e10vk
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark one)
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year-ended December 31, 2007
or
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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)
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Delaware
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34-1312571 |
(State or Other Jurisdiction of Incorporation or Organization)
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(IRS Employer Identification No.) |
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100 Throckmorton Street, Suite 1200, Fort Worth, Texas
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76102 |
(Address of Principal Executive Offices)
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(Zip Code) |
Registrants Telephone Number, Including Area Code
(817) 870-2601
Securities registered pursuant to Section 12(b) of the Act:
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Title Of Each Class
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Name Of Each Exchange On Which Registered |
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Common Stock, $.01 par value
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New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant as a well-known seasoned issuer, as defined in Rule
405 of the Securities Act.
Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section
13 or Section 15(d) of the Act.
Yes o No þ
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 þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation
S-K is not contained herein, and will not be contained, to the best of registrants 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. o
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):
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Large accelerated filer þ
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Accelerated filer o
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Non-accelerated filer o
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Smaller reporting company o |
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(Do not check if a smaller reporting company) |
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act).
Yes o No þ
The aggregate market value of the voting and non-voting common equity held by non-affiliates
(excluding voting shares held by officers and directors) as of June 29, 2007 was $5,459,435,000.
As of February 20, 2008, there were 149,903,625 shares of Range Resources Corporation Common
Stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the registrants proxy statement to be furnished to stockholders in connection
with its 2008 Annual Meeting of Stockholders 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 wholly-owned subsidiaries and its ownership
interests in equity method investees. Unless otherwise noted, all information in the report
relating to oil and gas 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.
TABLE OF CONTENTS
ii
RANGE RESOURCES CORPORATION
Annual Report on Form 10-K
Year Ended December 31, 2007
Disclosures Regarding Forward-Looking Statements
Certain information included in this report, other materials filed or to be filed with the
Securities and Exchange Commission (the SEC), as well as information included in oral statements
or other written statements made or to be made by us contain or incorporate by reference certain
statements (other than statements of historical fact) that constitute forward-looking statements
within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. When used herein, the words budget, budgeted, assumes, should,
goal, anticipates, expects, believes, seeks, plans, estimates, intends, projects
or targets and similar expressions that convey the uncertainty of future events or outcomes are
intended to identify forward-looking statements. Where any forward-looking statement includes a
statement of the assumptions or bases underlying such forward-looking statement, we caution that
while we believe these assumptions or bases to be reasonable and to be made in good faith, assumed
facts or bases almost always vary from actual results and the difference between assumed facts or
bases and the actual results could be material, depending on the circumstances. It is important to
note that our actual results could differ materially from those projected by such forward-looking
statements. Although we believe that the expectations reflected in such forward-looking statements
are reasonable and such forward-looking statements are based upon the best data available at the
date this report is filed with the SEC, we cannot assure you that such expectations will prove
correct. Factors that could cause our results to differ materially from the results discussed in
such forward-looking statements include, but are not limited to, the following: the factors listed
in Item 1A of this report under the heading Risk Factors, production variance from expectations,
volatility of oil and gas prices, hedging results, the need to develop and replace reserves, the
substantial capital expenditures required to fund operations, exploration risks, environmental
risks, uncertainties about estimates of reserves, competition, litigation, government regulation,
political risks, our ability to implement our business strategy, costs and results of drilling new
projects, mechanical and other inherent risks associated with oil and gas production, weather,
availability of drilling equipment and changes in interest rates. All such forward-looking
statements in this document are expressly qualified in their entirety by the cautionary statements
in this paragraph, and we undertake no obligation to publicly update or revise any forward-looking
statements.
PART I
ITEM 1. BUSINESS
General
We are a Fort Worth, Texas-based independent oil and gas company, engaged in the exploration,
development and acquisition of oil and gas properties, primarily in the Southwestern, Appalachian
and Gulf Coast regions of the United States. We were incorporated in early 1980 under the name
Lomak Petroleum, Inc. and, later that year, we completed an initial public offering and began
trading on the NASDAQ. In 1996, our common stock was listed on the New York Stock Exchange. In
1998, we changed our name to Range Resources Corporation. In 1999, we implemented a strategy of
internally generated drillbit growth coupled with complementary acquisitions. Our objective is to
build stockholder value through consistent growth in reserves and production on a cost-efficient
basis. During the past five years, we have increased our proved reserves 286%, while production
has increased 115% during that same period.
At year-end 2007, our proved reserves had the following characteristics:
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2.2 Tcfe of proved reserves; |
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82% natural gas; |
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64% proved developed; |
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77% operated; |
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a reserve life of 17.7 years (based on fourth quarter 2007 production); |
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a pre-tax present value of $5.2 billion of future net revenues attributable to our
reserves, discounted at 10% per annum (PV-10); and |
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a standardized measure of discounted future net cash flows of $3.7 billion (after
tax). |
PV-10 may be 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,
1
because it presents the discounted future net cash flows attributable to our proved reserves prior
to taking into account corporate future 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. The difference between the standardized
measure and the PV-10 amount is discounted estimated future income tax of $1.5 billion at December
31, 2007.
At year-end 2007, we owned 3,385,000 gross (2,695,000 net) acres of leasehold, including
407,800 acres where we also own a royalty interest. We have built a multi-year inventory drilling
that is estimated to contain over 11,000 drilling locations, with approximately 8,500 drilling
locations in our Appalachian region.
Our corporate offices are located at 100 Throckmorton Street, Suite 1200, Fort Worth, Texas
76102. Our telephone number is (817) 870-2601.
Business Strategy
Our objective is to build stockholder value through consistent growth in reserves and
production on a cost-efficient basis. Our strategy is to employ internally generated drillbit
growth coupled with complementary acquisitions. Our strategy requires us to make significant
investments in technical staff, acreage and seismic data and technology to build drilling
inventory. Our strategy has the following principal elements:
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Concentrate in Core Operating Areas. We currently operate in three regions; the
Southwestern (which includes the Barnett Shale of North Central Texas, the Permian
Basin of West Texas and eastern New Mexico, the East Texas Basin, the Texas Panhandle
and Anadarko Basin of Western Oklahoma), Appalachian (which includes tight-gas, shale,
coal bed methane and conventional oil and gas production in Pennsylvania, Virginia,
Ohio, New York and West Virginia) and the Gulf Coast (which includes onshore Texas,
Louisiana and Mississippi). Concentrating our drilling and producing activities in
these core areas allows us to develop the regional expertise needed to interpret
specific geological and operating trends and develop economies of scale. Operating in
multiple core areas allows us to blend the production characteristics of each area to
balance our portfolio toward our goal of consistent production and reserve growth. |
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Maintain Multi-Year Drilling Inventory. We focus on areas where multiple
prospective productive horizons and development opportunities exist. We use our
technical expertise to build and maintain a multi-year drilling inventory. A large,
multi-year inventory of drilling projects increases our ability to consistently grow
production and reserves. Currently, we have over 11,000 identified drilling locations
in inventory. In 2007, we drilled 967 gross (698 net) wells. In 2008, our capital
program targets the drilling of 968 gross (715 net) wells. |
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Make Complementary Acquisitions. We target complementary acquisitions in existing
core areas and focus on acquisition opportunities where our existing operating and
technical knowledge is transferable and drilling results can be forecast with
confidence. Over the past three years, we have completed $903.8 million of
complementary acquisitions. These acquisitions have been located in the Southwestern
and Appalachian regions. |
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Maintain Long Life, Low Decline Reserve Base. Long life, low decline, oil and gas
reserves provide a more stable growth platform than short life, high decline reserves.
Long life reserves reduce reinvestment risk as they lessen the amount of reinvestment
capital deployed each year to replace production. Long life, low decline oil and gas
reserves also assist us in minimizing costs as stable production makes it easier to
build and maintain operating economies of scale. Lastly, the inherent greater
predictability of low decline oil and gas reserve production better lends itself to
commodity price hedging than high decline reserves. We use our acquisition,
divestiture, and drilling activity to execute this strategy. |
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Maintain Flexibility. Because of the volatility of commodity prices and the risks
involved in drilling, we remain flexible and adjust our capital budget throughout the
year. We may defer capital projects to seize an attractive acquisition opportunity.
If certain areas generate higher than anticipated returns, we may accelerate drilling
in those areas and decrease capital expenditures elsewhere. We also believe in
maintaining a strong balance sheet and using commodity hedging. This allows us to be
more opportunistic in lower price environments as well as providing more consistent
financial results. |
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Equity Ownership and Incentive Compensation. We want our employees to act like
owners. To achieve this, we reward and encourage them through equity ownership in us.
As of December 31, 2007, our employees owned equity securities (vested and unvested)
that had an aggregate market value of approximately $260 million. |
2
Significant Accomplishments in 2007
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Production and reserve growth The fourth quarter of 2007 marked the 20th
consecutive quarter of sequential production growth. In 2007, our annual production
averaged 319.0 Mmcfe per day, an increase of 22% from 2006, after reclassification of
2006 to report the results of the Gulf of Mexico properties sold in the first quarter
of 2007 as discontinued operations. See Note 4 to our consolidated financial
statements. This achievement is the result of our continued drilling success and the
completion and integration of complementary acquisitions. Our business is inherently
volatile, and while consistent growth such as we have experienced over the past five
years will be challenging to sustain, the quality of our technical teams and our
sizable drilling inventory bode well for the future. Proven reserves increased 27% in
2007 to 2.2 Tcfe, marking the sixth consecutive year our proven reserves have
increased. |
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Successful drilling program In 2007, we drilled 967 gross wells. Production was
replaced by 416% through drilling in 2007, and our overall success rate was 98%. As we
continue to build our drilling inventory for the future, our ability to drill a large
number of wells each year on a cost effective and efficient basis is critical. |
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Continued expansion of drilling inventory and emerging plays To continue to grow,
the size of our prospect inventory must remain large. Our drilling inventory currently
includes over 11,000 projects, up from 9,400 at year-end 2006. We engaged in
meaningful expansion of our coal bed methane plays and our shale plays in 2007. We
have now leased 286,000 net acres in our coal bed methane plays and 1.0 million net
acres in our shale plays. We have hired additional experienced technical professionals
to assist us in these emerging plays. |
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Record financial results and balance sheet enhancement Growth in production
volumes and higher oil and gas prices drove our record financial performance in 2007.
Revenue, net income, and net cash flow provided from operating activities all reached
annual record highs. On the balance sheet, we refinanced $250 million of shorter term
bank debt with a like amount of senior subordinated fixed rate 7.5% notes having a
10-year maturity. This helped to align the maturity schedule of our debt with the
long-term life of our assets. Financial leverage, as measured by the
debt-to-capitalization ratio improved from 46% to 40%. Future cash flow will be
enhanced through low income tax payments due to a $204.4 million net operating loss
carryforward. |
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Successful acquisitions completed In 2007, we
acquired $260.9 million of
properties located in our core areas. The largest acquisition involved acquiring
additional interests in the Nora field of Virginia, where we entered into a joint
development plan with Equitable Resources, Inc. (Equitable). As a result of this
transaction, Equitable and Range equalized their working interests in the Nora field,
including producing wells, undrilled acreage and gathering systems. Range retained
separately owned royalty interests in the field. Equitable operates the producing
wells, manages the drilling operations of all future coal bed methane wells and manages
the gathering system. Range oversees the drilling of formations below the coal bed
methane formations, including tight gas, shale and deeper formations. A newly formed
limited liability company, owned 50% by Equitable and 50% by Range, holds the
investment in the gathering system. |
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Successful dispositions completed In February 2007, we sold the Austin Chalk
properties for proceeds of $80.4 million. In March 2007, we sold our Gulf of Mexico
properties for proceeds of $155.0 million. As a result of these divestitures, we
lowered our overall production decline rate and lengthened our reserve life. See Note
4 to our consolidated financial statements. |
Plans for 2008
We have announced a $1.1 billion capital budget for 2008, excluding acquisitions. The budget
includes $783 million to drill 968 gross (715 net) wells and to undertake 82 gross (66 net)
recompletions. Also included is $109 million for land, $51 million for seismic and $122 million
for the expansion and enhancement of gathering systems and facilities. Approximately 56% of the
budget is attributable to the Southwest Area, 40% to the Appalachia Area and 4% to the Gulf Coast
Area.
3
Production, Revenues and Price History
The following table sets forth information regarding oil and gas production, revenues and
direct operating expenses for the last three years. The information set forth in this table
reflects the reclassification of prior year amounts to report the results of operations of our Gulf
of Mexico properties sold in the first quarter of 2007 as discontinued operations. For additional
information on price calculations, see information set forth in Item 7. Managements Discussion
and Analysis of Financial Condition and Results of Operations.
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Year Ended December 31, |
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2007 |
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2006 |
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2005 |
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Production |
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Gas (Mmcf) |
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89,595 |
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70,713 |
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57,609 |
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Crude oil (Mbbls) |
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3,360 |
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3,039 |
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2,929 |
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Natural gas liquids (Mbbls) |
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1,115 |
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1,092 |
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1,012 |
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Total (Mmcfe) (a) |
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116,441 |
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95,498 |
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81,253 |
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Revenues ($000) |
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Gas |
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$ |
613,454 |
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$ |
418,183 |
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$ |
354,728 |
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Crude oil |
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202,931 |
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144,251 |
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113,153 |
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Natural gas liquids |
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46,152 |
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36,705 |
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27,589 |
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Transportation and gathering |
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2,290 |
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2,422 |
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2,306 |
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Derivative fair value income (loss) |
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(7,767 |
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142,395 |
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10,303 |
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Less: Mark-to-market component of derivative fair value
income (loss) (c) |
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79,589 |
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(92,456 |
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(7,397 |
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Total |
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936,649 |
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651,500 |
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500,682 |
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Direct operating expenses (b) |
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108,741 |
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81,261 |
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57,866 |
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Production and ad valorem taxes |
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42,443 |
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36,415 |
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30,822 |
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Gross margin |
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$ |
785,465 |
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$ |
533,824 |
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$ |
411,994 |
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Average sales price (wellhead) |
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Gas (per mcf) |
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$ |
6.54 |
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$ |
6.59 |
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$ |
8.00 |
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Crude oil (per bbl) |
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67.47 |
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62.36 |
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53.30 |
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Natural gas liquids (per bbl) |
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41.40 |
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33.62 |
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31.52 |
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Total (per mcfe) (a) |
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7.37 |
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7.25 |
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7.99 |
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Average realized price (including all derivative settlements) |
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Gas (per mcf) |
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$ |
7.66 |
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$ |
6.62 |
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$ |
6.21 |
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Crude oil (per bbl) |
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60.16 |
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47.46 |
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38.63 |
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Natural gas liquids (per bbl) |
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41.40 |
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33.62 |
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27.27 |
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Total (per mcfe) (a) |
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8.02 |
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6.80 |
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6.13 |
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Operating costs (per mcfe) |
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Direct (b) |
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$ |
0.93 |
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$ |
0.85 |
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$ |
0.71 |
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Production and ad valorem taxes |
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0.36 |
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0.38 |
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0.38 |
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Total operating costs |
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$ |
1.29 |
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$ |
1.23 |
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$ |
1.09 |
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Gross margin (per mcfe) |
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$ |
6.74 |
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$ |
5.59 |
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$ |
5.07 |
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(a) |
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Oil and NGLs are converted at the rate of one barrel equals six mcfe. |
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2007 direct operating expenses include $1.8 million (or $0.02 per mcfe) of
stock-based compensation. 2006 direct operating expenses include $1.4 million (or $0.01 per
mcfe) of stock-based compensation. |
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(c) |
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By adding this component, the total reflects realized gains (losses) on those
derivatives that do not qualify for hedge accounting and excludes unrealized gains (losses) on
derivatives that do not qualify for hedge accounting. |
Employees
As of January 1, 2008, we had 733 full-time employees, 371 of whom were field personnel. All
full-time employees are eligible to receive equity awards approved by the Compensation Committee of
the Board of Directors. No employees are 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, on-site production operation services and certain
accounting functions.
4
Available Information
We maintain an internet website under the name www.rangeresources.com. 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 providing such reports to the SEC. Also, 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 chief executive officer and senior
financial officers.
We file annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on
Form 8-K, proxy statements and other documents with the SEC under the Securities Exchange Act of
1934. The public may read and copy any materials that we file with the SEC at the SECs 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 www.sec.gov. 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 that we make with the SEC.
Competition
We encounter substantial competition in developing and acquiring oil and gas properties,
securing and retaining personnel, conducting drilling and field operations and marketing
production. Competitors in exploration, development, acquisitions and production include the major
oil companies as well as numerous independent oil 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 to 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.
Marketing and Customers
We market nearly all of our oil and gas production from the properties we operate for both our
interest and that of the other working interest owners and royalty owners. We sell our gas
pursuant to a variety of contractual arrangements; generally month-to-month and one to five-year
contracts. Less than 1% of our production is subject to contracts longer than five years. Pricing
on the month-to-month and short-term contracts is based largely on the New York Mercantile Exchange
(NYMEX) pricing, with fixed or floating basis. For one to five-year contracts, we sell our gas
on NYMEX pricing, published regional index pricing or percentage of proceeds sales based on local
indices. We sell less than 500 mcf per day under long-term fixed price contracts. Many contracts
contain provisions for periodic price adjustment, termination and other terms customary in the
industry. We sell our gas to utilities, marketing companies and industrial users. We sell our oil
under contracts ranging in terms from month-to-month, up to as long as one year. The pricing for
oil is based upon the posted prices set by major purchasers in the production area or upon NYMEX
pricing or fixed pricing. All oil pricing is adjusted for quality and transportation. Oil and gas
purchasers are selected on the basis of price, credit quality and service. For a summary of
purchasers of our oil and gas production that accounted for 10% or more of consolidated revenue,
see Note 15 to our consolidated financial statements. Because alternative purchasers of oil and
gas are usually readily available, we believe that the loss of any of these purchasers would not
have a material adverse effect on us.
We enter into hedging transactions with unaffiliated third parties for significant portions of
our production to achieve more predictable cash flows and to reduce our exposure to short-term
fluctuations in oil and gas prices. For a more detailed discussion, see the information set forth
in Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations
and Item 7A. Quantitative and Qualitative Disclosures about Market Risk. Proximity to local
markets, availability of competitive fuels and overall supply and demand are factors affecting the
prices for which our production can be sold. Market volatility due to international political
developments, overall energy supply and demand, fluctuating weather conditions, 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 incur gathering and transportation expenses to move our natural gas and crude oil 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 transporters. In the Southwestern and Gulf
Coast Areas, our natural gas and oil production are transported primarily through third-party
trucks, gathering systems and pipelines. Transportation space on these gathering systems and
pipelines is occasionally limited. In Appalachia, we own approximately 5,100 miles of gas
gathering pipelines which transport a majority
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of our Appalachian gas production as well as third-party gas to transmission lines and directly to
end-users and interstate pipelines. For additional information, see Risk Factors Our business
depends on oil and natural gas transportation facilities, many of which are owned by others, in
Item 1A of this report.
Governmental Regulation
Our operations are substantially affected by federal, state and local laws and regulations.
