 2012 is primarily due to additional expense of $10.0 million related to the
acceleration of stock-based compensation for our former executive chairman who became a non-employee director on
January 1, 2014. Stock-based compensation in the year ended December 31, 2014 includes $6.7 million of awards granted to
our former executive chairman for his 2013 service while he was a Range officer, which were fully vested upon grant. As
part of the closure of our Oklahoma City office announced in first quarter 2015, unvested SARs, restricted stock and PSUs
will be modified and fully vested effective with the closing of the office. These costs were estimated at December 31, 2014
as probable to occur and $3.0 million was accrued within termination costs in the consolidated statements of income. For the
year ended December 31, 2014 and 2013, tax benefits realized for deductions that were in excess of the stock-based
compensation expense were not recognized due to our net operating loss position.

Stock Appreciation Right Awards

We have two active equity-based stock plans, the 2005 Plan and the Director Plan. Under these plans, incentive and

non-qualified stock options, stock appreciation rights, restricted stock units and various other awards may be issued to
directors and employees pursuant to decisions of the Compensation Committee, which is made up of non-employee,
independent directors from the Board of Directors. After December 31, 2014, no new grants will be issued from the Director
Plan. All awards granted under these plans have been issued at prevailing market prices at the time of the grant. Of the 2.0
million grants outstanding at December 31, 2014, all grants relate to SARs. Information with respect to SARs activities is
summarized below:

Outstanding at December 31, 2011

Granted
Exercised
Expired/forfeited

Outstanding at December 31, 2012

Granted
Exercised
Expired/forfeited

Outstanding at December 31, 2013

Granted
Exercised
Expired/forfeited

Outstanding at December 31, 2014

Weighted
Average
Exercise Price
41.47
64.14
30.20
48.00
52.52
75.82
53.24
53.56
56.36
81.74
45.45
46.44
59.80

4,558,609 $
754,471
(1,860,367)
(19,351)

3,433,362
470,617
(1,269,323)
(52,582)

2,582,074
1,104
(616,563)
(66)
$

1,966,549

The following table shows information with respect to SARs outstanding and exercisable at December 31, 2014:

Range of Exercise Prices
$ 31.13–$ 39.99
40.00–49.99
50.00–59.99
60.00–69.99
70.00–79.99
80.00–81.15
Total

3,260
542,206
355,856
614,909
448,418

1,900
1,966,549

Outstanding
Weighted
Average
Remaining
Contractual
Life (in years)

Weighted
Average
Exercise
Price

0.58 $
0.49
1.38
2.33
3.30
3.69
1.87 $

38.82
46.47
52.35
64.18
75.88
81.15
59.80

Exercisable

Weighted
Average
Exercise
Price

38.82
46.47
52.35
64.21
76.30
81.15
56.64

3,260 $
542,206
355,856
422,546
196,064

1,900
1,521,832 $

F-30

During 2014, we granted SARs to our former executive chairman in conjunction with his retirement from Range as an
employee. During 2013 and 2012, we granted SARs to officers, non-officer employees and directors. The weighted average
grant date fair value of these SARs, based on our Black-Scholes-Merton assumptions, is shown below:

2014

2013

2012

Weighted average exercise price per share
Expected annual dividend yield
Expected life in years
Expected volatility
Risk-free interest rate
Weighted average grant date fair value per share

81.74 $
0.20%
4.3
33%
1.4%
$

23.17

75.82 $
0.21 %
3.7
35 %
0.6 %
$

20.20

64.14
0.25%
3.7
45%
0.5%

21.32

The expected dividend yield is based on the current annual dividend at the time of grant. The expected life was based

on the historical exercise activity. The expected volatility factors are based on a combination of both the historical volatilities
of the stock and implied volatility of traded options on our common stock. The risk-free interest rate is based on the U.S.
Treasury yield curve in effect at the time of grant for periods commensurate with the expected terms of the options.

The total intrinsic value (the difference in value between exercise and market price at the time of grant) of SARs
exercised during the years ended December 31, 2014 was $27.1 million compared to $30.3 million in 2013 and $61.0 million
in 2012. As of December 31, 2014, the aggregate intrinsic value of the awards outstanding was $4.2 million. The aggregate
intrinsic value and weighted average remaining contractual life of SARs awards exercisable as of December 31, 2014 was
$4.2 million and 1.6 years. As of December 31, 2014, the number of fully vested awards and awards expected to vest was 2.0
million shares. The weighted average exercise price and weighted average remaining contractual life of these awards were
$59.72 and 1.9 years and the aggregate intrinsic value was $4.2 million. As of December 31, 2014, unrecognized
compensation cost related to the awards was $3.9 million, which is expected to be recognized over a weighted average period
of 1.1 years.

Performance Share Unit Awards

The following is a summary of our non-vested PSU awards outstanding at December 31, 2014:

Outstanding at December 31, 2013

Granted (a)
Vested (b)
Forfeited

Outstanding at December 31, 2014

Weighted
Average
Grant Date
Fair Value

—
86.14
86.23
82.60
86.11

Units

— $
227,929
(92,077)
(1,511)
134,341 $

(a) Amounts granted reflect the number of performance units granted. The actual payout of shares may be between zero percent and 150%

of the performance units granted depending on the total shareholder return ranking compared to our peer companies at the vesting date.

(b) Primarily represents PSU awards granted to our prior executive chairman for the 2013 calendar year while he was a Range officer.