In particular, oil and gas production and related operations are, or have been, subject to price
controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own
or operate producing crude oil and natural gas properties have statutory provisions regulating the
exploration for and production of crude oil and natural gas, including provisions related to
permits for the drilling of wells, bonding requirements to drill or operate wells, the location of
wells, the method of drilling and casing wells, the surface use and restoration of properties upon
which wells are drilled, and the abandonment of wells. Our operations are also subject to various
conservation laws and regulations. These include the regulation of the size of drilling and
spacing units or proration units, the number of wells which may be drilled in an area, and the
unitization or pooling of crude oil and natural gas wells, generally prohibit the venting or
flaring of natural gas, and impose certain requirements regarding the ratability or fair
apportionment of production from fields and individuals wells.
In August 2005, Congress enacted the Energy Policy Act of 2005 (EPAct 2005). Among other
matters, the 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 (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 FERC, or the purchase or sale of
transportation services subject to the jurisdiction of 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 to make any such statement necessary to make the statements made
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 up to $1,000,000 per day per violation. The new anti-manipulation rule does not apply to
activities that relate only to intrastate or other non-jurisdictional sale 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 FERC jurisdiction.
It therefore reflects a significant expansion of FERCs enforcement authority. Range does not
anticipate it will be affected any differently than other producers of natural gas.
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 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.
Environmental and Occupational Matters
Our operations are subject to stringent federal, state and local laws governing the discharge
of materials into the environment or otherwise relating to environmental protection. Numerous
governmental departments such as the United States Environmental Protection Agency (EPA) issue
regulations to implement and enforce such laws, which are often difficult and costly to comply with
and 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, 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
former operations such as plugging abandoned wells or closing earthen pits and impose substantial
liabilities for pollution resulting from operations. In addition, these laws and regulations may
restrict the rate of production. The regulatory burden imposed on the oil and gas industry by
these laws and regulations increases the cost of doing business, affecting growth and
profitability. Changes in environmental laws and regulations occur frequently, and changes that
result in more stringent and costly waste handling, disposal or clean-up requirements could
adversely affect our operations and financial position, as well as the industry in general. We
believe we are in substantial compliance with current 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 2007, nor do we anticipate that such
expenditures will be material in 2008.
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The Comprehensive Environmental Response, Compensation and Liability Act, as amended,
(CERCLA), 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 include owners or operators of the disposal site or sites where the 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, such persons may be subject to joint and several
liabilities 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 and it is
not uncommon for neighboring landowners and other third parties to file claims for personal injury
and property damages allegedly caused by the release of hazardous substances or other pollutants
into the environment pursuant to environmental statutes, common law or both. 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 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. Beyond CERCLA, state laws regulate the disposal of oil and gas wastes,
and periodically new state legislative initiatives are proposed that could have a significant
impact on us.
We also may incur liability under the Resource Conservation and Recovery Act, as amended
(RCRA), which imposes requirements related to the handling and disposal of solid and hazardous
wastes. While there exists an exclusion from the definition of hazardous wastes for drilling
fluids, produced waters, and other wastes associated with the exploration, development, or
production of crude oil, natural gas or geothermal energy, these wastes may be regulated by the
EPA or state agencies as non-hazardous solid waste. Moreover, ordinary industrial wastes, such as
paint wastes, waste solvents, laboratory wastes and waste compressor oils, can 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.
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. Although we
used operating and disposal practices that were standard in the industry at the time, 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 wastes 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 analogous state laws.
Under such laws, 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 (FWPCA), and analogous state laws impose
restrictions and strict controls regarding the discharge of pollutants, including produced waters
and other oil and 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 EPA or
the state. These laws provide for administrative, civil and criminal penalties for any
unauthorized discharges of oil and other hazardous 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 are currently undertaking a review
of recently acquired oil and gas 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 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. While 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 addressing other air emission-related
issues, we do not believe that such requirements will have a material adverse affect on our
operations.
Changes in environmental laws and regulations occur frequently, and any changes that result in
more stringent and costly waste handling, storage, transport, disposal or cleanup requirements
could materially adversely affect our operations and financial position, as well as those of the
oil and gas industry in general. For instance, recent scientific studies have suggested that
emissions of certain gases, commonly referred to as greenhouse gases and including carbon dioxide
and methane, may be contributing to warming of the Earths atmosphere. In response to such
studies, the U.S. Congress is actively considering climate change-related legislation to restrict
greenhouse gas emissions. One bill recently approved by the U.S. Senate Environment and Public
Works Committee, known as the Lieberman Warner Climate Security Act or S. 2191, would require a
70% reduction in emissions of greenhouse gases from sources within the United States between 2012
and 2050. A vote on
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this bill by the full Senate is expected to occur before mid-year 2008. In addition, at least 17
states have already taken legal measures to reduce emissions of greenhouse gases, primarily through
the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap
and trade programs. Also, as a result of the U.S. Supreme Courts decision on April 2, 2007 in
Massachusetts, et al. v. EPA, the EPA may be required to regulate greenhouse gas emissions from
mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically
addressing emissions of greenhouse gases. The EPA has indicated that it will issue a rulemaking
notice to address greenhouse gas emissions from vehicles and automobile fuels, although the date
for the issuance of this notice has not been finalized. The Courts holding in Massachusetts that
greenhouse gases fall under the federal Clean Air Acts definition of air pollutant may also
result in future regulation of greenhouse gas emissions from stationary sources under certain Clean
Air Act programs. New legislation or regulatory programs that restrict emissions of greenhouse
gases in areas where we conduct business could adversely affect our operations and demand for our
products.
We are also subject to the requirements of the federal Occupational Safety and Health Act
(OSHA) and comparable state laws that regulate the protection of the health and safety of
employees. In addition, OSHAs 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 some, but not all, of the risks and uncertainties which may adversely affect
our business, financial condition or results of operations.
Risks Related to Our Business
Volatility of oil and natural gas prices significantly affects our cash flow and capital resources
and could hamper our ability to produce oil and gas economically
Oil and natural gas prices are volatile, and a decline in prices would adversely affect our
profitability and financial condition. The oil and natural gas industry is typically cyclical, and
prices for oil and natural gas have been highly volatile. Historically, the industry has
experienced severe downturns characterized by oversupply and/or weak demand. Higher oil and
natural gas prices have contributed to our positive earnings over the last several years. However,
long-term supply and demand for oil and natural gas is uncertain and subject to a myriad of factors
such as:
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the domestic and foreign supply of oil and gas; |
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the price and availability of alternative fuels; |
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weather conditions; |
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the level of consumer demand; |
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the price of foreign imports; |
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world-wide economic conditions; |
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political conditions in oil and gas producing regions; and |
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domestic and foreign governmental regulations. |
Decreases in oil and natural gas prices from current levels could adversely affect our
revenues, net income, cash flow and proved reserves. Significant price decreases could have a
material adverse effect on our operations and limit our ability to fund capital expenditures.
Without the ability to fund capital expenditures, we would be unable to replace reserves and
production.
Hedging transactions may limit our potential gains and involve other risks
To manage our exposure to price risk, we, from time to time, enter into hedging arrangements,
utilizing commodity derivatives with respect to a significant 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 oil and natural gas
prices rise above the price established by the hedge.
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In addition, hedging transactions may expose us to the risk of financial loss in certain
circumstances, including instances in which:
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our production is less than expected; |
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the counterparties to our futures contracts fail to perform under the contracts; or |
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a sudden, unexpected event materially impacts oil or natural gas prices or the
relationship between the hedged price index and the oil and gas sales price. |
Information concerning our reserves and future net reserve estimates is uncertain
There are numerous uncertainties inherent in estimating quantities of proved oil and natural
gas reserves and their values, including many factors beyond our control. Estimates of proved
reserves are by their nature uncertain. 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 oil and natural gas 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 oil and natural gas
reserve estimates, each of the following items may differ materially from the amounts or other
factors estimated:
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the amount and timing of oil and natural gas production; |
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the revenues and costs associated with that production; and |
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the amount and timing of future development expenditures. |
The discounted future net revenues 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 generally on prices and costs as of the date of the estimate, while
actual future prices and costs may be materially higher or lower. In addition, the 10 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 natural gas industry in general.
If oil and natural gas prices decrease or drilling efforts are unsuccessful, we may be required to
record write-downs of our oil and natural gas properties
In the past, we have been required to write down the carrying value of certain of our oil and
natural gas properties, and there is a risk that we will be required to take additional write-downs
in the future. This could occur when oil and natural gas 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 does not justify the expense.
Accounting rules require that the carrying value of oil and natural gas properties be
periodically reviewed for possible impairment. Impairment is recognized 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 oil and natural gas prices at the time of
the impairment review, as well as a continuing evaluation of drilling results, production data,
economics and other factors. While an impairment charge reflects our long-term ability to recover
an investment, it does not impact cash or cash flow from operating activities, but it does reduce
our reported earnings and increases our leverage ratios.
Our business is subject to operating hazards and environmental regulations that could result in
substantial losses or liabilities that may not be fully covered under our insurance policies
Oil and natural gas operations are subject to many risks, including well blowouts, craterings,
explosions, uncontrollable flows of oil, natural gas or well fluids, fires, formations with
abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic natural gas and other
environmental hazards and risks. If any of these hazards occur, we could sustain substantial
losses as a result of:
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injury or loss of life; |
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severe damage to or destruction of property, natural resources and equipment; |
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pollution or other environmental damage; |
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clean-up responsibilities; |
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regulatory investigations and penalties; or |
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suspension of operations. |
As we drill to deeper horizons and in more geologically complex areas, we could experience a
greater increase in operating and financial risks due to inherent higher reservoir pressures and
unknown downhole risk exposures. As we continue to drill deeper, the number of rigs capable of
drilling to such depths will be fewer and we may experience greater competition from other
operators.
We maintain insurance against some, but not all, of these potential risks and losses. We may
elect not to obtain insurance if we believe that the cost of available insurance is excessive
relative to the risks presented. Recently, we have experienced substantial increases in premiums
especially in areas affected by the hurricanes and tropical storms. Insurers have imposed revised
limits affecting how much the insurers will pay on actual storm claims plus the cost to re-drill
wells where substantial damage has been incurred. Insurers are also requiring us to retain larger
deductibles and reducing the scope of what insurable losses will include. Even with the increase
in future insurance premiums, coverage will be reduced, requiring us to bear a greater potential
risk if our oil and gas properties are damaged. We do not maintain any business interruption
insurance. In addition, pollution and environmental risks generally are not fully insurable. If a
significant accident or other event occurs that is not fully covered by insurance, it could have a
material adverse affect on our financial condition and results of operations.
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 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, 2007, approximately 74% of our debt is at fixed interest rates with the
remaining 26% subject to variable interest rates. Recent unfavorable disclosures concerning the
sub-prime mortgage market may lead to a contraction in credit availability impacting our ability to
finance our operations.
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 oil and natural gas. 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.
The demand for field services and their ability to meet that demand may limit our ability to drill
and produce our oil and natural gas properties
Due to current industry demands, well service providers and related equipment and personnel
are in short supply. This is causing escalating prices, the possibility of poor services coupled
with potential damage to downhole reservoirs and personnel injuries. Such pressures will likely
increase the actual cost of services, extend the time to secure such services and add costs for
damages due to accidents sustained from the over use of equipment and inexperienced personnel. In
some cases, we are operating in new areas where services and infrastructure do not exist or in
urban areas which are more restrictive.
The oil and natural gas industry is subject to extensive regulation
The oil and natural gas 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 oil and natural gas industry. Compliance with such
rules and regulations often increases our cost of doing business and, in turn, decreases our
profitability.
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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 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. Any past, present or future failure by us
to completely comply with environmental laws, regulations and enforcement policies could cause us
to incur substantial fines, sanctions or liabilities from cleanup costs or other damages.
Incurrence of those costs or damages could reduce or eliminate funds available for exploration,
development or acquisitions or cause us to incur losses.
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.
For example, in 1997, we consummated a large acquisition that proved extremely disappointing.
Production from the acquired properties fell more rapidly than anticipated and further development
results were below the results we had originally projected. The poor production performance of
these properties resulted in material downward reserve revisions. There is no assurance that our
recent and/or future acquisition activity will not result in similarly disappointing results.
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.
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, none of which 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 is intense. 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.
Our future success depends on our ability to replace reserves that we produce
Because the rate of production from oil and natural gas properties generally declines as
reserves are depleted, our future success depends upon our ability to economically find or acquire
and produce additional oil and natural gas 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 oil and
natural gas 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.
Drilling is a high-risk 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
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enough oil and natural gas to be commercially viable after drilling, operating and other costs.
Furthermore, our drilling and producing operations may be curtailed, delayed, or canceled as a
result of other factors, including:
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high costs, shortages or delivery delays of drilling rigs, equipment, labor, or
other services; |
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unexpected operational events and drilling conditions; |
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reductions in oil and natural gas prices; |
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limitations in the market for oil and natural gas; |
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adverse weather conditions; |
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facility or equipment malfunctions; |
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equipment failures or accidents; |
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title problems; |
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pipe or cement failures; |
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casing collapses; |
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compliance with environmental and other governmental requirements; |
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environmental hazards, such as natural gas leaks, oil spills, pipelines ruptures,
and discharges of toxic gases; |
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lost or damaged oilfield drilling and service tools; |
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unusual or unexpected geological formations; |
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loss of drilling fluid circulation; |
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pressure or irregularities in formations; |
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fires; |
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natural disasters; |
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blowouts, surface craterings and explosions; and |
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uncontrollable flows of oil, natural gas or well fluids. |
If any of these factors were to occur with respect to a particular field, we could lose all or
a part of our investment in the field, or we could fail to realize the expected benefits from the
field, either of which could materially and adversely affect our revenue and profitability.
New technologies may cause our current exploration and drilling methods to become obsolete
The oil and natural gas industry is subject to rapid and significant advancements in
technology, 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 cost. 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 business depends on oil and natural gas transportation facilities, most of which are owned by
others
The marketability of our oil and natural gas production depends in part on the availability,
proximity and capacity of pipeline systems owned by third parties. The unavailability of or 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 could materially affect our operations. We generally do not purchase firm
transportation on third party facilities and therefore, our production transportation can be
interrupted by those having firm arrangements. Federal and state regulation of oil and natural gas
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 oil and natural gas.
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The disruption of third-party facilities due to maintenance and/or weather could negatively
impact our ability to market and deliver our products. We have no control over when or if such
facilities are restored or 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.
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 estimated to range from $1.1 billion to $1.3 billion per year over the next three years,
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:
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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; |
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a portion of our borrowings are at variable rates of interest, making us vulnerable
to increases in interest rates; |
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we may be more highly leveraged than some of our competitors, which could place us
at a competitive disadvantage; |
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our degree of leverage may make us more vulnerable to a downturn in our business or
the general economy; |
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breach the numerous financial and other restrictive covenants contained in our
existing credit agreements; |
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our debt level could limit our flexibility in planning for, or reacting to, changes
in our business and the industry in which we operate; and |
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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.
Any failure to meet our debt obligations could harm our business, financial condition and results
of operations
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. 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 exist in a litigious environment
Any constituent could bring suit or allege a violation of an existing contract. This action
could delay when operations can actually commence or could cause a halt to production until such
alleged violations are resolved by the courts. Not only could we incur significant legal and
support expenses in defending our rights, planned operations could be delayed which would impact
our future operations and financial condition. Such legal disputes could also distract management
and other personnel from their primary responsibilities.
Our financial statements are complex
Due to accounting rules and the nature of our business, our financial statements continue to
be complex, particularly with reference to hedging, asset retirement obligations, equity awards,
deferred taxes and the accounting for our deferred compensation plans. We expect such complexity
to continue and possibly increase.
13
Risks Related to Our Common Stock
Common stockholders will be diluted if additional shares are issued
Since 1998, we have exchanged 31.9 million shares of common stock for debt and convertible
securities. The exchanges were made based on the relative market value of the common stock and the
debt and convertible securities at the time of the exchange. Also in 2004 and 2005, we sold 33.8
million shares of common stock to finance acquisitions. In 2006, we issued 6.5 million shares as
part of the Stroud acquisition. In 2007, we sold 8.1 million shares of common stock to finance
acquisitions. While the exchanges have reduced interest expense, preferred dividends and future
repayment obligations, the larger number of common shares outstanding had a dilutive effect on our
existing stockholders. Our ability to repurchase securities for cash is limited by our bank credit
facility and our senior subordinated note agreements. 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, 2005 to
December 31, 2007, the price of our common stock reported by the New York Stock Exchange ranged
from a low of $12.34 per share to a high of $51.88 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:
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changes in oil and natural gas prices; |
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variations in quarterly drilling, recompletions, acquisitions and operating results; |
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changes in financial estimates by securities analysts; |
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changes in market valuations of comparable companies; |
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additions or departures of key personnel; or |
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future sales of our stock. |
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
As of the date of this filing, we have no unresolved comments from the staff of the Securities
and Exchange Commission.
ITEM 2. PROPERTIES
The table below summarizes certain data for our core operating areas for the year ended
December 31, 2007. All Gulf of Mexico operations have been reclassified to discontinued
operations.
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|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Daily |
|
|
|
|
|
|
|
|
|
Total |
|
Percentage of |
|
|
Production |
|
Total |
|
Percentage |
|
Proved |
|
Total |
|
|
(mcfe |
|
Production |
|
of Total |
|
Reserves |
|
Proved |
Area |
|
per day) |
|
(mcfe) |
|
Production |
|
(Mmcfe) |
|
Reserves |
Southwest |
|
|
194,060 |
|
|
|
70,832,032 |
|
|
|
61 |
% |
|
|
1,048,314 |
|
|
|
47 |
% |
Appalachia |
|
|
118,383 |
|
|
|
43,209,899 |
|
|
|
37 |
% |
|
|
1,150,143 |
|
|
|
52 |
% |
Gulf Coast |
|
|
6,573 |
|
|
|
2,399,084 |
|
|
|
2 |
% |
|
|
34,305 |
|
|
|
1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
319,016 |
|
|
|
116,441,015 |
|
|
|
100 |
% |
|
|
2,232,762 |
|
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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14
We have a single company-wide management team that administers all properties as a whole
rather than by discrete operating segments; therefore, segment reporting is not applicable to us.
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.
Southwest Area
The Southwest Area conducts drilling, production and field operations in the Barnett Shale of
North Central Texas, the Permian Basin of West Texas and eastern New Mexico and the East Texas
Basin as well as in the Texas Panhandle and the Anadarko Basin of western Oklahoma. In the
Southwest Area, we own 2,928 net producing wells, 96% of which we operate. Our average working
interest is 77%. We have approximately 802,000 gross (536,000 net) acres under lease.
Total proved reserves increased 273.4 Bcfe, or 35%, at December 31, 2007 when compared to
year-end 2006. Production was more than offset by property purchases (30.2 Bcfe), drilling
additions (293.5 Bcfe) and a favorable reserve revision. Annual production increased 28% over
2006. During 2007, the region spent $506.0 million to drill 290.0 (256.4 net) development wells,
of which 282.0 (249.5 net) were productive and 6.0 (3.3 net) exploratory wells, of which 4.0 (2.8
net) were productive. During the year, the region achieved a 97% drilling success rate.
At December 31, 2007, the Southwest Area had a development inventory of 397 proven drilling
locations and 367 proven recompletions. During the year, the Southwest Area drilled 76 proven
locations and added new locations of 188. Development projects include recompletions, infill
drilling and to a lesser extent, installation of secondary recovery projects. 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.
Appalachia Area
Our properties in this area are located in the Appalachian Basin in the northeastern United
States principally in Ohio, Pennsylvania, New York, West Virginia and Virginia. The reserves
principally produce from the Pennsylvanian (coalbed formation), Upper Devonian, Medina, Clinton,
Queenston, Big Lime, Marcellus Shale, Niagaran Reef, Knox, Huntersville Chert, Oriskany and Trenton
Black River formations at depths ranging from 2,500 to 12,500 feet. Generally, after initial flush
production, most of these properties are characterized by gradual decline rates, typically
producing for 10 to 35 years. We own 10,800 net producing wells, 59% of which we operate and 5,100
miles of gas gathering lines. Our average working interest is 71%. We have approximately 2.5
million gross (2.1 million net) acres under lease which includes
407,800 acres where we also own a
royalty interest.
Reserves at December 31, 2007 increased 235.1 Bcfe, or 26%, from 2006 due to drilling
additions (177.4 Bcfe) and property purchases (102.8 Bcfe) which were partially offset by
production. Annual production increased 15% over 2006. During 2007,
the region spent $278.1 million to drill 654.0 (427.7 net) development wells, of which 653.0 (426.7 net) were productive
and 9 (5.5 net) exploratory wells, of which 7.0 (3.5 net) were productive. During the year, the
region achieved approximately a 99% drilling success rate. At December 31, 2007, the Appalachia
Area had an inventory of 3,600 proven drilling locations and 394 proven recompletions. During the
year, the Appalachia Area drilled 321 proven locations and added 755 new locations.
Gulf Coast Area
The Gulf Coast properties are located onshore in Texas, Louisiana and Mississippi. Our major
fields produce from Yegua formations at depths of 12,000 to 14,000 feet in the Upper Texas Gulf
Coast, the Upper Oligocene in South Louisiana at depths of 10,000 to 12,000 feet and the Sligo and
Hosston formations at depths of 15,000 to 16,500 feet in the Oakvale field in Mississippi. We have
approximately 126,000 gross (83,000 net) acres under lease. We own 43 net producing wells in this
Area, 98% of which we operate. Our average working interest is 57%.
In the first quarter of 2007, we sold all of our offshore properties. Reserves decreased 33.9
Bcfe, or 50%, from 2006 with property sales (37.1 Bcfe), production and an unfavorable reserve
revision partially offset by drilling additions (13.3 Bcfe). On an annual basis, production
decreased 17% from 2006. During 2007, the region spent $34.8 million to drill 7.0 (4.3 net)
development wells, of which all were productive and 1.0 (1.0 net) exploratory well that was not
productive. During the year, the Area had a 81% drilling success rate. At December 31, 2007, the
Gulf Coast Area had an inventory of 4 proven drilling locations and 16 proven recompletions.
15
Proved Reserves
The following table sets forth our estimated proved reserves at the end of each of the past
five years:
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|
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|
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|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2007 |
|
2006 |
|
2005 |
|
2004 |
|
2003 |
Natural gas (Mmcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed |
|
|
1,144,709 |
|
|
|
875,395 |
|
|
|
724,876 |
|
|
|
580,006 |
|
|
|
344,187 |
|
Undeveloped |
|
|
688,088 |
|
|
|
560,583 |
|
|
|
400,534 |
|
|
|
366,422 |
|
|
|
142,217 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
1,832,797 |
|
|
|
1,435,978 |
|
|
|
1,125,410 |
|
|
|
946,428 |
|
|
|
486,404 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and NGLs (Mbbls) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed |
|
|
47,015 |
|
|
|
37,750 |
|
|
|
33,029 |
|
|
|
27,715 |
|
|
|
24,912 |
|
Undeveloped |
|
|
19,645 |
|
|
|
15,957 |
|
|
|
13,863 |
|
|
|
10,451 |
|
|
|
8,111 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
66,660 |
|
|
|
53,707 |
|
|
|
46,892 |
|
|
|
38,166 |
|
|
|
33,023 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Mmcfe) (a) |
|
|
2,232,762 |
|
|
|
1,758,226 |
|
|
|
1,406,762 |
|
|
|
1,175,425 |
|
|
|
684,541 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% Developed |
|
|
64 |
% |
|
|
63 |
% |
|
|
66 |
% |
|
|
64 |
% |
|
|
72 |
% |
|
|
|
(a) |
|
Oil and NGLs are converted to mcfe at the rate of one barrel equals six
mcfe. |
Our percentage of proved developed reserves declined from 2003 to 2004 due to the proved
undeveloped reserves acquired in our Great Lakes and Pine Mountain acquisitions which added to our
future drilling inventory. From 2004 to 2005, our proved developed percentage increased from 64%
to 66% as we continued to drill aggressively. The Stroud acquisition in June of 2006 was primarily
responsible for the decrease in the proved developed reserve percentage in 2006. The Stroud
acquisition significantly increased our Barnett Shale drilling and prospect inventory. In 2007,
the percentage of proved developed reserves increased 1% to 64%.
The following table sets forth summary information by area with respect to estimated proved
reserves at December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PV-10 (a) |
|
|
Reserve Volumes |
|
|
|
Amount |
|
|
|
|
|
|
Oil & NGL |
|
|
Natural Gas |
|
|
Total |
|
|
|
|
|
|
(In thousands) |
|
|
% |
|
|
(Mbbls) |
|
|
(Mmcf) |
|
|
(Mmcfe) |
|
|
% |
|
Southwest |
|
$ |
2,942,845 |
|
|
|
57 |
% |
|
|
51,816 |
|
|
|
737,419 |
|
|
|
1,048,314 |
|
|
|
47 |
% |
Appalachia |
|
|
2,128,982 |
|
|
|
41 |
% |
|
|
13,742 |
|
|
|
1,067,691 |
|
|
|
1,150,143 |
|
|
|
52 |
% |
Gulf Coast |
|
|
132,997 |
|
|
|
2 |
% |
|
|
1,102 |
|
|
|
27,687 |
|
|
|
34,305 |
|
|
|
1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
5,204,824 |
|
|
|
100 |
% |
|
|
66,660 |
|
|
|
1,832,797 |
|
|
|
2,232,762 |
|
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
PV-10 was prepared using prices in effect at the end of 2007, discounted at 10%
per annum. Year-end PV-10 may be 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 prior to taking into account corporate future income taxes and our current tax
structure. While the standardized 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. The difference between the standardized measure and the PV-10 amount
is the discounted estimated future income tax of $1.5 billion at December 31, 2007. |
At year-end 2006, the following independent petroleum consultants reviewed our reserves:
DeGolyer and MacNaughton (Southwest and Gulf Coast), H.J. Gruy and Associates, Inc. (Southwest),
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, 2007,
these consultants collectively reviewed approximately 86% of our proved reserves. All estimates of
oil and gas reserves are subject to uncertainty. Historical variances between our reserve
estimates and the aggregate estimates of our consultants have been less than 5%. We did not file
any reports during the year ended December 31, 2007 with any federal authority or agency with
respect to our estimates of oil and natural gas reserves.
16
The following table sets forth the estimated future net revenues, excluding open hedging
contracts, from proved reserves, the present value of those net revenues (PV-10) and the expected
benchmark prices and average field prices used in projecting them over the past five years (in
millions except prices):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2007 |
|
2006 |
|
2005 |
|
2004 |
|
2003 |
Future net revenue |
|
$ |
11,908 |
|
|
$ |
6,391 |
|
|
$ |
10,429 |
|
|
$ |
5,035 |
|
|
$ |
2,687 |
|
Present value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Before income tax |
|
|
5,205 |
|
|
|
2,771 |
|
|
|
4,887 |
|
|
|
2,396 |
|
|
|
1,396 |
|
After income tax (Standardized Measure) |
|
|
3,666 |
|
|
|
2,002 |
|
|
|
3,384 |
|
|
|
1,749 |
|
|
|
1,003 |
|
Benchmark prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price (per barrel) |
|
$ |
95.98 |
|
|
$ |
61.05 |
|
|
$ |
61.04 |
|
|
$ |
43.33 |
|
|
$ |
32.52 |
|
Gas price (per mcf) |
|
$ |
6.80 |
|
|
$ |
5.64 |
|
|
$ |
10.08 |
|
|
$ |
6.18 |
|
|
$ |
6.19 |
|
Wellhead prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price (per barrel) |
|
$ |
91.88 |
|
|
$ |
57.66 |
|
|
$ |
57.80 |
|
|
$ |
40.44 |
|
|
$ |
29.48 |
|
Gas price (per mcf) |
|
$ |
6.44 |
|
|
$ |
5.24 |
|
|
$ |
9.83 |
|
|
$ |
6.05 |
|
|
$ |
6.03 |
|
Future net revenues represent projected revenues from the sale of proved reserves net of
production and development costs (including operating expenses and production taxes). Such
calculations, prepared in accordance with Statement of Financial Accounting Standards No. 69,
Disclosures about Oil and Gas Producing Activities, are based on costs and prices in effect at
December 31 of each year, without escalation. There can be no assurance that the proved reserves
will be produced within the periods indicated and prices and costs will not 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.
Producing Wells
The following table sets forth information relating to productive wells at December 31, 2007.
We also own royalty interests in an additional 1,649 wells where we do not own a working interest.
If we own both a royalty and a working interest in a well such interests are included in the table
below. Wells are classified as crude oil or natural gas according to their predominant production
stream. We do not have a significant number of dual completions.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
Total Wells |
|
Working |
|
|
Gross |
|
Net |
|
Interest |
Natural gas |
|
|
16,253 |
|
|
|
11,341 |
|
|
|
70 |
% |
Crude oil |
|
|
2,832 |
|
|
|
2,474 |
|
|
|
87 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
19,085 |
|
|
|
13,815 |
|
|
|
72 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
The day-to-day operations of oil and gas 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.
Acreage
We own interests in developed and undeveloped oil and gas acreage. These ownership interests
generally take the form of working interests in oil and 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.
17
The following table sets forth certain information regarding our developed and undeveloped
acreage in which we own a working interest as of December 31, 2007. Acreage related to royalty,
overriding royalty and other similar interests is excluded from this summary:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed Acres |
|
Undeveloped Acres |
|
Total Acres |
|
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
Alabama |
|
|
|
|
|
|
|
|
|
|
65,617 |
|
|
|
54,451 |
|
|
|
65,617 |
|
|
|
54,451 |
|
Louisiana |
|
|
3,289 |
|
|
|
2,058 |
|
|
|
17,454 |
|
|
|
8,457 |
|
|
|
20,743 |
|
|
|
10,515 |
|
Michigan |
|
|
162 |
|
|
|
162 |
|
|
|
855 |
|
|
|
378 |
|
|
|
1,017 |
|
|
|
540 |
|
Mississippi |
|
|
3,954 |
|
|
|
2,167 |
|
|
|
25,214 |
|
|
|
7,956 |
|
|
|
29,168 |
|
|
|
10,123 |
|
New York |
|
|
187,124 |
|
|
|
177,871 |
|
|
|
146,302 |
|
|
|
128,361 |
|
|
|
333,426 |
|
|
|
306,232 |
|
Ohio |
|
|
270,638 |
|
|
|
254,257 |
|
|
|
239,569 |
|
|
|
217,959 |
|
|
|
510,207 |
|
|
|
472,216 |
|
Oklahoma |
|
|
160,588 |
|
|
|
100,855 |
|
|
|
147,523 |
|
|
|
79,200 |
|
|
|
308,111 |
|
|
|
180,055 |
|
Pennsylvania |
|
|
427,516 |
|
|
|
388,947 |
|
|
|
632,448 |
|
|
|
532,328 |
|
|
|
1,059,964 |
|
|
|
921,275 |
|
Texas |
|
|
179,500 |
|
|
|
146,680 |
|
|
|
324,180 |
|
|
|
236,906 |
|
|
|
503,680 |
|
|
|
383,586 |
|
Virginia |
|
|
152,300 |
|
|
|
50,330 |
|
|
|
166,134 |
|
|
|
74,393 |
|
|
|
318,434 |
|
|
|
124,723 |
|
West Virginia |
|
|
48,468 |
|
|
|
47,883 |
|
|
|
107,300 |
|
|
|
104,300 |
|
|
|
155,768 |
|
|
|
152,183 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,433,539 |
|
|
|
1,171,210 |
|
|
|
1,872,596 |
|
|
|
1,444,689 |
|
|
|
3,306,135 |
|
|
|
2,615,899 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average working interest |
|
|
|
|
|
|
82 |
% |
|
|
|
|
|
|
77 |
% |
|
|
|
|
|
|
79 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Undeveloped Acreage Expirations
The table below summarizes by year our undeveloped acreage scheduled to expire in the next
five years.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acres |
|
% of Total |
As of December 31, |
|
Gross |
|
Net |
|
Undeveloped |
2008 |
|
|
157,342 |
|
|
|
123,432 |
|
|
|
8 |
% |
2009 |
|
|
244,817 |
|
|
|
173,246 |
|
|
|
11 |
% |
2010 |
|
|
299,460 |
|
|
|
219,017 |
|
|
|
14 |
% |
2011 |
|
|
162,742 |
|
|
|
136,695 |
|
|
|
9 |
% |
2012 |
|
|
303,922 |
|
|
|
250,387 |
|
|
|
16 |
% |
Drilling Results
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, 2007, we were in the process of drilling 131 gross
(83 net) wells.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
2005 |
|
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
Development wells |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive |
|
|
942.0 |
|
|
|
680.5 |
|
|
|
992.0 |
|
|
|
689.7 |
|
|
|
813.0 |
|
|
|
573.8 |
|
Dry |
|
|
9.0 |
|
|
|
7.9 |
|
|
|
8.0 |
|
|
|
4.6 |
|
|
|
10.0 |
|
|
|
7.7 |
|
Exploratory wells |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive |
|
|
11.0 |
|
|
|
6.3 |
|
|
|
12.0 |
|
|
|
6.9 |
|
|
|
13.0 |
|
|
|
8.1 |
|
Dry |
|
|
5.0 |
|
|
|
3.5 |
|
|
|
5.0 |
|
|
|
2.6 |
|
|
|
5.0 |
|
|
|
3.9 |
|
Total wells |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive |
|
|
953.0 |
|
|
|
686.8 |
|
|
|
1,004.0 |
|
|
|
696.6 |
|
|
|
826.0 |
|
|
|
581.9 |
|
Dry |
|
|
14.0 |
|
|
|
11.4 |
|
|
|
13.0 |
|
|
|
7.2 |
|
|
|
15.0 |
|
|
|
11.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
967.0 |
|
|
|
698.2 |
|
|
|
1,017.0 |
|
|
|
703.8 |
|
|
|
841.0 |
|
|
|
593.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Success ratio |
|
|
99 |
% |
|
|
98 |
% |
|
|
99 |
% |
|
|
99 |
% |
|
|
98 |
% |
|
|
98 |
% |
18
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:
|
|
|
customary royalty interests; |
|
|
|
|
liens incident to operating agreements and for current taxes; |
|
|
|
|
obligations or duties under applicable laws; |
|
|
|
|
development obligations under oil and gas leases; or |
|
|
|
|
burdens such as net profit interests. |
ITEM 3. LEGAL PROCEEDINGS
We have been named as a defendant in a number of legal actions arising in the ordinary course
of business. In the opinion of management, such litigation and claims are likely to be resolved
without a material adverse effect on our financial position or liquidity, although an unfavorable
outcome could have a material adverse effect on the operations of a given interim period or year.
See also Note 14 to our consolidated financial statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of our security holders during the fourth quarter of
2007.
PART II
|
|
|
ITEM 5. |
|
MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES |
Our common stock is listed on the New York Stock Exchange (NYSE) under the symbol RRC.
During 2007, trading volume averaged 1.6 million shares per day. On December 20, 2007, we were
selected to be included in the S&P 500 index. 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Dividends |
|
|
High |
|
Low |
|
Declared |
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
First quarter |
|
$ |
30.52 |
|
|
$ |
22.52 |
|
|
$ |
0.02 |
|
Second quarter |
|
|
30.29 |
|
|
|
21.74 |
|
|
|
0.02 |
|
Third quarter |
|
|
30.37 |
|
|
|
23.38 |
|
|
|
0.02 |
|
Fourth quarter |
|
|
31.77 |
|
|
|
22.80 |
|
|
|
0.03 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
First quarter |
|
$ |
33.80 |
|
|
$ |
25.59 |
|
|
$ |
0.03 |
|
Second quarter |
|
|
40.50 |
|
|
|
33.40 |
|
|
|
0.03 |
|
Third quarter |
|
|
41.87 |
|
|
|
33.28 |
|
|
|
0.03 |
|
Fourth quarter |
|
|
51.88 |
|
|
|
37.17 |
|
|
|
0.04 |
|
Between January 1, 2008 and February 20, 2008, the common stock traded at prices between
$43.02 and $64.50 per share. Our senior subordinated notes are not listed on an exchange, but
trade over-the-counter.
Holders of Record
On
February 20, 2008, there were approximately 1,848 holders of record of our common stock.
19
Dividends
In December 2007, the Board of Directors increased our quarterly dividend to $0.04 per common
share. The payment of dividends is subject to declaration by the Board of Directors and depends on
earnings, capital expenditures and various other factors. 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 and will depend upon our level of earnings and capital
expenditures and other matters that the Board of Directors deems relevant. For more information
see information set forth in Item 7 of this report Managements Discussion and Analysis of
Financial Condition and Results of Operations.
Issuer Purchases of Equity Securities
We have a repurchase program approved by the Board of Directors in 2006 for the repurchase of
up to $10.0 million of common stock based on market conditions and opportunities. There were no
repurchases during the fourth quarter of 2007. As of December 31, 2007, we have $4.7 million
remaining under this authorization.
Stockholder Return Performance Presentation*
The following graph is included in accordance with the SECs 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 the common stock, the
Dow Jones U.S. Exploration and Production Index and the S&P 500 Index for the five years ended
December 31, 2007. The graph assumes that $100 was invested in the Companys common stock and each
index on December 31, 2002.