The following assumptions were used to estimate the fair value of PSUs granted during the year ended December 31,

2014:

Risk-free interest rate
Expected annual volatility
Grant date fair value per unit

Year Ended
December, 31,
2014

0.77%
33%

86.14

We recorded PSU compensation expense of $7.7 million in the year ended December 31, 2014 compared to none in the

same period of 2013. As of December 31, 2014, there was $10.5 million of unrecognized compensation related to PSU
awards to be recognized over a weighted average period of 2.3 years.

F-31

Restricted Stock Awards
Equity Awards

In 2014, we granted 356,000 restricted stock Equity Awards to employees which generally vest over a three-year
period. We recorded compensation expense for these awards of $26.3 million in the year ended December 31, 2014. In 2013,
we granted 402,000 restricted stock Equity Awards to employees which generally vest over a three-year period. We recorded
compensation expense for these awards of $19.7 million in the year ended December 31, 2013. In 2012, we granted 364,000
restricted stock Equity Awards to employees which generally vest over a three-year period. We recorded compensation
expense for these awards of $11.8 million in the year ended December 31, 2012. As of December 31, 2014, there was $26.9
million of unrecognized compensation related to Equity Awards expected to be recognized over a weighted average period
of 1.8 years. Restricted stock Equity Awards are not issued to employees until such time they are vested and the employees
do not have the option to receive cash.

Liability Awards

In 2014, we granted 272,000 shares of restricted stock Liability Awards as compensation to directors and employees at

an average price of $87.34. This grant included 64,000 issued to non-employee directors, which vest immediately and
208,000 to employees with vesting generally over a three-year period. In 2013, we granted 425,000 shares of restricted stock
Liability Awards as compensation to directors and employees at an average price of $75.53. This grant included 18,000
issued to non-employee directors, which vest immediately, and 407,000 to employees with vesting generally over a three-
year period. In 2012, we granted 381,000 shares of restricted stock Liability Awards as compensation to directors and
employees at an average price of $64.06. This grant included 14,700 issued to non-employee directors, which vest
immediately, and 366,300 to employees with vesting generally over a three-year period. We recorded compensation expense
for these Liability Awards of $25.2 million in the year ended December 31, 2014 compared to $27.4 million in 2013 and
$21.5 million in 2012. As of December 31, 2014, there was $22.0 million of unrecognized compensation related to restricted
stock Liability Awards expected to be recognized over a weighted average period of 1.8 years. Substantially all of these
awards are held in our deferred compensation plan, are classified as a liability and are remeasured at fair value each reporting
period. This mark-to-market is reported as deferred compensation expense in our consolidated statements of income (see
additional discussion below). The proceeds received from the sale of stock held in our deferred compensation plan was $16.0
million in 2014. A summary of the status of our non-vested restricted stock outstanding at December 31, 2014 is summarized
below:

Equity Awards

Liability Awards

Outstanding at December 31, 2011

Granted
Vested
Forfeited

Outstanding at December 31, 2012

Granted
Vested
Forfeited

Outstanding at December 31, 2013

Granted
Vested
Forfeited

Outstanding at December 31, 2014

Weighted
Average Grant
Date Fair Value
49.64
63.44
56.73
58.65
59.08
71.26
62.43
65.29
68.24
84.87
72.85
75.66
79.60

221,609 $
364,082
(208,802)
(27,733)
349,156
402,053
(315,535)
(50,611)
385,063
356,194
(354,237)
(26,605)
$
360,415

Weighted
Average Grant
Date Fair Value
48.76
$
64.06
52.17
54.54
58.91
75.53
64.36
57.31
71.02
87.34
75.52
77.35
80.33

Shares
487,244
380,808
(438,283 )
(6,291 )

423,478
424,809
(437,570 )
(21,704 )
389,013
272,052
(356,413 )
(148 )
304,504

401(k) Plan

We maintain a 401(k) benefit plan that allows employees to contribute up to 75% of their salary (subject to Internal
Revenue Service limitations) on a pretax basis. Beginning in 2008, we began matching up to 6% of salary in cash. Prior to
2013, all contributions became fully vested after the individual employee had two years of service with us. Beginning in
2013, vesting of our contributions is immediate. In 2014, we contributed $5.8 million to the 401(k) Plan compared to $5.1
million in 2013. Employees have a variety of investment options in the 401(k) benefit plan.

F-32

Deferred Compensation Plan

Our deferred compensation plan gives directors, officers and key employees the ability to defer all or a portion of their

salaries and bonuses and invest in Range common stock or make other investments at the individual’s discretion. Range
provides a partial matching contribution which vests over three years. The assets of the plans are held in a grantor trust,
which we refer to as the Rabbi Trust, and are therefore available to satisfy the claims of our creditors in the event of
bankruptcy or insolvency. Our stock held in the Rabbi Trust is treated as a liability award as employees are allowed to take
withdrawals from the Rabbi Trust either in cash or in Range stock. The liability for the vested portion of the stock held in the
Rabbi Trust is reflected in the deferred compensation liability in the accompanying consolidated balance sheets and is
adjusted to fair value each reporting period by a charge or credit to deferred compensation plan expense on our consolidated
statements of income. The assets of the Rabbi Trust, other than our common stock, are invested in marketable securities and
reported at their market value in other assets in the accompanying consolidated balance sheets. The deferred compensation
liability reflects the vested market value of the marketable securities and Range stock held in the Rabbi Trust. Changes in the
market value of the marketable securities and changes in the fair value of the deferred compensation plan liability are charged
or credited to deferred compensation plan expense each quarter. We recorded mark-to-market income of $74.6 million in
2014 compared to $55.3 million expense in 2013 and $7.2 million expense in 2012. The Rabbi Trust held 2.8 million shares
(2.5 million of vested shares) of Range stock at December 31, 2014 compared to 2.8 million shares (2.4 million of vested
shares) at December 31, 2013.