Comparison
of Five Year Cumulative Returns
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2002 |
|
2003 |
|
2004 |
|
2005 |
|
2006 |
|
2007 |
Range Resources Corporation |
|
$ |
100 |
|
|
$ |
175 |
|
|
$ |
379 |
|
|
$ |
732 |
|
|
$ |
762 |
|
|
$ |
1,427 |
|
DJ U.S. Expl. & Prod. Index |
|
|
100 |
|
|
|
129 |
|
|
|
182 |
|
|
|
298 |
|
|
|
312 |
|
|
|
445 |
|
S&P 500 |
|
|
100 |
|
|
|
126 |
|
|
|
138 |
|
|
|
141 |
|
|
|
161 |
|
|
|
167 |
|
|
|
|
* |
|
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. |
20
ITEM 6. SELECTED FINANCIAL DATA
The following table shows selected financial information for the five years ended December 31,
2007. Significant producing property acquisitions in 2006 and 2004 affect the comparability of
year-to-year financial and operating data. In March 2007, we sold our Gulf of Mexico properties
for proceeds of $155.0 million. Accordingly, the financial and statistical data contained in the
following discussion reflects the reclassification of our Gulf of Mexico operations to discontinued
operations. All weighted average shares and per share data have been adjusted for the
three-for-two stock split effected December 2, 2005. This information should be read in
conjunction with Item 7 of this report Managements Discussion and Analysis of Financial Condition
and Results of Operations, and our consolidated financial statements and related notes included
elsewhere in this report.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2007 |
|
2006 |
|
2005 |
|
2004 |
|
2003 |
|
|
(in thousands, except per share data) |
Balance Sheet Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets (a) |
|
$ |
261,814 |
|
|
$ |
388,925 |
|
|
$ |
207,977 |
|
|
$ |
136,336 |
|
|
$ |
66,092 |
|
Current liabilities (b) |
|
|
305,433 |
|
|
|
251,685 |
|
|
|
321,760 |
|
|
|
177,162 |
|
|
|
106,964 |
|
Oil and gas properties, net |
|
|
3,503,808 |
|
|
|
2,608,088 |
|
|
|
1,679,593 |
|
|
|
1,340,077 |
|
|
|
658,798 |
|
Total assets |
|
|
4,016,508 |
|
|
|
3,187,674 |
|
|
|
2,018,985 |
|
|
|
1,595,406 |
|
|
|
830,091 |
|
Bank debt |
|
|
303,500 |
|
|
|
452,000 |
|
|
|
269,200 |
|
|
|
423,900 |
|
|
|
178,200 |
|
Subordinated notes |
|
|
847,158 |
|
|
|
596,782 |
|
|
|
346,948 |
|
|
|
196,656 |
|
|
|
109,980 |
|
Stockholders equity (c) |
|
|
1,728,022 |
|
|
|
1,256,161 |
|
|
|
696,923 |
|
|
|
566,340 |
|
|
|
274,066 |
|
Weighted average dilutive shares outstanding |
|
|
149,911 |
|
|
|
138,711 |
|
|
|
129,125 |
|
|
|
97,998 |
|
|
|
86,775 |
|
Cash dividends declared per common share |
|
|
0.13 |
|
|
|
0.09 |
|
|
|
.0599 |
|
|
|
.0267 |
|
|
|
.0067 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided from operating activities |
|
$ |
642,291 |
|
|
$ |
479,875 |
|
|
$ |
325,745 |
|
|
$ |
209,249 |
|
|
$ |
124,680 |
|
Net cash used in investing activities |
|
|
1,020,572 |
|
|
|
911,659 |
|
|
|
432,377 |
|
|
|
624,301 |
|
|
|
186,838 |
|
Net cash provided from financing activities |
|
|
379,917 |
|
|
|
429,416 |
|
|
|
93,000 |
|
|
|
432,803 |
|
|
|
61,455 |
|
|
|
|
(a) |
|
2007 included deferred tax assets of $26.9 million. 2005 included deferred tax
assets of $61.7 million compared to $26.3 million in 2004 and $19.9 million in 2003. 2007
includes a $53.0 million unrealized derivative asset compared to $93.6 million in 2006. |
|
(b) |
|
2007 includes unrealized derivative liabilities of $30.5 million compared to $4.6
million in 2006, $160.1 million in 2005, $61.0 million in 2004 and $54.3 million in 2003. |
|
(c) |
|
Stockholders equity includes other comprehensive income (loss) of ($26.8 million)
in 2007 compared to $36.5 million in 2006, ($147.1 million) in 2005, ($43.3 million) in 2004
and ($42.9 million) in 2003. |
21
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2007 |
|
2006 |
|
2005 |
|
2004 |
|
2003 |
|
|
(in thousands, except per share data) |
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales |
|
$ |
862,537 |
|
|
$ |
599,139 |
|
|
$ |
495,470 |
|
|
$ |
278,903 |
|
|
$ |
179,074 |
|
Transportation and gathering |
|
|
2,290 |
|
|
|
2,422 |
|
|
|
2,306 |
|
|
|
2,002 |
|
|
|
3,248 |
|
Gain (loss) on retirement of securities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(39 |
) |
|
|
18,526 |
|
Derivative fair value (loss) income |
|
|
(7,767 |
) |
|
|
142,395 |
|
|
|
10,303 |
|
|
|
614 |
|
|
|
(1,282 |
) |
Other |
|
|
5,031 |
|
|
|
856 |
|
|
|
1,024 |
|
|
|
1,588 |
|
|
|
(865 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue |
|
|
862,091 |
|
|
|
744,812 |
|
|
|
509,103 |
|
|
|
283,068 |
|
|
|
198,701 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating |
|
|
108,741 |
|
|
|
81,261 |
|
|
|
57,866 |
|
|
|
39,419 |
|
|
|
28,110 |
|
Production and ad valorem taxes |
|
|
42,443 |
|
|
|
36,415 |
|
|
|
30,822 |
|
|
|
19,845 |
|
|
|
12,059 |
|
Exploration |
|
|
43,345 |
|
|
|
44,088 |
|
|
|
29,529 |
|
|
|
12,619 |
|
|
|
12,530 |
|
General and administrative |
|
|
68,428 |
|
|
|
49,886 |
|
|
|
33,444 |
|
|
|
20,634 |
|
|
|
17,818 |
|
Deferred compensation plan |
|
|
28,332 |
|
|
|
6,873 |
|
|
|
29,474 |
|
|
|
19,176 |
|
|
|
6,559 |
|
Interest expense and dividends on trust preferred |
|
|
77,737 |
|
|
|
55,849 |
|
|
|
37,619 |
|
|
|
22,437 |
|
|
|
21,507 |
|
Depletion, depreciation and amortization |
|
|
227,328 |
|
|
|
154,739 |
|
|
|
114,364 |
|
|
|
80,628 |
|
|
|
62,687 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
596,354 |
|
|
|
429,111 |
|
|
|
333,118 |
|
|
|
214,758 |
|
|
|
161,270 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes
and accounting change |
|
|
265,737 |
|
|
|
315,701 |
|
|
|
175,985 |
|
|
|
68,310 |
|
|
|
37,431 |
|
|
Income tax provision (benefit) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
320 |
|
|
|
1,912 |
|
|
|
1,071 |
|
|
|
(245 |
) |
|
|
170 |
|
Deferred |
|
|
98,441 |
|
|
|
119,840 |
|
|
|
64,809 |
|
|
|
25,327 |
|
|
|
14,125 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
98,761 |
|
|
|
121,752 |
|
|
|
65,880 |
|
|
|
25,082 |
|
|
|
14,295 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
|
166,976 |
|
|
|
193,949 |
|
|
|
110,105 |
|
|
|
43,228 |
|
|
|
23,136 |
|
Income (loss) from discontinued operations |
|
|
63,593 |
|
|
|
(35,247 |
) |
|
|
906 |
|
|
|
(997 |
) |
|
|
7,788 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of changes in
accounting principles |
|
|
230,569 |
|
|
|
158,702 |
|
|
|
111,011 |
|
|
|
42,231 |
|
|
|
30,924 |
|
|
Cumulative effect of changes in accounting principles,
net of taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,491 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
230,569 |
|
|
|
158,702 |
|
|
|
111,011 |
|
|
|
42,231 |
|
|
|
35,415 |
|
Preferred dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,163 |
) |
|
|
(803 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders |
|
$ |
230,569 |
|
|
$ |
158,702 |
|
|
$ |
111,011 |
|
|
$ |
37,068 |
|
|
$ |
34,612 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic income from continuing operations |
|
$ |
1.16 |
|
|
$ |
1.45 |
|
|
$ |
0.89 |
|
|
$ |
0.41 |
|
|
$ |
0.27 |
|
income (loss) from discontinued operations |
|
|
0.44 |
|
|
|
(0.26 |
) |
|
|
|
|
|
|
(0.01 |
) |
|
|
0.10 |
|
cumulative effect of changes in accounting
principles |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.05 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net income |
|
$ |
1.60 |
|
|
$ |
1.19 |
|
|
$ |
0.89 |
|
|
$ |
0.40 |
|
|
$ |
0.42 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted income from continuing operations |
|
$ |
1.11 |
|
|
$ |
1.39 |
|
|
$ |
0.85 |
|
|
$ |
0.39 |
|
|
$ |
0.27 |
|
income (loss) from discontinued operations |
|
|
0.43 |
|
|
|
(0.25 |
) |
|
|
0.01 |
|
|
|
(0.01 |
) |
|
|
0.09 |
|
cumulative effect of changes in accounting
principles |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.05 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net income |
|
$ |
1.54 |
|
|
$ |
1.14 |
|
|
$ |
0.86 |
|
|
$ |
0.38 |
|
|
$ |
0.41 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22
ITEM 7. MANAGEMENTS 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. This section should be read in
conjunction with Item 6, Selected Financial Data and our consolidated financial statements and
the accompanying notes included elsewhere in this Form 10-K.
Statements in our discussion may be forward-looking. These forward-looking statements involve
risks and uncertainties. We caution that a number of factors could cause future production,
revenues and expenses to differ materially from our expectations. See Disclosures Regarding
Forward-Looking Statements at the beginning of this Annual Report and Risk Factors in Item 1A
for additional discussion of some of these factors and risks.
Items Impacting the Comparability to Prior Year Reports
In March 2007, we sold our Gulf of Mexico properties for proceeds of $155.0 million.
Accordingly, the financial and statistical data contained in the following discussion for all
periods presented reflects the reclassification of our Gulf of Mexico operations to discontinued
operations.
Overview of Our Business
We are an independent oil and gas company engaged in the exploration, development and
acquisition of oil and gas properties, primarily in the Southwestern, Appalachian and Gulf Coast
regions of the United States. We operate in one 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 strategy is to increase reserves and production through internally generated drilling
projects coupled with complementary acquisitions. Our revenues, profitability and future growth
depend substantially on prevailing prices for oil and gas and on our ability to find, develop and
acquire oil and gas reserves that are economically recoverable. We use the successful efforts
method of accounting for our oil and gas activities. Our corporate headquarters are in Fort Worth,
Texas.
Industry Environment
We operate entirely within the United States, a mature region for the exploration and
production of oil and gas. As a mature region, while new discoveries of oil and gas occur in the
United States, the size and frequency of these discoveries is generally declining, while finding
and development costs are increasing. We believe that there remain areas of the United States,
such as the Appalachian Basin and certain areas in our Southwest and Gulf Coast Areas, which are
underexplored or have not been fully explored and developed with the benefit of newly available
exploration, production and reserve enhancement technology. Examples of such technology include
advanced 3-D seismic processing, hydraulic reservoir fracture stimulation, advances in well logging
and analysis, horizontal drilling and completion techniques, secondary and tertiary recovery
practices, and automated remote well monitoring and control devices.
Another characteristic of a mature region is the historical exit of larger independent
producers and major oil companies from such regions. These companies, searching for ever larger
new discoveries, have ventured increasingly overseas and offshore, de-emphasizing their onshore
United States assets. This movement out of mature basins by larger companies has provided
acquisition opportunities for companies like ours that maintain well-equipped technical teams
capable of generating additional value from these assets. In other situations, to increase cash
flow without increasing capital spending, larger independent producers and major integrated oil
companies have allowed smaller companies the opportunity to explore and develop reserves on their
undeveloped acreage through joint ventures and farm-in arrangements.
We believe the acquisition market for oil and gas properties has become extremely competitive
as producers vie for additional production and expanded drilling opportunities. Acquisition values
have reached historic highs and we expect these values to remain high in 2008. In addition, we
expect drilling and service costs to remain at a high level in 2008 and for lease operating
expenses to continue to rise as producers are forced to make operational enhancements to maintain
aging fields.
Oil and gas is a commodity. The price that we receive for the natural gas we produce is
largely a function of market supply and demand. Demand for natural gas in the United States has
increased dramatically over the last ten years. Demand is impacted by general economic conditions,
estimates of gas in storage, weather and other seasonal condition, including hurricanes and
tropical storms. Market conditions involving over or under supply of natural gas can result in
substantial price volatility. Historically, commodity prices have been volatile and we expect the
volatility to continue in the future. A factor impacting the future supply balance is the recent
increase in the United States LNG import capacity. Significant LNG capacity
23
increases have been announced which may result in increased price volatility. A substantial or
extended decline in oil and gas prices or poor drilling results could have a material adverse
effect on our financial position, results of operations, cash flows, quantities of oil and gas
reserves that may be economically produced and our ability to access capital markets.
Source of Our Revenues
We derive our revenues from the sale of oil and gas that is produced from our properties.
Revenues are a function of the volume produced, the prevailing market price at the time of sale,
quality, BTU content and transportation costs to market. The price of oil and natural gas is the
primary factor affecting our revenues. To achieve more predictable cash flows and to reduce our
exposure to downward price fluctuations, we use derivative instruments to hedge future sales prices
on a significant portion of our natural gas and oil production. During 2006 and 2005 the use of
derivative instruments prevented us from realizing the full benefit of upward price movements and
may continue to do so in future periods. Our realized price calculations include the effects of
the settlement of derivative contracts that are accounted for as hedges and the settlement of
derivative contracts that are not accounted for as hedges.
Principal Components of Our Cost Structure
|
|
|
Direct Operating Expenses. These are day-to-day costs incurred to bring hydrocarbons
out of the ground and to the market together with the daily costs incurred to maintain our
producing properties. Such costs also include workovers and repairs to our oil and gas
properties. These costs are expected to remain high in 2008 as the demand for these
services continues to increase. Direct operating expenses also include stock-based
compensation expense (non-cash) associated with the adoption of SFAS No. 123(R) and
amortization of restricted stock grants as part of employee compensation. |
|
|
|
|
Production and Ad Valorem Taxes. These costs are taxes paid on produced oil and gas
based on a percentage of market prices (not at hedged prices) or at fixed rates established
by federal, state or local taxing authorities. |
|
|
|
|
Exploration Expense. Geological and geophysical costs, including payroll and benefits
for the geological and geophysical staff, seismic costs, delay rentals and the costs of
unsuccessful exploratory or dry holes. Exploration expense includes stock-based
compensation expense (non-cash) associated with the adoption of SFAS No. 123(R) and
amortization of restricted stock grants as part of employee compensation. |
|
|
|
|
General and Administrative Expense. Overhead, including payroll and benefits for our
corporate staff, costs of maintaining our headquarters, costs of managing our production
and development operations, audit and other professional fees and legal compliance are
included in general and administrative expense. General and administrative expense
includes stock-based compensation expense (non-cash) associated with the adoption of SFAS
No. 123(R) and amortization of restricted stock grants as part of employee compensation. |
|
|
|
|
Interest. We typically finance a portion of our working capital requirements and
acquisitions with borrowings under our bank credit facility and with our longer term debt
securities. As a result, we incur substantial interest expense that is affected by both
fluctuations in interest rates and our financing decisions. We will likely continue to
incur significant interest expense as we continue to grow. We expect our 2008 capital
budget to be funded primarily with internal cash flow and asset sales. |
|
|
|
|
Depreciation, Depletion and Amortization. The systematic expensing of the capitalized
costs incurred to acquire, explore and develop natural gas 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 includes
the systematic, monthly accretion of the future abandonment costs of tangible assets such
as wells, service assets, pipelines, and other facilities. This category also includes
unproved property impairment and costs associated with lease expirations. |
|
|
|
|
Income Taxes. We are subject to state and federal income taxes but are currently not in
a tax paying position for regular federal income taxes, primarily due to the current
deductibility of intangible drilling costs (IDC). We do pay some state income taxes
where our IDC deductions do not exceed our taxable income or where state income taxes are
determined on another basis. Currently, substantially all of our federal taxes are
deferred; however, at some point, we anticipate using all of our net operating loss
carryforwards and we will recognize current income tax expense and continue to recognize
current tax expense as long as we are generating taxable income. |
24
Managements Discussion and Analysis of Income and Operations
Overview of 2007 Results
During 2007, we achieved the following results:
|
|
|
Achieved 22% production growth and 27% reserve growth; |
|
|
|
|
Drilled 698 net wells; |
|
|
|
|
Continued expansion of drilling inventory and emerging plays; |
|
|
|
|
Posted record financial results and continued balance sheet improvements; and |
|
|
|
|
Completed acquisitions of properties containing 133 Bcfe of proved reserves. |
Our 2007 performance reflects another year of successfully executing our strategy of growth
through drilling and complementary acquisitions. The business of exploring for, developing, and
acquiring oil and gas is highly competitive and capital intensive. As in any commodity business,
the costs associated with finding, acquiring, extracting, and financing the operation are critical
to profitability and long-term value creation for stockholders. Generating meaningful growth while
containing costs presents an ongoing challenge. During periods of historically high oil and gas
prices, drilling service and operating cost increases are more prevalent due to increased
competition for goods and services. We faced other challenges in 2007 including attracting and
retaining qualified personnel, consummating and integrating acquisitions, and accessing the capital
markets to fund our growth on sufficiently favorable terms. We have continued to expand and
improve the technical staff through the hiring of additional experienced professionals. Our
inventory of exploration and development prospects continues to be strong, providing new growth
opportunities, greater diversification of technical risk and better efficiency.
Total revenues increased 16% in 2007 over the same period of 2006. This increase is due to
higher production and higher realized oil and gas prices. Our 2007 production growth is due to the
continued success of our drilling program and to acquisitions completed in 2006 and 2007. Realized
prices were higher by 18% in 2007. As discussed in Item 1A of this report, significant changes in
oil and gas prices can have a significant impact on our balance sheet and our results of
operations, including the fair value of our derivatives.
Oil and Gas Sales, Production and Realized Price Calculations
Our oil and gas sales vary from year to year as a result of changes in commodity prices or
volumes of production sold. Hedges realized reflect settlements on those derivatives that qualify
for hedge accounting. Oil and gas sales increased 44% from 2006 due to a 22% increase in
production and an 18% increase in realized prices. Oil and gas sales in 2006 increased 21% from
2005 due to an 18% increase in production and a 3% increase in realized prices. The following
table illustrates the primary components of oil and gas sales for each of the last three years (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Oil and Gas Sales |
|
|
|
|
|
|
|
|
|
|
|
|
Oil wellhead |
|
$ |
226,686 |
|
|
$ |
189,516 |
|
|
$ |
156,102 |
|
Oil hedges realized |
|
|
(23,755 |
) |
|
|
(45,265 |
) |
|
|
(42,948 |
) |
|
|
|
|
|
|
|
|
|
|
Total
oil
revenue |
|
$ |
202,931 |
|
|
$ |
144,251 |
|
|
$ |
113,154 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas wellhead |
|
$ |
585,538 |
|
|
$ |
466,099 |
|
|
$ |
461,132 |
|
Gas hedges realized |
|
|
27,916 |
|
|
|
(47,916 |
) |
|
|
(106,404 |
) |
|
|
|
|
|
|
|
|
|
|
Total
gas
revenue |
|
$ |
613,454 |
|
|
$ |
418,183 |
|
|
$ |
354,728 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL |
|
$ |
46,152 |
|
|
$ |
36,705 |
|
|
$ |
31,891 |
|
NGL hedges realized |
|
|
|
|
|
|
|
|
|
|
(4,302 |
) |
|
|
|
|
|
|
|
|
|
|
Total
NGL
revenue |
|
$ |
46,152 |
|
|
$ |
36,705 |
|
|
$ |
27,589 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined wellhead |
|
$ |
858,376 |
|
|
$ |
692,320 |
|
|
$ |
649,126 |
|
Combined hedges |
|
|
4,161 |
|
|
|
(93,181 |
) |
|
|
(153,655 |
) |
|
|
|
|
|
|
|
|
|
|
Total
oil and
gas
sales |
|
$ |
862,537 |
|
|
$ |
599,139 |
|
|
$ |
495,471 |
|
|
|
|
|
|
|
|
|
|
|
25
Our production continues to grow through continued drilling success and additions from
acquisitions. For 2007, our production volumes increased 15% in our Appalachia Area, increased 28%
in our Southwest Area and declined 17% in our Gulf Coast Area. For 2006, our production volumes
increased 10% in our Appalachia Area, increased 29% in our Southwest Area and declined 36% in our
Gulf Coast Area. Our production for each of the last three years is set forth in the following
table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
2005 |
Production |
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls) |
|
|
3,359,668 |
|
|
|
3,039,150 |
|
|
|
2,929,013 |
|
NGLs (bbls) |
|
|
1,114,730 |
|
|
|
1,091,785 |
|
|
|
1,011,692 |
|
Natural gas (mcf) |
|
|
89,594,626 |
|
|
|
70,712,770 |
|
|
|
57,608,816 |
|
Total (mcfe) (a) |
|
|
116,441,014 |
|
|
|
95,498,380 |
|
|
|
81,253,046 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily production |
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls) |
|
|
9,205 |
|
|
|
8,326 |
|
|
|
8,025 |
|
NGLs (bbls) |
|
|
3,054 |
|
|
|
2,991 |
|
|
|
2,772 |
|
Natural gas (mcf) |
|
|
245,465 |
|
|
|
193,734 |
|
|
|
157,832 |
|
Total (mcfe) (a) |
|
|
319,016 |
|
|
|
261,639 |
|
|
|
222,611 |
|
|
(a) Oil and NGLs are converted to mcfe at the rate of one barrel
equals six mcfe. |
Our average realized price (including all derivative settlements) received for oil and gas
during 2007 was $8.02 per mcfe compared to $6.80 per mcfe in 2006 and $6.13 per mcfe in 2005. Our
average realized price calculation (including all derivative settlements) includes all cash
settlements for derivatives, whether or not they qualify for hedge accounting. Average price
calculations for each of the last three years is shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
2005 |
Average Prices |
|
|
|
|
|
|
|
|
|
|
|
|
Average sales prices (wellhead): |
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (per bbl) |
|
$ |
67.47 |
|
|
$ |
62.36 |
|
|
$ |
53.30 |
|
NGLs (per bbl) |
|
$ |
41.40 |
|
|
$ |
33.62 |
|
|
$ |
31.52 |
|
Natural gas (per mcf) |
|
$ |
6.54 |
|
|
$ |
6.59 |
|
|
$ |
8.00 |
|
Total (per mcfe) (a) |
|
$ |
7.37 |
|
|
$ |
7.25 |
|
|
$ |
7.99 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized prices (including derivatives that qualify
for hedge accounting): |
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (per bbl) |
|
$ |
60.40 |
|
|
$ |
47.46 |
|
|
$ |
38.63 |
|
NGLs (per bbl) |
|
$ |
41.40 |
|
|
$ |
33.62 |
|
|
$ |
27.27 |
|
Natural gas (per mcf) |
|
$ |
6.85 |
|
|
$ |
5.91 |
|
|
$ |
6.16 |
|
Total (per mcfe) (a) |
|
$ |
7.41 |
|
|
$ |
6.27 |
|
|
$ |
6.10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized prices (including all derivative settlements): |
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (per bbl) |
|
$ |
60.16 |
|
|
$ |
47.46 |
|
|
$ |
38.63 |
|
NGLs (per bbl) |
|
$ |
41.40 |
|
|
$ |
33.62 |
|
|
$ |
27.27 |
|
Natural gas (per mcf) |
|
$ |
7.66 |
|
|
$ |
6.62 |
|
|
$ |
6.21 |
|
Total (per mcfe) (a) |
|
$ |
8.02 |
|
|
$ |
6.80 |
|
|
$ |
6.13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average NYMEX prices (b): |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per bbl) |
|
$ |
72.34 |
|
|
$ |
66.22 |
|
|
$ |
56.56 |
|
Natural gas (per mcf) |
|
$ |
6.92 |
|
|
$ |
7.26 |
|
|
$ |
8.55 |
|
|
(a) Oil and NGLs are converted at the rate of one barrel equals six mcfe. |
|
(b) Based on average of bid week prompt month prices. |
26
Derivative fair value income (loss) decreased to a loss of $7.8 million in 2007 compared to a
gain of $142.4 million in 2006 and a gain of $10.3 million in 2005. In the fourth quarter of 2005,
certain of our gas hedges no longer qualified for hedge accounting due to the effect of gas price
volatility on the correlation between realized prices and hedge reference prices. Also, as a
result of the sale of our Gulf of Mexico assets in the first quarter of 2007, the portion of our
derivatives which were designated to our Gulf of Mexico production was marked to market resulting
in fair value income of $209,000. In the fourth quarter of 2007, we began marking a portion of our
oil hedges designated as Permian Basin production to market due to the anticipated sale of a
portion of our Permian properties resulting in derivative fair value loss of $14.7 million. The
loss of hedge accounting treatment creates volatility in our revenues as gains and losses from
non-hedge derivatives are included in total revenues and are not included in our balance sheet in
accumulated other compensation loss. As commodity prices increase or decrease such changes will
have an opposite effect on the mark-to-market value of our derivatives. Because oil prices
increased dramatically in 2007, our derivatives became comparatively less valuable. However, we
expect these losses will be offset by higher wellhead revenues in the future. Beginning in the
third quarter of 2007, we have also entered into basis swap agreements which do not qualify for
hedge accounting purposes and are marked to market. Hedge ineffectiveness included in this
category is associated with our hedging contracts that qualify for hedge accounting under SFAS No.
133. The following table presents information about the components of derivative fair value income
(loss) for each of the years in the three-year period ended December 31, 2007 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Hedge ineffectiveness realized |
|
$ |
968 |
|
|
$ |
|
|
|
$ |
|
|
unrealized (a) |
|
|
(820 |
) |
|
|
5,965 |
|
|
|
(3,471 |
) |
Change in fair value of derivatives that do not qualify for |
|
|
(78,769 |
) |
|
|
86,491 |
|
|
|
10,868 |
|
hedge accounting (a)
Realized gain on settlements gas (b) |
|
|
71,098 |
|
|
|
49,939 |
|
|
|
2,906 |
|
Realized loss on settlements oil (b) |
|
|
(244 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative fair value (loss) income |
|
$ |
(7,767 |
) |
|
$ |
142,395 |
|
|
$ |
10,303 |
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
These amounts are unrealized and are not included in average sales price
calculations. |
| |
(b) |
These amounts represent realized gains and losses on settled derivatives that do not
qualify for hedge accounting which before settlement have been recognized in the unrealized
mark-to-market component of derivative fair value income (loss). These settlements are
included in average realized price calculations (including all derivative settlements). |
Other revenue increased in 2007 to a gain of $5.0 million compared to a gain of $856,000 in
2006 and a gain of $1.0 million in 2005. The 2007 period includes income from equity method
investments of $974,000 and other miscellaneous income. The 2006 period includes income from
equity method investments of $548,000. The 2005 period includes income of $514,000 from
Independent Producer Finance, one of our businesses that no longer operates.
Comparison of 2007 and 2006 Expenses
Our unit costs have increased as we continue to grow. We believe some of our expense
fluctuations should be analyzed on a unit-of-production, or per mcfe basis. The following table
presents information about certain of our expenses on a per mcfe basis for 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses (per mcfe) |
|
2007 |
|
2006 |
|
Change |
|
% Change |
Direct operating expense |
|
$ |
0.93 |
|
|
$ |
0.85 |
|
|
$ |
0.08 |
|
|
|
9 |
% |
Production and ad valorem tax expense |
|
|
0.36 |
|
|
|
0.38 |
|
|
|
(0.02 |
) |
|
|
5 |
% |
General and administrative expense |
|
|
0.59 |
|
|
|
0.52 |
|
|
|
0.07 |
|
|
|
13 |
% |
Interest expense |
|
|
0.67 |
|
|
|
0.58 |
|
|
|
0.09 |
|
|
|
15 |
% |
Depletion, depreciation and amortization expense |
|
|
1.95 |
|
|
|
1.62 |
|
|
|
0.33 |
|
|
|
20 |
% |
Direct operating expense for 2007 increased $27.5 million, or 33.8%, to $108.7 million due to
higher oilfield service costs, higher volumes and the integration of our recent acquisitions. Our
operating expenses are increasing as we add new wells and maintain production from our existing
properties. On a per mcfe basis, direct operating expenses were $0.93 and increased $0.08 from
2006 with the increase consisting primarily of higher water disposal costs ($0.02 per mcfe), higher
well services and equipment costs ($0.04 per mcfe), higher workover costs ($0.02 per mcfe) and a
$0.01 per mcfe increase in stock-
based compensation. The following table summarizes direct operating expenses per mcfe for
2007 and 2006:
27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% |
|
|
|
2007 |
|
|
2006 |
|
|
Change |
|
|
Change |
|
Lease operating expense |
|
$ |
0.85 |
|
|
$ |
0.80 |
|
|
$ |
0.05 |
|
|
|
6 |
% |
Workovers |
|
|
0.06 |
|
|
|
0.04 |
|
|
|
0.02 |
|
|
|
50 |
% |
Stock-based compensation |
|
|
0.02 |
|
|
|
0.01 |
|
|
|
0.01 |
|
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total direct operating expenses |
|
$ |
0.93 |
|
|
$ |
0.85 |
|
|
$ |
0.08 |
|
|
|
9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and ad valorem taxes are paid based on market prices and not hedged prices. For
2007, these taxes increased $6.0 million, or 17%, from the same period of the prior year. On a per
mcfe basis, production and ad valorem taxes decreased from $0.38 in 2006 to $0.36 in 2007 with
lower ad valorem taxes per mcfe due to lower property tax rates in Texas as a result of the new
margin tax.
General and administrative expense for 2007 increased $18.5 million, or 37%, primarily due to
higher salaries and benefits of $9.2 million ($0.03 per mcfe), higher office rent and general
office expense of $2.3 million ($0.01 per mcfe) and higher stock based compensation of $4.0 million
($0.01 per mcfe). The stock-based compensation expense represents amortization of restricted stock
grants and stock option/SARs expense under SFAS No. 123(R). On a per mcfe basis, general and
administration expense increased from $0.52 in 2006 to $0.59 in 2007. The following table
summarizes general and administrative expenses per mcfe for 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% |
|
|
|
2007 |
|
|
2006 |
|
|
Change |
|
|
Change |
|
General and administrative |
|
$ |
0.43 |
|
|
$ |
0.37 |
|
|
$ |
0.06 |
|
|
|
16 |
% |
Stock-based compensation |
|
|
0.16 |
|
|
|
0.15 |
|
|
|
0.01 |
|
|
|
7 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general and administrative expenses |
|
$ |
0.59 |
|
|
$ |
0.52 |
|
|
$ |
0.07 |
|
|
|
13 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense for 2007 increased $21.9 million, or 39%, to $77.7 million with higher
average debt balances and the refinancing of certain debt from short-term floating to longer-term
fixed rates. In September 2007, we issued $250.0 million of 7.5% senior subordinated notes due
2017 which added $4.8 million of interest costs in 2007. In May 2006, we issued $250.0 million of
7.5% senior subordinated notes due 2016 which increased interest expense by $9.1 million in 2007.
The proceeds from these issuances were used to retire shorter term lower rate bank debt. In 2007,
the average debt outstanding on the bank credit facility was $417.6 million with an average
interest rate of 6.4% compared to an average debt outstanding in 2006 of $347.8 million, with an
average interest rates of 6.4%.
Depletion, depreciation and amortization (DD&A) for 2007 increased $72.6 million, or 47%, to
$227.3 million, due to higher production and higher depletion rates. Depletion rates increased
16%, or $0.24 per mcfe, due to increased drilling costs and the mix of our production. DD&A
increased from $1.62 per mcfe in 2006 to $1.95 per mcfe in 2007. For 2008, based on our current
reserve base, we expect our DD&A rate to average approximately $2.10 per mcfe. The twelve months
ended 2007 also includes higher unproved property impairment of $3.0 million ($0.03 per mcfe),
higher acreage expiration expense of $3.4 million ($0.03 per mcfe), higher accretion expense
related to asset retirement obligations of $2.3 million ($0.01 per mcfe) and higher depreciation
expense of $3.3 million ($0.01 per mcfe). In the fourth quarter of 2006, we lowered our salvage
value estimates on our Appalachia wells which increased DD&A expense by $4.6 million.
Our operating expenses also include other expenses that generally do not trend with
production. These expenses include stock-based compensation, exploration expense and deferred
compensation plan expense. In 2007, stock-based compensation of $24.0 million is a component of direct operating
expense ($1.8 million), exploration expense ($3.5 million) and general and administrative expense
($18.2 million). In 2006, stock-based compensation of $19.1 million is a component of direct operating expense ($1.4 million), exploration expense ($3.1 million) and general and administrative expense ($14.3 million). In 2007 and
2006, this expense represents the amortization of restricted stock grants, stock options and SARs
as they become vested.
28
Exploration expense for 2007 decreased $743,000, or 2%, to $43.3 million due to lower seismic
costs ($4.3 million) somewhat offset by higher personnel costs. The following table details our
exploration-related expenses (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% |
|
|
|
2007 |
|
|
2006 |
|
|
Change |
|
|
Change |
|
Dry hole expense |
|
$ |
15,149 |
|
|
$ |
15,084 |
|
|
$ |
65 |
|
|
|
|
|
Seismic |
|
|
10,933 |
|
|
|
15,277 |
|
|
|
(4,344 |
) |
|
|
28 |
% |
Personnel expense |
|
|
8,924 |
|
|
|
6,917 |
|
|
|
2,007 |
|
|
|
29 |
% |
Stock-based compensation expense |
|
|
3,473 |
|
|
|
3,079 |
|
|
|
394 |
|
|
|
13 |
% |
Delay rentals and other |
|
|
4,866 |
|
|
|
3,731 |
|
|
|
1,135 |
|
|
|
30 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total exploration expense |
|
$ |
43,345 |
|
|
$ |
44,088 |
|
|
$ |
(743 |
) |
|
|
2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred compensation plan expense for 2007 increased to $28.3 million, or 312%, from $6.9
million in 2006. This non-cash expense relates to the increase or decrease in value of our common
stock and other investments held in our deferred compensation plans. In the fourth quarter of
2007, we recorded adjustments that decreased deferred compensation plan expense by $12.4 million.
Such adjustments were the result of an incorrect practice of adjusting our deferred compensation
liability for market value changes in unvested shares held in our deferred compensation plan. In
addition, interest and dividends related to the marketable securities held in the deferred
compensation plan were inappropriately recorded in accumulated other comprehensive loss. Of the
$12.4 million decrease in deferred compensation expense, $7.1 million is related to periods prior
to 2007 and $5.3 million is related to the first three quarters of 2007. Our common stock price
increased from $26.34 per share at the end of 2005 to $27.46 per share at the end of 2006 to $51.36
per share at the end of 2007.
Income tax expense for 2007 decreased $23.0 million, or 19%, to $98.8 million due to a 16%
decrease in income from continuing operations. Our effective tax rate was 37% for 2007 compared to
39% for 2006. The twelve months ended December 31, 2007 includes a non-recurring $3.0 million tax
benefit related to an increase in the Texas Margin Tax credit carryover. This benefit is related
to a change in the Texas law allowing companies to realize tax attributes carrying forward from the
previously applicable Texas Franchise tax to the new Texas Margin tax. The twelve months ended
December 31, 2006 includes a $2.8 million tax expense for changes in state tax rates. We expect
our effective tax rate to be approximately 37% for 2008. Given our available net operating loss
carryover, we do not expect to pay significant federal income taxes. We received a refund of
$299,000 for state income taxes in 2007.
Discontinued operations includes the operating results related to our Gulf of Mexico
properties and Austin Chalk properties that we sold in the first quarter of 2007. See also Note 4
to our consolidated financial statements.
Comparison of 2006 to 2005 Expenses
Our unit costs have increased as we continue to grow. We believe some of our expense
fluctuations should be analyzed on a unit of production, or per mcfe basis. The following table
presents information about certain of our operating expenses on a per mcfe basis for 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% |
Operating expenses (per mcfe) |
|
2006 |
|
2005 |
|
Change |
|
Change |
Direct operating expense |
|
$ |
0.85 |
|
|
$ |
0.71 |
|
|
$ |
0.14 |
|
|
|
20 |
% |
Production and ad valorem tax expense |
|
|
0.38 |
|
|
|
0.38 |
|
|
|
|
|
|
|
|
|
General and administration expense |
|
|
0.52 |
|
|
|
0.41 |
|
|
|
0.11 |
|
|
|
27 |
% |
Interest expense |
|
|
0.58 |
|
|
|
0.46 |
|
|
|
0.12 |
|
|
|
26 |
% |
Depletion, depreciation and amortization expense |
|
|
1.62 |
|
|
|
1.41 |
|
|
|
0.21 |
|
|
|
15 |
% |
Direct operating expense for 2006 increased $23.4 million to $81.3 million due to higher
oilfield service costs, higher volumes and the integration of our recent acquisitions. Our
operating expenses are increasing as we add new wells and maintain production from our existing
properties. On a per mcfe basis, direct operating expenses were $0.85 and increased 20% or $0.14
from 2005 consisting of higher utilities ($0.01 per mcfe), higher water disposal and equipment
costs ($0.06 per mcfe) and higher pumper expenses ($0.01 per mcfe). The following table summarizes
direct operating expenses per mcfe for 2006 and 2005:
29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% |
|
|
|
2006 |
|
|
2005 |
|
|
Change |
|
|
Change |
|
Lease operating |
|
$ |
0.80 |
|
|
$ |
0.66 |
|
|
$ |
0.14 |
|
|
|
21 |
% |
Workovers |
|
|
0.04 |
|
|
|
0.04 |
|
|
|
|
|
|
|
|
% |
Stock-based compensation |
|
|
0.01 |
|
|
|
0.01 |
|
|
|
|
|
|
|
|
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total direct operating expenses |
|
$ |
0.85 |
|
|
$ |
0.71 |
|
|
$ |
0.14 |
|
|
|
20 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and ad valorem taxes are paid based on market prices and not hedged prices. For
2006, these taxes increased $5.6 million, or 18%, from the same period of the prior year. On a per
mcfe basis, production and ad valorem taxes remained the same at $0.38.