(13) SUPPLEMENTAL CASH FLOW INFORMATION

2014

Year Ended December 31,
2013
(in thousands)

2012

Net cash provided from operating activities included:

Income taxes (refunded from) paid to taxing authorities $
Interest paid

(156) $
165,530

(347 ) $
159,137

386
153,249

Non-cash investing and financing activities included:

Asset retirement costs capitalized, net
Increase (decrease) in accrued capital expenditures

56,822 $
150,604

76,373 $
27,079

57,982
(94,121)

F-33

(14) COMMITMENTS AND CONTINGENCIES

Litigation

We are the subject of, or party to, a number of pending or threatened legal actions and claims arising in the ordinary

course of our business. While many of these matters involve inherent uncertainty, we believe that the amount of the liability,
if any, ultimately incurred with respect to proceedings or claims will not have a material adverse effect on our consolidated
financial position as a whole or on our liquidity, capital resources or future annual results of operations. We will continue to
evaluate our litigation on a quarter-by-quarter basis and will establish and adjust any litigation reserves as appropriate to
reflect our assessment of the then current status of litigation.

Lease Commitments

We lease certain office space, office equipment, production facilities, compressors and transportation equipment under
cancelable and non-cancelable leases. Rent expense under operating leases (including renewable monthly leases and amounts
related to discontinued operations) totaled $13.3 million in 2014 compared to $13.1 million in 2013 and $13.8 million in
2012. Commitments related to these lease payments are not recorded in the accompanying consolidated balance sheets.
Future minimum rental commitments under non-cancelable leases having remaining lease terms in excess of one year are as
follows (in thousands):

2015
2016
2017
2018
2019
Thereafter

Operating
Lease
Obligations
16,557
$
12,700
7,292
5,660
4,399
12,830
59,438

Transportation and Gathering Contracts

We have entered into firm transportation and gathering contracts with various pipeline carriers for the future
transportation and gathering of natural gas, NGLs and oil production primarily from our properties in Pennsylvania. Under
these contracts, we are obligated to transport or gather minimum daily natural gas volumes, or pay for any deficiencies at a
specified reservation fee rate. In most cases, our production committed to these pipelines is expected to exceed the minimum
daily volumes provided in the contracts. As of December 31, 2014, future minimum transportation and gathering fees under
our commitments are as follows (in thousands):

2015
2016
2017
2018
2019
Thereafter

Transportation
and Gathering
Contracts (a)
342,204
366,836
356,789
321,385
317,627
1,842,410
$ 3,547,251

(a) The amounts in this table represent the gross amounts that we are committed to pay; however, we will record in our financial statements

our proportionate share of costs based on our working interest.

In addition to the amounts included in the above table, we have entered into additional agreements which are

contingent on certain pipeline and gathering line modifications and/or construction. These agreements range between five and
twenty year terms and are expected to begin mid-2015 through 2017. Based on these contracts, we will have additional
transportation and gathering obligations for natural gas volumes from 7,000 mcfe per day to 400,000 mcfe per day, ethane
volumes of 20,000 bbls per day and propane volumes of 20,000 bbls per day through the end of the contract terms.

F-34

Delivery Commitments

We have various volume delivery commitments that are primarily related to our Midcontinent and Marcellus Shale

areas. We expect to be able to fulfill our contractual obligations from our own production, however, we may purchase third
party volumes to satisfy our commitments or pay demand fees for commitment shortfalls, should they occur. As of
December 31, 2014, our delivery commitments through 2028 were as follows:

Year Ending December 31,
2015
2016
2017
2018
2019
2020
2021
2022⎯2028

Natural Gas
(mmbtu per day)
313,180
268,055
139,840
30,000
30,000
30,000
30,000
—

Ethane
(bbls per day)
15,000
15,000
15,000
15,000
15,000
15,000
15,000
15,000

In addition to the amounts included in the above table, we have contracted with several pipeline companies through
2033 to deliver ethane production volumes from our Marcellus Shale wells. These agreements and related fees, which are
contingent upon pipeline construction and/or modification, are for 10,000 bbls per day starting in 2015, increasing to 20,000
bbls per day in late 2015, increasing to 30,000 bbls per day in 2017 and 45,000 bbls per day in 2018 through the end of the
term.

Other

We have agreements in place for hydraulic fracturing including related equipment, material and labor for $12.0 million

in 2015. We also have lease acreage that is generally subject to lease expiration if initial wells are not drilled within a
specified period, generally between three to five years. We do not expect to lose significant lease acreage because of failure
to drill due to inadequate capital, equipment or personnel. However, based on our evaluation of prospective economics, we
have allowed acreage to expire and will allow additional acreage to expire in the future. To date, our expenditures to comply
with environmental or safety regulations have not been a significant component of our cost structure and are not expected to
be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result
in significant future costs.

(15) EQUITY METHOD INVESTMENTS

We accounted for our investments in entities over which we had significant influence, but not control, using the equity
method of accounting. Under the equity method of accounting, we recorded our proportionate share of net earnings, declared
dividends and partnership distributions based on the most recently available financial statements of the investee. We also
evaluated our equity method investments for potential impairment whenever events or changes in circumstances indicate that
there is an other than temporary decline in value of the investment. Such events include sustained operating losses by the
investee or long-term negative changes in the investee’s industry. As of June 16, 2014, we no longer have equity method
investments.