General and administrative expense for 2006 increased $16.4 million, or 49%, to 49.9 million,
from 2005 due primarily to higher salaries and benefits of $6.0 million ($0.03 per mcfe), higher
office rent and general office expenses of $1.0 million ($0.01 per mcfe) and higher stock-based
compensation expense of $9.4 million ($0.09 per mcfe). The stock-based compensation expense
represents amortization of restricted stock grants in 2006 and 2005, expense related to the
adoption of SFAS No. 123(R) in 2006 and the mark-to-market of SARs granted to employees in 2005.
On a per mcfe basis, general and administration expense increased 27% from $0.41 in 2005 to $0.52
in 2006. The following table summarizes general and administrative expenses per mcfe for 2006 and
2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% |
|
|
|
2006 |
|
|
2005 |
|
|
Change |
|
|
Change |
|
General and administrative expense |
|
$ |
0.37 |
|
|
$ |
0.35 |
|
|
$ |
0.02 |
|
|
|
6 |
% |
Stock-based compensation |
|
|
0.15 |
|
|
|
0.06 |
|
|
|
0.09 |
|
|
|
150 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general and administrative expenses |
|
$ |
0.52 |
|
|
$ |
0.41 |
|
|
$ |
0.11 |
|
|
|
27 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense for 2006 increased $18.2 million, or 48%, to $55.8 million with higher
average interest rates, higher average debt balances and the refinancing of certain debt from
short-term floating to longer-term fixed rates. In May 2006, we issued $250.0 million of 7.5%
senior subordinated notes which added $9.7 million of interest costs. The proceeds from this
issuance were used to retire shorter term bank debt. Average debt outstanding on the bank credit
facility was $347.8 million with an average interest rate of 6.4% compared to an average debt
outstanding in 2005 of $314.8 million with an average interest rate of 4.5%.
Depletion, depreciation and amortization for 2006 increased $40.4 million, or 35%, to $154.7
million due to higher production and higher depletion rates. DD&A increased from $1.41 per mcfe in
2005 to $1.62 per mcfe in 2006. This increase is primarily related to our Stroud acquisition,
increasing drilling costs and the mix of our production. In the fourth quarter of 2006, we lowered
our salvage value estimates on our Appalachia wells which increased DD&A expense by $4.6 million.
Operating expenses also include stock-based compensation, exploration expense and deferred
compensation plan expenses that generally do not trend with production. In 2006, stock-based
compensation expense is a component of direct operating expense ($1.4 million), exploration expense
($3.1 million) and general and administrative expense ($14.3 million) and a $320,000 reduction of
gas transportation revenues for a total of $19.1 million. In 2005, stock-based compensation is a
component of direct operating expense ($480,000), exploration expense ($1.2 million) and general
and administrative expense ($4.9 million) and a reduction of $117,000 of gas transportation
revenues for a total of $6.7 million. This expense represents the amortization of restricted stock
grants in 2006 and 2005, expense related to the adoption of SFAS No. 123(R) in 2006 and in 2005,
the mark-to-market of SARs granted to employees.
Exploration expense increased 49% to $44.1 million due to higher seismic costs ($2.0 million),
higher dry hole costs ($8.5 million) and higher personnel costs. The following table details our
exploration-related expenses (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% |
|
|
|
2006 |
|
|
2005 |
|
|
Change |
|
|
Change |
|
Dry hole expense |
|
$ |
15,084 |
|
|
$ |
6,560 |
|
|
$ |
8,524 |
|
|
|
130 |
% |
Seismic |
|
|
15,277 |
|
|
|
13,292 |
|
|
|
1,985 |
|
|
|
15 |
% |
Personnel expense |
|
|
6,917 |
|
|
|
5,872 |
|
|
|
1,045 |
|
|
|
18 |
% |
Stock-based compensation expense |
|
|
3,079 |
|
|
|
1,250 |
|
|
|
1,829 |
|
|
|
146 |
% |
Other |
|
|
3,731 |
|
|
|
2,555 |
|
|
|
1,176 |
|
|
|
46 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total exploration expense |
|
$ |
44,088 |
|
|
$ |
29,529 |
|
|
$ |
14,559 |
|
|
|
49 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30
Deferred compensation plan expense for 2006 decreased $22.6 million, or 77%, to $6.9 million.
This non-cash expense relates to the increase or decrease in value of our common stock and other
investments held in our deferred compensation plans. Our common stock price increased from $13.64
per share at the end of 2004 to $26.34 per share at the end of 2005 to $27.46 per share at the end
of 2006.
Tax expense for 2006 increased $55.9 million, or 85%, to $121.8 million due to a 79% increase
in income from continuing operations. Our effective tax rate was 39% for 2006 compared to 37% in
2005. Given our available net operating loss carryforward, we do not expect to pay significant
federal income taxes. The twelve months ended December 31, 2006 includes a $2.8 million adjustment
for changes in state tax rates. We paid $1.8 million of state taxes in 2006.
Discontinued operations for 2006 and 2005 includes the results of operations for our Gulf of
Mexico assets which were sold in the first quarter of 2007. Discontinued operations for 2006 also
includes the operating results and impairment losses on the Austin Chalk properties which were
acquired as part of our 2006 Stroud acquisition. Due to significant price declines after the
purchase of these properties and volumes produced since the acquisition, we recognized an
impairment of $74.9 million. These properties were also sold in the first quarter of 2007. See
also Note 4 to our consolidated financial statements.
Managements Discussion and Analysis of Financial Condition, Cash Flows and Liquidity
Our main sources of liquidity and capital resources are internally generated cash flow from
operations, a committed bank credit facility, asset sales and access to both the debt and equity
capital markets. During 2007, our net cash provided from continuing operations of $632.1 million,
proceeds from our April 2007 common stock offering of $280.4 million, proceeds from our September
2007 note offering of $250.0 million and proceeds from the sale of assets of $234.3 million were
used to fund $1.2 billion of capital expenditures (including acquisitions and equity investments).
At December 31, 2007 we had $4.0 million in cash and total assets of $4.0 billion. Our debt to
capitalization ratio was 40.0% at December 31, 2007 compared to 45.5% at December 31, 2006. As of
December 31, 2007 and 2006, our total capitalization was as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
Bank debt |
|
$ |
303,500 |
|
|
$ |
452,000 |
|
Senior subordinated notes |
|
|
847,158 |
|
|
|
596,782 |
|
|
|
|
|
|
|
|
Total debt |
|
|
1,150,658 |
|
|
|
1,048,782 |
|
Stockholders equity |
|
|
1,728,022 |
|
|
|
1,256,161 |
|
|
|
|
|
|
|
|
Total capitalization |
|
$ |
2,878,680 |
|
|
$ |
2,304,943 |
|
|
|
|
|
|
|
|
Debt to capitalization ratio |
|
|
40 |
% |
|
|
46 |
% |
Long-term debt at December 31, 2007 totaled $1.2 billion, including $303.5 million of bank
credit facility debt and $847.2 million of senior subordinated notes. Our available borrowing
capacity at December 31, 2007 was $596.5 million. Cash is required to fund capital expenditures
necessary to offset inherent declines in production and reserves which is typical in the oil and
gas industry. Future success in growing reserves and production will be highly dependent on
capital resources available and the success of finding or acquiring additional reserves. We
believe that net cash generated from operating activities and unused committed borrowing capacity
under the bank credit facility combined with our oil and gas price hedges currently in place will
be adequate to satisfy near term financial obligations and liquidity needs. However, 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 oil and gas business. A
material drop in oil and gas prices or a reduction in production and reserves would reduce our
ability to fund capital expenditures, reduce debt, meet financial obligations and remain
profitable. We operate in an environment with numerous financial and operating risks, including,
but not limited to, the inherent risks of the search for, development and production of oil and
gas, the ability to buy properties and sell production at prices which provide an attractive return
and the highly competitive nature of the industry. Our ability to expand our reserve base is, in
part, dependent on obtaining sufficient capital through internal cash flow, bank borrowings or the
issuance of debt or equity securities. There can be no assurance that internal cash flow and other
capital sources will provide sufficient funds to maintain capital expenditures that we believe are
necessary to offset inherent declines in production and proved reserves.
Bank Debt
We maintain a $900.0 million revolving credit facility, which we refer to as our bank debt or
our bank credit facility. The bank credit facility is secured by substantially all of our assets
and matures on October 25, 2012. Availability under the bank credit facility is subject to a
borrowing base set by the lenders semi-annually with an option to set more often in certain
circumstances. The borrowing base is dependent on a number of factors, primarily the lenders
assessment of future cash flows. Redeterminations of the borrowing base require approval of 75% of
the lenders; increases require unanimous approval.
31
At February 20, 2008, the bank credit facility had a $1.5 billion borrowing base and a $900.0
million facility amount. Credit availability is equal to the lesser of the facility amount or the
borrowing base resulting in credit availability of $300.5 million on February 20, 2008. The
facility amount can be increased to the borrowing base with twenty days notice.
Our bank debt 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). Under the bank credit facility, common and preferred dividends are permitted.
The terms of each of our subordinated notes limit restricted payments (including dividends) to the
greater of $20.0 million or a formula based on earnings and equity issuances since the original
issuances of the notes. The 7.5% senior subordinated notes due in 2016 and 2017 also allow for any
cash proceeds received within twelve months from the sale of oil and gas properties purchased in an
acquisition using stock as consideration to be added to the restricted payment basket. At December
31, 2007, approximately $922.4 million was available under the restricted payment baskets for each
of the 7.375% senior subordinated notes, 6.375% senior subordinated notes and the $7.5% senior
subordinated notes due in 2017. There was $1.0 billion available under the restricted payment
basket for the 7.5% senior subordinated notes due 2016. The bank credit facility provides for a
restricted payment basket of $20.0 million plus 66-2/3% of net cash proceeds from common stock
issuances and 50% of net income. Approximately $735.2 million was available under the bank credit
facility restricted payment basket as of December 31, 2007. The debt agreements contain customary
covenants relating to debt incurrence, working capital, dividends and financial ratios. We were in
compliance with all covenants at December 31, 2007.
Cash Flow
Our principal sources of cash are operating cash flow, bank borrowings, asset sales and at
times, issuance of debt and equity securities. Our operating cash flow is highly dependent on oil
and gas prices. As of December 31, 2007, we had entered into hedging agreements covering 102.1
Bcfe for 2008 and 61.3 Bcfe for 2009. The $808.4 million of cash capital expenditures for 2007,
excluding acquisitions, was funded with internal cash flow and proceeds from asset sales. The $1.1
billion capital budget for 2008, which excludes acquisitions, is expected to increase production
and to expand the reserve base. Based on current projections, oil and gas futures prices and our
hedge position, the 2008 capital program is expected to be funded, primarily with internal cash
flow and asset sales.
Net cash provided from continuing operations in 2007 was $632.1 million, compared to $441.5
million in 2006 and $288.6 million in 2005. In 2007, cash flow from continuing operations
increased due to higher production volumes and higher realized prices partially offset by
increasing operating costs. In 2006, cash flow from operations increased due to higher production
volumes and prices partially offset by increasing operating, exploration and interest expenses. In
2005, cash flow from operations increased due to higher volumes and prices partially offset by
increasing operating costs.
Net cash used in investing activities in 2007 was $1.0 billion, compared to $911.7 million in
2006 and $432.4 million in 2005. In 2007, we spent $782.4 million in additions to oil and gas
properties, $336.5 million on acquisitions and $94.7 on equity method investments. Also in 2007,
we recognized proceeds of $234.3 million from the sale of assets. The 2006 period included $487.2
million in additions to oil and gas properties and $360.1 million of acquisitions. The 2005 period
included $266.4 million in additions to oil and gas properties and $153.6 million of acquisitions.
Net cash provided from financing activities in 2007 was $379.9 million, compared to $429.4
million in 2006 and $93.0 million in 2005. Historically, sources of financing have been primarily
bank borrowings and capital raised through equity and debt offerings. During 2007, we received
proceeds of $250.0 million from the issuance of our 7.5% senior subordinated notes due 2017 and
proceeds of $280.4 million from a common stock offering. During 2006, we received proceeds of
$249.5 million from the issuance of our 7.5% senior subordinated notes due 2016. During 2005, the
outstanding balance under our bank credit facility declined $154.7 million primarily due to the
proceeds received from the 6.375% senior subordinated notes due 2017 being applied to our bank
debt. During 2005, we also received proceeds of $109.2 million from a common stock offering.
Capital Requirements
Our primary needs for cash are for exploration, development and acquisition of oil and gas
properties, repayment of principal and interest on outstanding debt and payment of dividends.
During 2007, $820.0 million of capital was expended on drilling
projects. Also in 2007, $339.0 million was expended on acquisitions primarily to purchase additional interests in producing
properties and unproved acreage. The capital program, excluding acquisitions, was funded by net
cash flow from operations and proceeds from asset sales. The 2008 capital budget of $1.1 billion,
excluding acquisitions, is expected to be funded primarily by cash flow from operations and asset
sales. Development and exploration activities are highly discretionary, and, for the foreseeable
future, we expect such activities to be maintained at levels equal to internal cash flow and asset
sales. To the extent capital requirements exceed internal cash flow and proceeds from asset sales,
debt or equity may be issued to fund these requirements. We currently believe we have sufficient
liquidity and cash flow to meet our obligations for
the next twelve months; however, a drop in oil and gas prices or a reduction in production or
reserves could adversely affect our
32
ability to fund capital expenditures and meet our financial
obligations. Also, our obligations may change due to acquisitions, divestitures and continued
growth. We may issue additional shares of stock, subordinated notes or other debt securities to
fund capital expenditures, acquisitions, extend maturities or to repay debt.
Cash Dividend Payments
The amount of future dividends is subject to declaration by the Board of Directors and
primarily depends on earnings and capital expenditures. In 2007, we paid $19.1 million in
dividends to our common shareholders ($0.04 per share in the fourth quarter and $0.03 per share in
the third, second and first quarters). In 2006, we paid $12.2 million in dividends to our common
stockholders ($0.03 per share in the fourth quarter and $0.02 per share in the third, second and
first quarters). In 2005, we paid $7.6 million in dividends to our common stockholders ($0.0133
per share in the second and third quarters and $0.02 per share in the fourth quarter). Also in
2005, we paid $2.2 million in preferred stock dividends.
Future Commitments
In addition to our capital expenditure program, we are committed to making cash payments in
the future on two types of contracts: note agreements and operating leases. As of December 31,
2007, we do not have any capital leases nor have we entered into any material long-term contracts
for equipment. As of December 31, 2007, we do not have any significant off-balance sheet debt or
other such unrecorded obligations and we have not guaranteed the debt of any other party. 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, 2007. In addition to the contractual obligations listed on
the table below, our balance sheet at December 31, 2007 reflects accrued interest payable on our
bank debt of $739,000 which is payable in the first quarter of 2008. We expect to make annual
interest payments of $14.8 million per year on our 7.375% senior subordinated notes, $18.8 million
per year on our 7.5% senior subordinated notes due 2016, $9.6 million per year on our 6.375% senior
subordinated notes and $18.8 million per year on our 7.5% senior subordinated notes due 2017.
The following summarizes our contractual financial obligations at December 31, 2007 and their
future maturities. We expect to fund these contractual obligations with cash generated from
operating activities, borrowings under our bank credit facility and proceeds from asset sales.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payment due by period |
|
|
|
|
|
|
|
2009 and |
|
|
2011 and |
|
|
|
|
|
|
|
|
|
2008 |
|
|
2010 |
|
|
2012 |
|
|
Thereafter |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
|
|
|
Bank debt due 2012 |
|
$ |
|
|
|
$ |
|
|
|
$ |
303,500 |
(a) |
|
$ |
|
|
|
$ |
303,500 |
|
7.375% senior subordinated notes due 2013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
200,000 |
|
|
|
200,000 |
|
6.375% senior subordinated notes due 2015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
150,000 |
|
|
|
150,000 |
|
7.5% senior subordinated notes due 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
250,000 |
|
|
|
250,000 |
|
7.5% senior subordinated notes due 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
250,000 |
|
|
|
250,000 |
|
Operating leases |
|
|
9,657 |
|
|
|
19,221 |
|
|
|
12,801 |
|
|
|
8,568 |
|
|
|
50,247 |
|
Seismic agreements |
|
|
500 |
|
|
|
300 |
|
|
|
|
|
|
|
|
|
|
|
800 |
|
Derivative obligations (b) |
|
|
30,457 |
|
|
|
45,819 |
|
|
|
|
|
|
|
|
|
|
|
76,276 |
|
Asset retirement obligation liability |
|
|
1,903 |
|
|
|
9,816 |
|
|
|
2,538 |
|
|
|
61,051 |
|
|
|
75,308 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual obligations (c) |
|
$ |
42,517 |
|
|
$ |
75,156 |
|
|
$ |
318,839 |
|
|
$ |
919,619 |
|
|
$ |
1,356,131 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Due at termination date of our bank credit facility. We expect to renew our bank
credit facility, but there is no assurance that can be accomplished. Interest paid on our
bank credit facility would be approximately $28.0 million each year assuming no change in
the interest rate or outstanding balance. |
|
(b) |
|
Derivative obligations represent net open derivative contracts valued as of
December 31, 2007. While such payments will be funded by higher prices received from the
sale of our production, production receipts may be received after our payments to
counterparties which can result in borrowings under our bank credit facility. |
|
(c) |
|
This table excludes the liability for the deferred compensation plans since these
obligations will be funded with existing plan assets. |
Hedging Oil and Gas Prices
We enter into derivative agreements to reduce the impact of oil and gas price volatility. At
December 31, 2007, swaps were in place covering 71.3 Bcf of gas at prices averaging $8.82 per mcf.
We also had collars covering 54.8 Bcf of gas at weighted average floor and cap prices of $8.07 to
$9.73 and 6.2 million barrels of oil at weighted average floor and cap prices of $61.54 to $75.72.
The derivative fair value, represented by the estimated amount that would be realized or payable on
termination, based on a comparison of the contract price and a reference price, generally NYMEX,
approximated a pretax loss of $22.3 million at December 31, 2007. The contracts expire monthly
through December 2009. Settled transaction gains and
33
losses for derivatives that qualify for hedge
accounting are determined monthly and are included as increases or decreases on oil and gas sales
in the period the hedged production is sold. Oil and gas sales included realized hedging gains of
$4.2 million in 2007 compared to losses of $93.2 million in 2006 and losses of $153.7 million in
2005. Unrealized effective gains and losses on derivatives that qualify for hedge accounting are
recorded at an estimate of fair value based on a comparison of the contract price and a reference
price, generally NYMEX, on our consolidated balance sheet as accumulated other comprehensive
income, a component of stockholders equity.