Investment in Whipstock Natural Gas Services, LLC

In 2006, we acquired a 50% interest in Whipstock Natural Gas Services, LLC (“Whipstock”), an unconsolidated
investee in the business of providing oil and gas drilling equipment, well servicing rigs and equipment, and other well
services in Appalachia. On the acquisition date, we contributed cash of $11.7 million representing the fair value of 50% of
the membership interest in Whipstock. In September 2013, we sold our equity method investment in Whipstock for proceeds
of $7.0 million and recognized a gain of $4.4 million.

Investment in Nora Gathering, LLC

In May 2007, we completed the initial closing of a joint development arrangement with EQT Corporation (“EQT”).

Pursuant to the terms of the arrangement, Range and EQT (“the parties”) agreed to, among other things, form a new pipeline
and natural gas gathering operations entity, Nora Gathering, LLC (“NGLLC”). NGLLC was an unconsolidated investee
created by the parties for the purpose of conducting pipeline, natural gas gathering, and transportation operations associated
with the parties’ collective interests in properties in the Nora Field. In connection with the formation, we contributed cash of

F-35

$94.7 million for a 50% membership interest in NGLLC. In the past three years, there were no additional contributions made
to fund the expansion of the Nora Field gathering system infrastructure.

NGLLC followed a calendar year basis of financial reporting consistent with us and our equity in NGLLC earnings

from the acquisition date is included in brokered natural gas, marketing and other revenue in the accompanying consolidated
statements of income for 2014, 2013 and 2012. In 2014, we received partnership distributions of $7.0 million compared to
$9.0 million in 2013 and $12.8 million in 2012. In determining our proportionate share of the net earnings of NGLLC, certain
adjustments were required to be made to NGLLC’s reported results to eliminate the profits recognized by NGLLC included
in the gathering and transportation fees charged to us on production in the Nora Field. For the six months ended June 30,
2014, our equity in losses of NGLLC of $277,000 reflects a reduction of $3.1 to eliminate the profit on gathering and
transportation fees charged to us. For the year ended December 31, 2013, our equity in losses of NGLLC of $146,000 reflects
a reduction of $7.7 million to eliminate the profit on the gathering and transportation fees charged to us. For the year ended
December 31, 2012, our equity in the losses of NGLLC of $1.2 million reflects a reduction of $7.5 million to eliminate the
profit on the gathering and transportation fees charged to us.

On June 16, 2014, as part of our Conger Exchange, we acquired the remaining 50% interest in NGLLC held by EQT.

See Note 3 for additional information. As of June 2014, we have consolidated these operations into our consolidated financial
statements.

(16) OFFICE CLOSING AND EXIT COSTS

In first quarter 2015, we announced the closing of our Oklahoma City administrative and operational office in order

to lower our general and administrative expenses, due in part to lower commodity prices. The properties will be operated
from our office in Fort Worth. As part of an ongoing benefit arrangement that was probable of occurring as of the end of the
year, 2014 includes $8.4 million of accrued severance and accelerated vesting of SARs, restricted stock and PSUs.
Additional costs, including office rent and other employee-related termination costs, related to the closing of this office will
be accrued during 2015 as required by GAAP. The following table details the accrued liability as of December 31, 2014 (in
thousands):

Beginning balance

Accrued termination costs

Ending balance

2014

—
8,371
8,371

F-36

(17) SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

The following tables set forth unaudited financial information on a quarterly basis for each of the last two years.

Second quarter 2014 includes a gain of $280.1 million from the Conger Exchange. General and administrative expense in
first quarter 2013 includes a $35.0 million Drummond lawsuit settlement accrual. Second quarter 2013 includes an additional
$52.5 million related to the Drummond legal settlement. Second quarter 2013 also includes a gain of $79.4 million from the
sale of our Delaware and Permian basin properties in southeast New Mexico and West Texas. The fourth quarter 2013
deferred tax expense includes a $21.2 million benefit for state apportionment rate adjustments (in thousands, except per share
data):

March

June

2014
September

December

Total

Revenues and other income:

Natural gas, NGLs and oil sales
Derivative fair value (loss) income
(Loss) gain on the sale of assets
Brokered natural gas, marketing and other

Total revenue and other income

572,017 $
(146,850)
(353)
32,528
457,342

477,517 $
(24,109)
282,064
30,052
765,524

446,067 $
142,057
167
28,324
616,615

416,388 $
412,422
3,760
39,644
872,214

1,911,989
383,520
285,638
130,548
2,711,695

Costs and expenses:

Direct operating
Transportation, gathering and

compression

Production and ad valorem taxes
Brokered natural gas and marketing
Exploration
Abandonment and impairment of

unproved properties
General and administrative
Termination costs
Deferred compensation plan
Interest expense
Loss on early extinguishment of debt
Depletion, depreciation and amortization
Impairment of proved properties and

other

Total costs and expenses

Income before income taxes
Income tax expense (benefit):

Current
Deferred

Net income

Net income per common share:

Basic
Diluted

$
$

39,795

34,935

37,792

37,961

150,483

74,161
11,678
34,129
14,846

9,995
49,212
—
(2,035)
45,401
—
128,682

—
405,864

76,809
10,844
34,775
13,621

9,332
56,888
—
10,519
45,488
24,596
133,361

24,991
476,159

84,777
10,110
28,706
11,443

13,444
54,963
—
(46,198)
39,188
—
142,450

—

376,675

89,542
11,923
32,370
23,638

14,308
52,363
8,371
(36,836 )
38,900
—
146,539

325,289
44,555
129,980
63,548

47,079
213,426
8,371
(74,550)
168,977
24,596
551,032

3,033

422,112

28,024
1,680,810

51,478

289,365

239,940

450,102

1,030,885

6
18,951
18,957
32,521 $

(1)
117,977
117,976
171,389 $

—
93,522
93,522
146,418 $

(4 )
166,052
166,048
284,054 $

1
396,502
396,503
634,382

0.20 $
0.20 $

1.04 $
1.04 $

0.87 $
0.86 $

1.68 $
1.68 $

3.81
3.79

F-37

March

June

2013
September

December

Total

Revenues and other income:

Natural gas, NGLs and oil sales
Derivative fair value (loss) income
(Loss) gain on the sale of assets
Brokered natural gas, marketing and other
Total revenue and other income

398,239 $
(99,875)
(166)
21,041
319,239

437,678 $
137,760
83,287
14,631
673,356

431,214 $
(40,355)
6,008
45,171
442,038

448,545 $
(59,355 )
3,162
35,734
428,086

1,715,676
(61,825)
92,291
116,577
1,862,719

Costs and expenses:

Direct operating
Transportation, gathering and compression
Production and ad valorem taxes
Brokered natural gas and marketing
Exploration
Abandonment and impairment of unproved

properties

General and administrative
Deferred compensation plan
Interest expense
Loss on early extinguishment of debt
Depletion, depreciation and amortization
Impairment of proved properties and other

Total costs and expenses

30,188
62,416
11,383
22,315
16,780

15,218
84,058
42,360
42,210
⎯
115,101
⎯
442,029

32,636
66,048
11,113
16,662
13,068

19,156
101,987
(6,878)
45,071
12,280
119,995
741
431,879

30,907
60,958
11,454
51,117
20,496

11,692
44,919
(2,225)
44,321
⎯
130,343
7,012

410,994

34,360
66,820
11,290
41,692
14,065

5,852
60,207
22,039
44,955
⎯
126,958
⎯
428,238

128,091
256,242
45,240
131,786
64,409

51,918
291,171
55,296
176,557
12,280
492,397
7,753
1,713,140

(Loss) income before income taxes
Income tax (benefit) expense:

Current
Deferred

Net (loss) income

Net (loss) income per common share:

Basic
Diluted

$
$

(122,790)

241,477

31,044

(152 )

149,579

25
(47,205)
(47,180)
(75,610) $

(25)
97,519
97,494
143,983 $

⎯
11,866
11,866
19,178 $

(143 )
(28,180 )
(28,323 )
28,171 $

(143)
34,000
33,857
115,722

(0.47) $
(0.47) $

0.88 $
0.88 $

0.12 $
0.12 $

0.17 $
0.17 $

0.71
0.70

(18) SUPPLEMENTAL INFORMATION ON NATURAL GAS AND OIL EXPLORATION, DEVELOPMENT

AND PRODUCTION ACTIVITIES (UNAUDITED)

Our natural gas and oil producing activities are conducted onshore within the continental United States and all of our

proved reserves are located within the United States.

Capitalized Costs and Accumulated Depreciation, Depletion and Amortization (a)

Natural gas and oil properties:

2014

December 31,
2013
(in thousands)

2012

Properties subject to depletion
Unproved properties

$ 9,624,725 $ 8,225,859 $ 7,368,308
743,467
10,567,971 9,032,881 8,111,775
Accumulated depreciation, depletion and amortization (2,590,398) (2,274,444 ) (2,015,591)
$ 7,977,573 $ 6,758,437 $ 6,096,184

Net capitalized costs

807,022

943,246

Total

(a) Includes capitalized asset retirement costs and the associated accumulated amortization.

F-38

Costs Incurred for Property Acquisition, Exploration and Development (a)

Acquisitions (b)
Acreage purchases
Development
Exploration:

2014

December 31,
2013
(in thousands)

2012

404,252 $
226,475
1,119,896

⎯ $
137,538
938,668

⎯
188,843
1,049,129

Drilling
Expense
Stock-based compensation expense

180,925
58,979
4,569

189,742
60,384
4,025

309,816
65,758
4,049

Gas gathering facilities:
Development
Subtotal

Asset retirement obligations
Total costs incurred

13,137
2,008,233
56,822

41,035
1,658,630
57,982
$ 2,065,055 $ 1,453,816 $ 1,716,612

47,086
1,377,443
76,373

(a) Includes cost incurred whether capitalized or expensed.
(b) See also Note 3 for additional information related to the Conger Exchange which includes $134.8 million of gas

gathering assets received in the exchange and $11.9 million of asset retirement obligations added in the exchange.

Estimated Quantities of Proved Oil and Gas Reserves (Unaudited)

Reserves of natural gas, NGLs, crude oil and condensate are estimated by our petroleum engineering staff and are

adjusted to reflect contractual arrangements and royalty rates in effect at the end of each year. Many assumptions and
judgmental decisions are required to estimate reserves. Reported quantities are subject to future revisions, some of which
may be substantial, as additional information becomes available from reservoir performance, new geological and geophysical
data, additional drilling, technological advancements, price changes, production taxes and other economic factors.