At December 31, 2007, the following commodity derivative contracts were outstanding:
|
|
|
|
|
|
|
Period |
|
Contract Type |
|
Volume Hedged |
|
Average Hedge Price |
Natural Gas |
|
|
|
|
|
|
2008
|
|
Swaps
|
|
155,000 Mmbtu/day
|
|
$8.97 |
2008
|
|
Collars
|
|
70,000 Mmbtu/day
|
|
$8.01 $10.83 |
2009
|
|
Swaps
|
|
40,000 Mmbtu/day
|
|
$8.24 |
2009
|
|
Collars
|
|
80,000 Mmbtu/day
|
|
$8.12 $8.76 |
|
|
|
|
|
|
|
Crude Oil |
|
|
|
|
|
|
2008
|
|
Collars
|
|
9,000 bbl/day
|
|
$59.34 $75.48 |
2009
|
|
Collars
|
|
8,000 bbl/day
|
|
$64.01 $76.00 |
Some of our derivatives do not qualify for hedge accounting but are effective as economic
hedges of our commodity price exposure. These contracts are accounted for using the mark-to-market
accounting method. Under this method the contracts are carried at their fair value on our
consolidated balance sheet under the captions Unrealized derivative gains and Unrealized
derivative losses. We recognize all unrealized and realized gains and losses related to these
contracts in our consolidated statement of operations in the caption Derivative fair value income
(loss).
As of the fourth quarter of 2005, certain of our gas derivatives no longer qualified for hedge
accounting and are marked to market. Also, as a result of the sale of our Gulf of Mexico assets in
the first quarter of 2007, a portion of derivatives which were designated to our Gulf Coast
production was marked to market. In the fourth quarter of 2007, we began marking a portion of our
oil hedges designated as Permian production to market due to the anticipated sale of a portion of
our Permian properties. Derivatives that no longer qualify for hedge accounting are accounted for
using the mark-to-market accounting method described above. As of December 31, 2007, hedges on
64.0 Bcfe no longer qualify or are not designated for hedge accounting.
During the third and fourth quarter of 2007, in addition to the swaps and collars above, we
entered into basis swap agreements which do not qualify as hedges for hedge accounting purposes and
are marked to market. The price we receive for our production can be less than 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 the basis adjustments. The fair value
of the basis swaps was a net unrealized pre-tax gain of $145,000 at December 31, 2007.
Interest Rates
At December 31, 2007, we had $1.2 billion of debt outstanding. Of this amount, $850.0 million
bears interest at fixed rates averaging 7.3%. Bank debt totaling $303.5 million bears interest at
floating rates, which averaged 6.2% at year-end 2007. The 30-day LIBOR rate on December 31, 2007
was 4.6%. A 1% increase in short-term interest rates on the floating-rate debt outstanding at
December 31, 2007 would cost us approximately $3.0 million in additional annual interest.
Off-Balance Sheet Arrangements
We do not currently utilize any off-balance sheet arrangements to enhance our liquidity or
capital resource position, or for any other purpose.
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 oil and gas
prices and the costs to produce our reserves. Oil and gas 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. In a trend that
began in 2004 and accelerated through 2007, commodity prices for oil and gas increased
significantly. The higher prices have
34
led to increased activity in the industry and, consequently,
rising costs. These cost trends have put pressure not only on our operating costs but also on our
capital costs. We expect these costs to remain high for 2008.
The following table indicates the average oil and gas prices received over the last five years
and quarterly for 2007, 2006 and 2005. Average price calculations exclude all derivative
settlements whether or not they qualify for hedge accounting. Oil is converted to natural gas
equivalent at the rate of one barrel equals six mcfe.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Prices (Wellhead) |
|
|
Average NYMEX Prices (a) |
|
|
|
|
|
|
|
|
|
|
|
Equivalent |
|
|
|
|
|
|
|
|
|
Oil |
|
|
Natural Gas (Per |
|
|
Mcf |
|
|
Oil |
|
|
Natural Gas |
|
|
|
(Per bbl) |
|
|
mcf) |
|
|
(Per mcfe) |
|
|
(Per bbl) |
|
|
(Per mcf) |
|
Annual |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
$ |
67.47 |
|
|
$ |
6.54 |
|
|
$ |
7.37 |
|
|
$ |
72.34 |
|
|
$ |
6.92 |
|
2006 |
|
|
62.36 |
|
|
|
6.59 |
|
|
|
7.25 |
|
|
|
66.22 |
|
|
|
7.26 |
|
2005 |
|
|
53.30 |
|
|
|
8.00 |
|
|
|
7.99 |
|
|
|
56.56 |
|
|
|
8.55 |
|
2004 |
|
|
39.20 |
|
|
|
5.80 |
|
|
|
5.79 |
|
|
|
41.41 |
|
|
|
6.09 |
|
2003 |
|
|
28.23 |
|
|
|
5.03 |
|
|
|
4.85 |
|
|
|
31.04 |
|
|
|
5.44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarterly |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
$ |
56.01 |
|
|
$ |
6.41 |
|
|
$ |
6.88 |
|
|
$ |
58.27 |
|
|
$ |
6.96 |
|
Second |
|
|
62.20 |
|
|
|
6.95 |
|
|
|
7.57 |
|
|
|
65.03 |
|
|
|
7.56 |
|
Third |
|
|
70.51 |
|
|
|
5.97 |
|
|
|
7.01 |
|
|
|
75.38 |
|
|
|
6.13 |
|
Fourth |
|
|
82.12 |
|
|
|
6.80 |
|
|
|
7.94 |
|
|
|
90.68 |
|
|
|
7.03 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
$ |
59.74 |
|
|
$ |
8.33 |
|
|
$ |
8.41 |
|
|
$ |
63.48 |
|
|
$ |
9.07 |
|
Second |
|
|
65.36 |
|
|
|
6.28 |
|
|
|
7.17 |
|
|
|
70.70 |
|
|
|
6.82 |
|
Third |
|
|
64.53 |
|
|
|
6.12 |
|
|
|
7.00 |
|
|
|
70.48 |
|
|
|
6.53 |
|
Fourth |
|
|
59.80 |
|
|
|
5.91 |
|
|
|
6.58 |
|
|
|
60.21 |
|
|
|
6.62 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
$ |
47.01 |
|
|
$ |
5.98 |
|
|
$ |
6.25 |
|
|
$ |
49.84 |
|
|
$ |
6.32 |
|
Second |
|
|
48.72 |
|
|
|
6.41 |
|
|
|
6.65 |
|
|
|
53.17 |
|
|
|
6.80 |
|
Third |
|
|
59.94 |
|
|
|
7.88 |
|
|
|
8.16 |
|
|
|
63.19 |
|
|
|
8.25 |
|
Fourth |
|
|
56.38 |
|
|
|
11.30 |
|
|
|
10.54 |
|
|
|
60.02 |
|
|
|
12.85 |
|
|
|
|
(a) |
|
Based on average of bid week prompt month prices. |
Managements 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 and the reported
amounts of revenues and expenses during the year. We base our estimates on historical experience
and various other assumptions that we believe are reasonable; however, actual results may differ.
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.
Oil and Gas Properties
Proved reserves are defined by the SEC as those volumes of crude oil, condensate, natural gas
liquids and natural gas that geological and engineering data demonstrate with reasonable certainty
are recoverable 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
35
for reserves established by the SEC, 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 oil and gas 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 the depletion rates used by us. 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 who reports directly to our Chief Operating
Officer. To further ensure the reliability of our reserve estimates, we engage independent
petroleum consultants to review our estimates of proved reserves. Historical variances between our
reserve estimates and the aggregate estimates of our consultants have been less than 5%.
The following table sets forth a summary of the percent of reserves which were reviewed by
independent petroleum consultants for each of the years ended 2007, 2006 and 2005.
|
|
|
|
|
Audited (a) |
2007 |
|
2006 |
|
2005 |
86%
|
|
87%
|
|
84% |
|
|
|
|
|
|
|
|
(a) |
|
Audited reserves are those reserves estimated by our employees and
reviewed by an independent petroleum consultant. |
We use the successful efforts method to account for exploration and development expenditures.
Unsuccessful exploration drilling costs are expensed and can have a significant effect on reported
operating results. Successful exploration drilling costs and all development costs are capitalized
and systematically charged to expense using the units of production method based on proved
developed oil and gas reserves as estimated by our engineers and reviewed 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 charged 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.
We adhere to the Statement of Financial Accounting Standards No. 19, Financial Accounting and
Reporting by Oil and Gas Producing Companies, for recognizing any impairment of capitalized costs
to unproved properties. The greatest portion of these costs generally relate to the acquisition of
leasehold costs. The costs are capitalized and periodically evaluated (at least quarterly) as to
recoverability, based on changes brought about by economic factors and potential shifts in business
strategy employed by management. We consider a combination of time, geologic and engineering
factors to evaluate the need for impairment of these costs. Unproved properties had a net book
value of $271.4 million in 2007 compared to $226.2 million in 2006 and $28.5 million in 2005.
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. Estimated
reserves are used as the basis for calculating the expected future cash flows from a property,
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 oil and gas producing activities and reserve quantities in Note 19 to our
consolidated financial statements. Changes in the estimated reserves are considered in estimates
for accounting purposes and are reflected on a prospective basis.
We monitor our long-lived assets recorded in property, plant and equipment in our consolidated
balance sheet 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 oil and
natural gas sales prices, an estimate of the ultimate amount of recoverable oil and gas reserves
that will be produced from a field, the timing of future production, future production costs,
future abandonment costs, and future inflation. The need to test a property for impairment can be
based on several factors, including a significant reduction in sales prices for oil and/or gas,
unfavorable adjustment to reserves, physical damage to production equipment and facilities, a
change in costs, or other changes to contracts,
environmental regulations or tax laws. All of these factors must be considered when testing a
propertys carrying value for impairment. We cannot predict whether impairment charges may be
required in the future.
36
We are required to develop estimates of fair value to allocate purchase prices paid to acquire
businesses to the assets acquired and liabilities assumed under the purchase method of accounting.
The purchase price paid to acquire a business is allocated to its assets and liabilities based on
the estimated fair values of the assets acquired and liabilities assumed as of the date of
acquisition. We use all available information to make these fair value determinations. See Note 3
to our consolidated financial statements for information on these acquisitions.
Oil and Gas Derivatives
We enter into derivative contracts to mitigate our exposure to commodity price risk associated
with future oil and natural gas production. These contracts have historically consisted of
options, in the form of collars, and fixed price swaps. Under SFAS No. 133, every derivative
instrument is required to be recorded on the balance sheet as either an asset or a liability
measured at its fair value. If the derivative does not qualify as a hedge or is not designated as
a hedge, the change in fair value of the derivative is recognized currently in earnings. If the
derivative qualifies for cash flow hedge accounting, the change in fair value of the derivative is
recognized in accumulated other comprehensive income (equity) to the extent that the hedge is
effective and in the income statement to the extent it is ineffective.
Some of our derivatives do not qualify for hedge accounting but are effective as economic
hedges of our commodity price exposure. These contracts are accounted for using the mark-to-market
accounting method. Under this method, the contracts are carried at their fair value on our
consolidated balance sheet under the captions Unrealized derivative assets and Unrealized
derivative liabilities. We recognize all unrealized and realized gains and losses related to
these contracts on our consolidated statement of operations under the caption Derivative fair
value income (loss).
As of the fourth quarter of 2005, certain of our gas derivatives no longer qualified for hedge
accounting due to the effect of volatility of gas prices on the correlation between realized prices
and hedge reference prices. Also, as a result of the sale of our Gulf of Mexico assets in the
first quarter of 2007, the portion of derivatives which were designated to our Gulf Coast
production no longer qualified for hedge accounting resulting in derivative fair value income of
$209,000. In the fourth quarter of 2007, we began marking a portion of our oil hedges designated
as Permian production to market due to the anticipated sale of a portion of our Permian properties
resulting in derivative fair value loss of $14.7 million. These derivatives that no longer qualify
for hedge accounting under SFAS No. 133 are accounted for using the mark-to-market accounting
method described above.
During the third and fourth quarter of 2007, we entered into basis swap agreements which do
not qualify as hedges for hedge accounting and are also marked to market. The price we receive for
our gas production can be less than the NYMEX price because of adjustments for delivery location,
or basis, relative quality and other factors; therefore, we have entered into basis swap agreement
that effectively fix our basis adjustments.
While there is a risk that the financial benefit of rising oil and gas 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.
Asset Retirement Obligations
We have significant obligations to remove tangible equipment and restore land at the end of
oil and gas 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 oil and gas property balance. In
addition, increases in the discounted ARO liability resulting from the passage of time are
reflected as accretion expense, a component of depletion, depreciation and amortization in our
consolidated statement of operations. Due to the sale of our Gulf of Mexico assets in the first
quarter of 2007, our ARO liability decreased $20.0 million.
37
Deferred 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 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. A valuation allowance is recognized on deferred tax assets when we
believe that certain of these assets are not likely to be realized.
In determining deferred tax liabilities, accounting rules require OCI to be considered, even
though such income or loss has not yet been earned. At year-end 2006, deferred tax liabilities
exceeded deferred tax assets by $468.6 million, with $21.3 million of deferred tax liabilities
related to unrealized deferred hedging gains included in OCI. At year-end 2007, deferred tax
liabilities exceeded deferred tax assets by $563.9 million, with $16.3 million of deferred tax
assets related to unrealized hedging losses included in OCI.
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. 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
Oil, gas and natural gas liquids are recognized when the products are sold and delivery to the
purchaser has occurred. We use the sales method the account for gas imbalances, recognizing
revenue based on gas delivered rather than our working interest share of gas produced.
Accounting Standards Not Yet Adopted
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets
and Financial Liabilities. This statement permits entities to choose to measure many financial
instruments and certain other items at fair value that are not currently required to be measure at
fair value. It requires that unrealized gains and losses on items for which the fair value option
has been elected be recorded in net income. The statement also establishes presentation and
disclosure requirements designed to facilitate comparisons between entities that choose different
measurement attributes for similar types of assets and liabilities. For us, SFAS No. 159 will be
effective January 1, 2008, and retrospective application is not permitted. Should we elect to
apply the fair value option to any eligible items that exist at January 1, 2008, the effect of the
first remeasurement to fair value would be reported as a cumulative effect adjustment to the
opening balance of retained earnings. We will adopt SFAS No. 159 as of January 1, 2008 and the impact of the adoption will result in a reclassification of a $2.0 million pre-tax loss related to our investment securities from accumulated other
comprehensive loss to retained earnings.
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurement. This statement
defines fair value, establishes a framework for measuring fair value in generally accepted
accounting principles and expands disclosures about fair value measurements. SFAS No. 157 does not
require any new fair value measurements but may require some entities to change their measurement
practices. For us, SFAS No. 157 will be effective January 1, 2008. We have not yet determined
whether SFAS No. 157 will have a material impact on our financial condition, results of operations
or cash flow. However, we believe we will be required to provide additional disclosures as part of
future financial statements, beginning with the first quarter of 2008.
In December 2007, the FASB issued SFAS No. 141(R), Business Combinations. SFAS No. 141(R)
replaces SFAS No. 141. The statement retains the purchase method of accounting for acquisitions,
but requires a number of changes, including changes in the way assets and liabilities are
recognized in the purchase accounting. It changes the recognition of
38
assets acquired and liabilities assumed arising from contingencies, requires the
capitalization of in-process research and development at fair value, and requires the expensing of
acquisition-related costs as incurred. The statement will apply prospectively to business
combinations occurring in our fiscal year beginning January 1, 2009. We are currently evaluating
provisions of this statement.
ITEM 7A. QUANTITIVE 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 oil and gas 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 US dollar
denominated.
Market Risk
Our major market risk is exposure to oil and gas prices. Realized prices are primarily driven
by worldwide prices for oil and spot market prices for North American gas production. Oil and gas
prices have been volatile and unpredictable for many years.
Commodity Price Risk
We periodically enter into derivative arrangements with respect to our oil and gas production.
These arrangements are intended to reduce the impact of oil and gas price fluctuations. 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 also includes collars which assume a minimum
floor price and a predetermined ceiling price. Historically, we applied hedge accounting to
derivatives utilized to manage price risk associated with our oil and gas production. Accordingly,
we recorded change in the fair value of our swap and collar contracts, including changes associated
with time value, under the caption, Accumulated other comprehensive income (loss) and into oil
and gas sales when the forecasted sale of production occurs. Any hedge ineffectiveness associated
with contracts qualifying for and designated as a cash flow hedge is reported currently each period
under the caption Derivative fair value income (loss) in our consolidated statement of
operations. Some of our derivatives do not qualify for hedge accounting but are effective as
economic hedges of our commodity price exposure. These contracts are accounted for using the
mark-to-market accounting method. Under this method, the contracts are carried at their fair value
on our consolidated balance sheet under the captions Unrealized derivative gains and Unrealized
derivative losses. We recognize all unrealized and realized gains and losses related to these
contracts in our consolidated statement of operations under the caption Derivative fair value
income (loss). Generally, derivative losses occur when market prices increase, which are offset
by gains on the underlying physical commodity transaction. Conversely, derivative gains occur when
market prices decrease, which are offset by losses on the underlying commodity transaction. We do
not enter into derivative instruments for trading purposes.
As of December 31, 2007, we had oil and gas swaps in place covering 71.3 Bcf of gas. We also
had collars covering 54.8 Bcf of gas and 6.2 million barrels of oil. These contracts expire
monthly through December 2009. The fair value, represented by the estimated amount that would be
realized upon immediate liquidation as of December 31, 2007, approximated a net unrealized pre-tax
loss of $22.3 million.
At December 31, 2007, the following commodity derivative contracts were outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period |
|
Contract Type |
|
Volume Hedged |
|
Average Hedge Price |
|
Fair Market Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
Natural Gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
Swaps |
|
155,000 Mmbtu/day |
|
$ |
8.97 |
|
|
$ |
64,982 |
|
2008 |
|
Collars |
|
55,000 Mmbtu/day |
|
$ |
8.01 - $10.83 |
|
|
$ |
19,288 |
|
2009 |
|
Swaps |
|
40,000 Mmbtu/day |
|
$ |
8.24 |
|
|
$ |
(3,812 |
) |
2009 |
|
Collars |
|
80,000 Mmbtu/day |
|
$ |
8.12 - $8.76 |
|
|
$ |
(3,070 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
Collars |
|
9,000 bbl/day |
|
$ |
59.34 - $75.48 |
|
|
$ |
(59,624 |
) |
2009 |
|
Collars |
|
8,000 bbl/day |
|
$ |
64.01 - $76.00 |
|
|
$ |
(40,085 |
) |
39
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, during the third and fourth quarter of 2007, we entered into basis swap agreements
which do not qualify for hedge accounting purpose and are marked to market. The price we receive
for our gas production can be 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 the basis adjustments. The fair value of the basis swaps was a net
realized pre-tax gain of $145,000 at December 31, 2007.