Reserve Audit

All reserve information in this report is based on estimates prepared by our petroleum engineering staff. At year-end

2014, the following independent petroleum consultants conducted an audit of our reserves: DeGolyer and MacNaughton
(Midcontinent) and Wright and Company, Inc. (Appalachia). These engineers were selected for their geographic expertise
and their historical experience in engineering certain properties. At December 31, 2014, these consultants collectively audited
approximately 96% of our proved reserves. Copies of the summary reserve reports prepared by each of these independent
petroleum consultants are included as an exhibit to this Annual Report on Form 10-K. The technical person at each
independent petroleum consulting firm responsible for reviewing the reserve estimates presented herein 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. We
maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent
petroleum consultants to ensure the integrity, accuracy and timeliness of data furnished during the reserves audit process.
Throughout the year, our technical team meets periodically with representatives of each of our independent petroleum
consultants to review properties and discuss methods and assumptions. While we have no formal committee specifically
designated to review reserves reporting and the reserves estimation process, our senior management reviews and approves
any significant changes to our proved reserves. We provide historical information to our consultants for our largest producing
properties such as ownership interest, natural gas, NGLs and oil production, well test data, commodity prices and operating
and development costs. The consultants perform an independent analysis and differences are reviewed with our Senior Vice
President of Reservoir Engineering and Economics. In some cases, additional meetings are held to review identified reserve
differences. The reserve auditor estimates of proved reserves and the pre-tax present value of such reserves discounted at
10% did not differ from our estimates by more than 10% in the aggregate. However, when compared lease-by-lease, field-by-
field or area-by-area basis, some of our estimates may be greater than those of the auditors and some may be less than the
estimates of the reserve auditors. When such differences do not exceed 10% in the aggregate, our reserve auditors are
satisfied that the proved reserves and pre-tax present value of such reserves discounted at 10% are reasonable and will issue
an unqualified opinion. Remaining differences are not resolved due to the limited cost benefit of continuing such analysis.

Historical variances between our reserve estimates and the aggregate estimates of our independent petroleum

F-39

Mr. Alan Farquharson, our Senior Vice President of Reservoir Engineering and Economics, holds a Bachelor of Science
degree in Electrical Engineering from the Pennsylvania State University. Before joining Range, he held various technical and
managerial positions with Amoco, Hunt Oil and Union Pacific Resources and has more than thirty-five years of engineering
experience in the oil and gas industry. During the year, our reserves group may also perform separate, detailed technical
reviews of reserve estimates for significant acquisitions or for properties with problematic indicators such as excessively long
lives, sudden changes in performance or changes in economic or operating conditions.

The SEC defines proved reserves as those volumes of natural gas, NGLs, crude oil and condensate that geological and
engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing
economic and operating conditions. Proved developed reserves are those proved reserves, which can be expected to be
recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes
expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is
required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it
can be demonstrated with certainty that there is continuity of production from the existing productive formation. Proved
undeveloped reserves can only be assigned to acreage for which improved recovery technology is contemplated when such
techniques have been proven effective by actual tests in the area and in the same reservoir. Undrilled locations can be
classified as having undeveloped reserves only if a development plan has been adopted indicating each location is scheduled
to be drilled within five years from the date it was booked as proved reserves, unless specific circumstances justify a longer
time.

The reported value of proved reserves is not necessarily indicative of either fair market value or present value of future
net cash flows because prices, costs and governmental policies do not remain static, appropriate discount rates may vary, and
extensive judgment is required to estimate the timing of production. Other logical assumptions would likely have resulted in
significantly different amounts.

The average realized prices used at December 31, 2014 to estimate reserve information were $79.04 per barrel of oil,

$27.20 per barrel of NGLs and $4.14 per mcf for gas, using a benchmark (NYMEX) of $94.42 per barrel and $4.35 per
Mmbtu. The average realized prices used at December 31, 2013 to estimate reserve information were $86.66 per barrel of oil,
$25.93 per barrel of NGLs and $3.75 per mcf for gas, using a benchmark (NYMEX) of $97.33 per barrel and $3.67 per
Mmbtu. The average realized prices used at December 31, 2012 to estimate reserve information were $86.91 per barrel of oil,
$32.23 per barrel of NGLs and $2.75 per mcf for gas, using a benchmark (NYMEX) of $95.05 per barrel and $2.76 per
MMbtu.

F-40

Proved developed and undeveloped reserves:

Balance, December 31, 2011

Revisions
Extensions, discoveries and additions
Purchases
Property sales
Production

Balance, December 31, 2012

Revisions
Extensions, discoveries and additions
Purchases
Property sales
Production

Balance, December 31, 2013

Revisions
Extensions, discoveries and additions
Purchases
Property sales
Production

Balance, December 31, 2014

Proved developed reserves:

December 31, 2012
December 31, 2013
December 31, 2014

Proved undeveloped reserves:
December 31, 2012
December 31, 2013
December 31, 2014

Natural Gas
(Mmcf)

NGLs
(Mbbls)

Crude Oil and
Condensate

(Mbbls)

Natural Gas
Equivalents
(Mmcfe) (a)

4,009,676
76,925
996,059
—

(73,429)
(216,555)

4,792,676
384,825
853,746
⎯

(101,074)
(264,528)

5,665,645

(30,566)

1,393,108
262,813
(81,238)
(286,926)

6,922,836

2,373,604
2,797,483
3,583,051

2,419,072
2,868,162
3,339,785

142,515
3,036
113,392
—

(11,575)
(6,969)

240,399
7,743
135,810
⎯
(286)
(9,254)

374,412
19,716
154,664
⎯
(14,064)
(18,821)

515,907

154,984
206,477
270,271

85,415
167,935
245,636

31,532
2,316
15,131
—
(1,046 )
(2,851 )

45,082
2,935
10,723
⎯
(6,553 )
(3,827 )

48,360
515
12,936
⎯
(9,083 )
(4,070 )

5,053,961
109,036
1,767,202
—
(149,153)
(275,476)

6,505,570
448,898
1,732,944
⎯
(142,116)
(343,022)

8,202,274
90,822
2,398,709
262,813
(220,122)
(424,267)

48,658

10,310,229

25,667
26,054
24,180

19,415
22,306
24,478

3,457,502
4,192,666
5,349,761

3,048,068
4,009,608
4,960,468

(a) Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to

natural gas, which is not indicative of the relationship of oil and natural gas prices.

During 2014, we added approximately 2.4 Tcfe of proved reserves from drilling activities and evaluation of proved

areas primarily in the Marcellus Shale. Approximately 58% of 2014 reserve additions were attributable to natural gas.
Included in 2014 proved reserves is a total of 1,170 Bcfe of ethane reserves (264.3 Mmbbls) in the Marcellus Shale.
Revisions of previous estimates of a net 91 Bcfe includes positive performance revisions, improved recovery primarily from
our Marcellus Shale natural gas properties and positive price revisions are somewhat offset by reserves of 611 Bcfe
reclassified to unproved as we continue to see success from drilling longer laterals, increasing the number of frac stages and
better lateral targeting which caused some previously planned wells to not be drilled within the original five-year
development horizon.

During 2013, we added approximately 1.7 Tcfe of proved reserves from drilling activities and valuation of proved

areas primarily in the Marcellus Shale. Approximately 49% of 2013 reserve additions were attributable to natural gas. Also,
included in 2013 proved reserves is a total of 676 Bcfe of ethane reserves (155.8 Mmbbls) in the Marcellus Shale. Revisions
of previous estimates of a net 449 Bcfe includes positive performance revisions and improved recovery primarily from our
Marcellus Shale natural gas properties and positive pricing revisions, somewhat offset by reserves reclassified to unproved
because of a slower pace of development activity beyond the five-year development horizon.

F-41

During 2012, we added approximately 1.8 Tcfe of proved reserves from drilling activities and evaluation of proved
areas primarily in the Marcellus Shale. Approximately 56% of the 2012 reserve additions were attributable to natural gas.
Also included in 2012 additions is 307 Bcfe of ethane reserves (51.2 Mmbbls) in the Marcellus Shale which was associated
with initial ethane deliveries under contracts commencing in 2013. Revisions of previous estimates of a net 109 Bcfe include
positive performance revisions primarily from our Marcellus Shale natural gas properties, partially offset by negative pricing
revisions.

The following details the changes in proved undeveloped reserves for 2014 (Mmcfe):

Beginning proved undeveloped reserves at December 31, 2013

Undeveloped reserves transferred to developed
Revisions (a)
Purchases/ (sales)
Extension and discoveries

Ending proved undeveloped reserves at December 31, 2014

4,009,608
(620,167 )
(147,019 )
(58,045 )
1,776,091
4,960,468

(a) Includes 611,341 Mmcfe of proved undeveloped reserves dropped due to the five year rule.

Approximately $591.0 million was spent during 2014 related to undeveloped reserves that were transferred to
developed reserves. Estimated future development costs of proved undeveloped reserves are projected to be approximately
$981.1 million in 2015, $1.0 billion in 2016 and $993.5 million in 2017. Included in proved undeveloped reserves at
December 31, 2014 are approximately 3 bcfe of reserves (less than 1% of total proved undeveloped reserves) that have been
reported for five or more years. All proved undeveloped drilling locations are scheduled to be drilled prior to the end of 2019.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)

The following summarizes the policies we used in the preparation of the accompanying natural gas, NGLs, crude oil

and condensate reserve disclosures, standardized measures of discounted future net cash flows from proved natural gas,
NGLs and oil reserves and the reconciliations of standardized measures from year to year. The information disclosed is an
attempt to present the information in a manner comparable with industry peers.

The information is based on estimates of proved reserves attributable to our interest in natural gas and oil properties as

of December 31 of the years presented. These estimates were prepared by our petroleum engineering staff. Proved reserves
are estimated quantities of natural gas, NGLs, crude oil and condensate, which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating
conditions.

The standardized measure of discounted future net cash flows from production of proved reserves was developed as

follows:

Estimates are made of quantities of proved reserves and future amounts expected to be produced based on
current year-end economic conditions.

For the years ended 2014, 2013 and 2012, estimated future cash inflows are calculated by applying a
twelve-month average price of natural gas, NGLs and oil relating to our proved reserves to the quantities
of those reserves produced in each future year.

Future cash flows are reduced by estimated production costs, administrative costs, costs to develop and
produce the proved reserves and abandonment costs, all based on current year-end economic conditions.
Future income tax expenses are based on current year-end statutory tax rates giving effect to the
remaining tax basis in the natural gas, NGLs and oil properties, other deductions, credits and allowances
relating to our proved natural gas and oil reserves.
The resulting future net cash flows are discounted to present value by applying a discount rate of 10%.

The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present
the fair value of our natural gas, NGLs and oil reserves. An estimate of fair value would also take into account, among other
things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a
discount factor more representative of the time value of money and the risks inherent in reserve estimates.

F-42

The standardized measure of discounted future net cash flows relating to proved natural gas, NGLs, crude oil and

condensate reserves is as follows and excludes cash flows associated with derivatives outstanding at each of the respective
reporting dates. Future cash inflows are net of third party transportation, gathering and compression expense.

Future cash inflows
Future costs:

Production
Development (a)

As of December 31,
2013

2014

(in thousands)
$ 46,507,646 $ 35,143,097

(15,239,210 ) (10,176,140)
(4,275,693 ) (3,938,296)

Future net cash flows before income taxes

26,992,743 21,028,661

Future income tax expense

(8,900,383 ) (6,913,196

)

Total future net cash flows before 10% discount

18,092,360 14,115,465

10% annual discount

(10,499,333 ) (8,253,234

)

Standardized measure of discounted future net cash flows

$ 7,593,027 $ 5,862,231

(a) 2014 includes $439.6 million of undiscounted future asset retirement costs estimated as of December 31, 2014, using current

estimates of future abandonment costs.

The following table summarizes changes in the standardized measure of discounted future net cash flows.

Revisions of previous estimates:

Changes in prices and production costs
Revisions in quantities
Changes in future development and abandonment costs
Net change in income taxes

Accretion of discount
Purchases of reserves in place
Additions to proved reserves from extensions, discoveries

2014

December 31,
2013
(in thousands)

2012

5,069 $ 2,172,704 $ (2,498,616)
88,190
(354,766)
832,830
608,381
—

513,168
102,760
(407,688)
(275,468 )
(441,935) (1,299,227 )
395,989
789,754
⎯
297,358

755,384
(249,055)
(443,187)

2,713,999 1,981,054
(1,391,663) (1,286,103 )
462,862
(162,463 )
135,910
1,730,796 2,638,426
5,862,231 3,223,805

1,429,340
(976,224)
562,329
(120,637)
(861,919)
(1,291,092)
4,514,897
$ 7,593,027 $ 5,862,231 $ 3,223,805

and improved recovery

Natural gas, NGLs and oil sales, net of production costs
Development costs incurred during the period
Sales of reserves in place
Timing and other
Net change for the year
Beginning of year
End of year

F-43

Range Resources Corporation

Range is a leading independent oil and natural gas company with operations in Appalachia and the southwest region of the United States.

The Company pursues an organic growth strategy targeting high-return, low-cost projects within its large inventory of low-risk drilling

opportunities. As of December 31, 2014, Range had 10.3 Tcfe of proved reserves, a 26% increase over the prior year, and a 34% increase in

crude oil and NGL volumes over the prior year. In addition, Range estimates 66-87 Tcfe in net unrisked resource potential from its current

acreage position. Range’s common stock is listed on the New York Stock Exchange under the symbol “RRC.” More information about Range

can be found at www.rangeresources.com.

BOAR D OF DIRE CTORS

SEnIOR MAnAgEMEnT

ANTH O NY V. DUB 1

Chairman, Indigo Capital, LLC

J EF FR E Y L . V ENT U RA

V. RICHARD EALES 1,5

AL LEN FI NKELSON 2,4

JAM ES M. FUNK 1,2,3

CH RIS TOpH ER A. HELMS 4

Retired Executive Vice President,
Union Pacific Resources Group

Retired Partner, Cravath,
Swaine & Moore LLP

President, J.M. Funk & Associates,
past President of Shell Oil Co. and
Equitable Production Co.

Founder and CEO, US Shale Energy
Advisors LLC, past Executive Vice
President & Group CEO, NiSource, Inc.

R OG ER S . M AN NY

R AY N . WA L KE R , JR .

J OH N K. Ap pLE G AT H

A LA N W. FA RQ UH AR S ON

DOR I A . G IN N

JO NAT HAN S. LINKER 1,4

Energy Consultant

M ARY RALpH LOWE 4

President & CEO, Maralo, LLC

DAV ID p. pOO L E

KEV IN S. McCARTHY 2,4

JO H N H . pINKERTON 3

JE FFRE Y L. VENTUR A

Chairman, Chief Executive Officer
& President, Kayne Anderson MLP

Former Chairman, President & Chief
Executive Officer, Range Resources
Corporation

Chairman, President & Chief Executive
Officer, Range Resources Corporation

C HA D L . S TEpH E NS

R ODN EY L . WA L L ER

Board Committee Membership: 1 Audit, 2 Compensation,
3 Dividend, 4 Governance and Nominating, 5 Lead Director

Chairman, President &
Chief Executive Officer

Executive Vice President –
Chief Financial Officer

Executive Vice President –
Chief Operating Officer

Senior Vice President –
S. Marcellus Shale Division

Senior Vice President –
Reservoir Engineering & Economics

Senior Vice President – Controller
& Principal Accounting Officer

Senior Vice President – General
Counsel & Corporate Secretary

Senior Vice President –
Corporate Development

Senior Vice President
& Assistant Secretary

FORM 10-K

TRAnSFER AgEnT

Additional copies of the Company’s Annual Report on Form 10-K filed with the
Securities and Exchange Commission may be obtained upon request from Investor
Relations at our headquarters’ address.

Inquiries about the Company should be directed to:

INVESTOR RELATIONS
RANGE RESOURCES CORpORATION
100 THROCKMORTON ST., SUITE 1200
FORT WORTH, TX 76102
817-870-2601
817-869-9166 (FAX)

For assistance regarding a change of address or
concerning your stock account, please contact:

COMpUTERSHARE, INC.
p.O. BOX 43078
pROVIDENCE, RI 02940
877-588-4114
HTTpS://WWW-US.COMpUTERSHARE.COM/INVESTOR/CONTACT

Use our web site to obtain the latest news releases
and SEC filings: WWW.RANGERESOURCES.COM

In addition to historical information, this report contains forward-looking statements that may vary materially from actual
results. Factors that could cause actual results to differ are included in the Company’s Form 10-K for the year ended December
31, 2014, which has been filed with the Securities and Exchange Commission.

Range has posted on its website detailed calculations of EBITDAX, all-in finding costs and drill bit finding cost.

This book has been printed on paper that is FSC certified. The Forest Stewardship Council (FSC) is a non-profit organization devoted
to encouraging the responsible management of the world’s forests. The FSC sets high standards that ensure forestry is practiced in
an environmentally responsible, socially beneficial and economically viable way.