In 2007, a 10% reduction in oil and gas prices, excluding amounts fixed through hedging
transactions, would have reduced revenue by $85.4 million. If oil and gas futures prices at
December 31, 2007 had declined by 10%, the unrealized hedging gain at that date would have
increased $137.9 million.
Interest Rate Risk
At December 31, 2007, we had $1.2 billion of debt outstanding. Of this amount, $850.0 million
bears interest at a fixed rate averaging 7.3%. Bank debt totaling $303.5 million bears interest at
floating rates, which averaged 6.2% on that date. On December 31, 2007, the 30-day LIBOR rate was
4.6%. A 1% increase in short-term interest rates on the floating-rate debt outstanding at December
31, 2007 would cost us approximately $3.0 million in additional annual interest rates.
The fair value of our subordinated debt is based on quoted market prices. The following table
presents information on these fair values (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Carrying |
|
Fair |
|
|
Value |
|
Value |
Fixed rate debt: |
|
|
|
|
|
|
|
|
Senior Subordinated Notes due 2013 |
|
$ |
197,602 |
|
|
$ |
204,000 |
|
(The interest rate is fixed at a rate of 7.375%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior Subordinated Notes due 2015 |
|
|
150,000 |
|
|
|
147,750 |
|
(The interest rate is fixed at a rate of 6.375%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior Subordinated Notes due 2016 |
|
|
249,556 |
|
|
|
254,375 |
|
(The interest rate is fixed at a rate of 7.5%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior Subordinated Notes due 2017 |
|
|
250,000 |
|
|
|
251,250 |
|
(The interest rate is fixed at a rate of 7.5%) |
|
|
|
|
|
|
|
|
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. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
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 report. Our disclosure
controls and procedures are designed to provide reasonable assurance that the 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 on that evaluation, our Chief Executive Officer and our Chief Financial Officer
concluded that our disclosure controls and procedures are effective as of December 31, 2007.
40
Managements Annual Report on Internal Control over Financial Reporting and Attestation Report
of Registered Public Accounting Firm. Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002,
we have included a report of managements assessment of the design and effectiveness of its
internal controls as part of this Annual Report on Form 10-K for the fiscal year ended December 31,
2007. Ernst & Young LLP, our registered public accountants, also attested to, and reported on,
managements assessment of the effectiveness of internal control over financial reporting.
Managements report and the independent public accounting firms attestation report are included in
our 2007 Financial Statements in Item 15 under the captions Managements Report on Internal
Control over Financial Reporting and Report of Independent Registered Public Accounting Firm on
Internal Control over Financial Reporting and are incorporated herein by reference.
Changes in Internal Control over Financial Reporting. As of the end of the period covered by
this report, we carried out an evaluation, under the supervision and with the participation of our
Chief Executive Officer and Chief Financial Officer, of our internal control over financial
reporting to determine whether any changes occurred during the fourth quarter of 2007 that have
materially affected, or are reasonably likely to materially affect, our internal control over
financial reporting. Based on that evaluation, there were no changes in our internal control over
financial reporting or in other factors that have materially affected or are reasonably likely to
materially affect our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
41
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 2007 annual stockholders
meeting. Officers are appointed by our board of directors.
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Office |
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Held |
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Age |
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Since |
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Position |
Charles L.Blackburn
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80 |
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2003 |
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Director, Chairman of the Board |
Anthony V. Dub
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58 |
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1995 |
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Director |
V. Richard Eales
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71 |
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2001 |
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Director |
Allen Finkelson
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61 |
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1994 |
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Director |
Jonathan S. Linker
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59 |
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2002 |
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Director |
Kevin S. McCarthy
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48 |
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2005 |
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Director |
John H. Pinkerton
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53 |
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1990 |
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Director, President, Chief Executive Officer |
Jeffrey L. Ventura
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50 |
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2003 |
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Director, Executive Vice President Chief Operating Officer |
Alan W. Farquharson
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50 |
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2007 |
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Senior Vice President Reservoir Engineering |
Steven L. Grose
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59 |
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2005 |
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Senior Vice President Appalachia |
Roger S. Manny
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50 |
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2003 |
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Senior Vice President and Chief Financial Officer |
Chad L. Stephens
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52 |
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1990 |
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Senior Vice President Corporate Development |
Rodney L. Waller
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58 |
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1999 |
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Senior Vice President, Chief Compliance Officer and Corporate Secretary |
Mark D. Whitley
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56 |
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2005 |
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Senior Vice President Permian Business Unit and Engineering
Technology |
Charles L. Blackburn was elected as a director in 2003 and appointed as the non-executive
Chairman of the Board. Mr. Blackburn has more than 40 years experience in oil and gas exploration
and production serving in several executive and board positions. Previously, he served as Chairman
and Chief Executive Officer of Maxus Energy Corporation from 1987 until that companys sale to YPF
Socieded Anonima in 1995. Maxus was the oil and gas producer which remained after Diamond Shamrock
Corporations spin-off of its refining and marketing operations. Mr. Blackburn joined Diamond
Shamrock in 1986 as President of their exploration and production subsidiary. From 1952 through
1986, Mr. Blackburn was with Shell Oil Company, serving as Director and Executive Vice President
for exploration and production for the final ten years of that period. Mr. Blackburn has
previously served on the Boards of Anderson Clayton and Co. (1978-1986), King Ranch Corp.
(1987-1988), Penrod Drilling Co. (1988-1991), Landmark Graphics Corp. (1992-1996) and Lone Star
Technologies, Inc. (1991-2001). Currently, Mr. Blackburn also serves as an advisory director to
the oil and gas loan committee of Guaranty Bank. Mr. Blackburn received his Bachelor of Science
degree in Engineering Physics from the University of Oklahoma in 1952.
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 & Poors in 2004. Capital IQ is the
leader in helping organizations capitalize on synergistic integration of market intelligence,
institutional knowledge and relationships. Mr. Dub received a Bachelor of Arts, magna cum laude,
from Princeton University.
V. Richard Eales became a director in 2001. Mr. Eales has over 35 years of experience in the
energy, high 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. Prior to 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 from Cornell University and his Masters in Business
Administration from Stanford University.
Allen Finkelson became a director in 1994. Mr. Finkelson has been a partner at Cravath,
Swaine & Moore LLP since 1977, 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.
42
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 business since 1972. Mr. Linker joined
First Reserve Corporation in 1988 and was a Managing Director of the firm from 1996 until July
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, and Manager of Shelby Resources
Inc., all small, privately-owned exploration and production companies. Mr. Linker received a
Bachelor of Arts in Geology from Amherst College, a Masters in Geology from Harvard University and
an MBA from Harvard Universitys Graduate School of Business Administration.
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. 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 Clearwater Natural
Resources, L.P. and Direct Fuel Partners, L.P. He earned a
Bachelor of Arts in Economics and Geology from Amherst College and an MBA in Finance from the
University of Pennsylvanias Wharton School.
John H. Pinkerton, President, Chief Executive Officer and a director, became a director in
1988. He joined Range as President in 1990 and was appointed Chief Executive Officer in 1992.
Previously, Mr. Pinkerton was Senior Vice President of Snyder Oil Corporation (SOCO). Before
joining SOCO in 1980, Mr. Pinkerton was with Arthur Andersen. Mr. Pinkerton received his Bachelor
of Arts in Business Administration from Texas Christian University and a masters degree from the
University of Texas at Arlington.
Jeffrey L. Ventura, Executive Vice President Chief Operating Officer, joined Range in 2003
and became a director in 2005. Previously, Mr. Ventura served as President and Chief Operating
Officer of Matador Petroleum Corporation which he joined in 1997. Prior to 1997, 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, 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.
Alan W. Farquharson, Senior Vice President Reservoir Engineering, joined Range in 1998.
Mr. Farquharson has held the positions of Manager and Vice President of Reservoir Engineering. In
February 2007, Mr. Farquharson was appointed Senior Vice President. Prior to 1998, Mr. Farquharson
held various positions with Union Pacific Resources including Engineering Manager Business
Development International. Prior to 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.
Steven L. Grose, Senior Vice President Appalachia, joined Range in 1980. Previously, Mr.
Grose was employed by Halliburton Services, Inc. from 1971 until 1978. Mr. Grose is a member of
the Society of Petroleum Engineers and is a past president of The Ohio Oil and Gas Association.
Mr. Grose received his Bachelor of Science degree in Petroleum Engineering from Marietta College.
Roger S. Manny, Senior Vice President and Chief Financial Officer, joined Range in 2003. From
1998 to 2003, Mr. Manny served as Executive Vice President and Chief Financial Officer of Matador
Petroleum Corporation. Prior to 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.
Chad L. Stephens, Senior Vice President Corporate Development, joined Range in 1990. Prior
to 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 and Gas Company. Mr.
Stephens received a Bachelor of Arts in Finance and Land Management from the University of Texas.
Rodney L. Waller, Senior Vice President, Chief Compliance Officer and Corporate Secretary,
joined Range in 1999. Since joining Range, Mr. Waller has held the position of Senior Vice
President and Corporate Secretary. In 2005, Mr. Waller was appointed Chief Compliance Officer.
Previously, Mr. Waller was Senior Vice President of SOCO, now part of Devon Energy Corporation.
Before joining SOCO, Mr. Waller was with Arthur Andersen. Mr. Waller is a certified public
accountant
43
and petroleum land man. Mr. Waller served as a director of Range from 1988 to 1994. Mr.
Waller received a Bachelor of Arts degree in Accounting from Harding University.
Mark D. Whitley, Senior Vice President Permian Business Unit and Engineering Technology,
joined Range in 2005. Previously, he served as Vice President Operations with Quicksilver
Resources for two years. Prior to that, he served as Production/Operation Manager for Devon Energy
Corporation, following the Devon/Mitchell merger. From 1982 to 2002, Mr. Whitley held a variety of
technical and managerial roles with Mitchell Energy and Development Corporation. Notably, he led
the team of engineers at Mitchell Energy who applied new stimulation techniques to unlock the shale
gas potential in the Fort Worth Basin. Previous positions included serving as a production and
reservoir engineer with Shell Oil. He holds a Bachelors degree in Chemical Engineering from
Worcester Polytechnic Institute and a Masters degree in Chemical Engineering from the University
of Kentucky.
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 2008 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 Commission initial
reports of ownership and reports of changes in ownership of our common stock and other equity
securities of ours. Directors, officers and 10% holders are required by Commission regulations to
send us copies of all of the Section 16(a) reports they file. Based solely upon a review of the
copies of the forms sent to us and the representations made by the reporting persons to us, we
believe that, other than as described below, during the fiscal year ended December 31, 2007, our
directors, officers and 10% holders complied with all filing requirements under Section 16(a) of
the Exchange Act. Each of those listed below had two delinquent Form 4 filings a filing on
February 26, 2007 for a transaction that occurred on February 21, 2007 and a filing on January 3,
2008 for a transaction that occurred on December 18, 2007:
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Mr. Steven Grose
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Mr. Jeffrey Ventura |
Mr. Roger Manny
|
|
Mr. Rodney Waller |
Mr. John Pinkerton
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Mr. Mark Whitley |
Mr. Chad Stephens |
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|
In addition, Mr. Alan Farquharson had a delinquent Form-4 filing on January 3, 2008 for a
transaction that occurred on December 18, 2007.
Code of Ethics
Code of Ethics. We have adopted a Code of Ethics that applies to our principal
executive officers, principal financial officer, principal accounting officer, or persons
performing similar functions. 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 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 the material under the heading Consideration of Director Nominees in the Range Proxy
Statement for the 2008 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 2008
Annual Meeting of stockholders which is incorporated herein by reference.
NYSE 303A Certification
The Chief Executive Officer of Range Resources Corporation made an unqualified certification
to the NYSE with respect to the Companys compliance with the NYSE Corporate Governance listing
standards on June 8, 2007.
44
ITEM 11. EXECUTIVE COMPENSATION
Information required by this item is incorporated by reference to such information as set
forth in our definitive Proxy Statement for the 2008 Annual Meeting of stockholders.
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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 our definitive proxy statement for the 2008 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 our definitive proxy statement for the 2008 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 our definitive proxy statement for the 2008 Annual Meeting of stockholders.
45
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Documents filed as part of the report
1. Financial Statements:
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PAGE |
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F- 1 |
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F- 2 |
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F- 3 |
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F- 4 |
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F- 5 |
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F- 6 |
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F- 7 |
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F- 8 |
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F- 9 |
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F-10 |
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F-32 |
Supplemental Information on Oil and Gas Exploration, Development and Production Activities (Unaudited) |
|
F-34 |
2. |
|
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. |
3. Exhibits:
(a) See Index of Exhibits on page F-37 for a description of the exhibits filed as a part of
this report.
46
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 NGL, which reflects relative energy content.
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 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.
infill well. A well drilled between known producing wells to better exploit the reservoir.
LIBOR. London Interbank Offer Rate, the rate of interest at which banks offer to lend to one
another in the wholesale money markets in the City of London. This rate is a yardstick for lenders
involved in many debt transactions.
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 NGL, 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.
47
proved developed reserves. Proved reserves that can be expected to be recovered through existing
wells with existing equipment and operating methods.
proved reserves. The estimated quantities of crude oil, natural gas and natural gas liquids which
geological and engineering data demonstrate with reasonable certainty to be recoverable in future
years from known reservoirs under existing economics and operating conditions.
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 index. Proved reserves at a point in time divided by the then production rate (annual
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 Commissions rules for
inclusion of oil and gas reserve information in financial statements filed with the Commission.
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.
48
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
Dated: February 26, 2008
RANGE RESOURCES CORPORATION
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By: |
/s/ John H. Pinkerton
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John H. Pinkerton |
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President and Chief Executive Officer |
|
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the capacity and on the
dates indicated.
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/s/ Charles L. Blackburn
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Chairman of the Board
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February 26, 2008 |
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/s/ John H. Pinkerton
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President, Chief Executive Officer and Director
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February 26, 2008 |
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/s/ Jeffrey L. Ventura
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Executive Vice President and Director
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February 26, 2008 |
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/s/ Roger S. Manny
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Chief Financial and Accounting Officer
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February 26, 2008 |
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/s/ Anthony V. Dub
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Director
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February 26, 2008 |
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/s/ V. Richard Eales
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Director
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February 26, 2008 |
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/s/ Allen Finkelson
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Director
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February 26, 2008 |
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/s/ Jonathan S. Linker
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Director
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February 26, 2008 |
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/s/ Kevin S. McCarthy
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Director
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February 26, 2008 |
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|
49
RANGE RESOURCES CORPORATION
INDEX TO FINANCIAL STATEMENTS
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Page |
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Number |
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F- 2 |
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F- 3 |
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F- 4 |
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F- 5 |
|
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F- 6 |
|
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|
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F- 7 |
|
|
|
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F- 8 |
|
|
|
|
F- 9 |
|
|
|
|
F-10 |
|
|
|
|
F-32 |
|
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|
F-34 |
|
F-1
MANAGEMENTS REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
To the Board of Directors and 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 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. 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, 2007. 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. Based on our assessment, we believe that, as of December 31, 2007, our
internal control over financial reporting is effective based on those criteria.
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By:
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/s/ John H. Pinkerton
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|
|
By:
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/s/ Roger S. Manny
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John H. Pinkerton
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|
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Roger S. Manny |
|
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President and Chief Executive Officer
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|
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Senior Vice President and Chief Financial Officer |
|
|
Fort Worth, Texas
February 25, 2008
F-2
REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING
To the Board of Directors and Stockholders of
Range Resources Corporation:
We have audited Range Resources Corporations internal control over financial reporting as of
December 31, 2007, based on criteria established in Internal Control Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Range
Resources Corporations 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 Managements Report on Internal Control over Financial
Reporting. Our responsibility is to express an opinion on the Companys 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 companys 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 companys 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 companys 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, 2007, 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, 2007 and 2006 and the related consolidated statements of operations, stockholders
equity, comprehensive income (loss) and cash flows for each of the three years in the period ended
December 31, 2007 and our report dated February 25, 2008 expressed an unqualified opinion thereon.
Ernst & Young LLP
Fort Worth, Texas
February 25, 2008
F-3
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the 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, 2007 and 2006, and the related consolidated statements of
operations, stockholders equity, comprehensive income (loss) and cash flows for each of the three
years in the period ended December 31, 2007. These consolidated financial statements are the
responsibility of the Companys management. Our responsibility is to express an opinion on these
consolidated 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 consolidated 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 consolidated financial statements referred to above present fairly, in all
material respects, the consolidated financial position of Range Resources Corporation at December
31, 2007 and 2006, and the consolidated results of their operations and their cash flows for each
of the three years in the period ended December 31, 2007, in conformity with U.S. generally
accepted accounting principles.
As discussed in Note 2 to the consolidated financial statements, in 2006, the Company adopted
Statement of Financial Accounting Standards No. 123(R), Share-Based Payment.
We also have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), Range Resources Corporations internal control over financial
reporting as of December 31, 2007, based on criteria established in Internal Control Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our
report dated February 25, 2008 expressed an unqualified opinion thereon.
Ernst & Young LLP
Fort Worth, Texas
February 25, 2008
F-4
RANGE RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
Assets |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and equivalents |
|
$ |
4,018 |
|
|
$ |
2,382 |
|
Accounts receivable, less allowance for doubtful accounts of $583 and $746 |
|
|
166,484 |
|
|
|
125,421 |
|
Assets held for sale |
|
|
|
|
|
|
79,304 |
|
Assets of discontinued operation |
|
|
|
|
|
|
78,161 |
|
Unrealized derivative gain |
|
|
53,018 |
|
|
|
93,588 |
|
Deferred tax asset |
|
|
26,907 |
|
|
|
|
|
Inventory and other |
|
|
11,387 |
|
|
|
10,069 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
261,814 |
|
|
|
388,925 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized derivative gain |
|
|
1,082 |
|
|
|
61,068 |
|
Equity method investments |
|
|
113,722 |
|
|
|
13,618 |
|
Oil and gas properties, successful efforts method |
|
|
4,443,577 |
|
|
|
3,359,093 |
|
Accumulated depletion and depreciation |
|
|
(939,769 |
) |
|
|
(751,005 |
) |
|
|
|
|
|
|
|
|
|
|
3,503,808 |
|
|
|
2,608,088 |
|
|
|
|
|
|
|
|
Transportation and field assets |
|
|
104,802 |
|
|
|
80,066 |
|
Accumulated depreciation and amortization |
|
|
(43,676 |
) |
|
|
(32,923 |
) |
|
|
|
|
|
|
|
|
|
|
61,126 |
|
|
|
47,143 |
|
Other assets |
|
|
74,956 |
|
|
|
68,832 |
|
|
|
|
|
|
|
|
Total assets |
|
$ |
4,016,508 |
|
|
$ |
3,187,674 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities |
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
212,514 |
|
|
$ |
171,914 |
|
Asset retirement obligations |
|
|
1,903 |
|
|
|
3,853 |
|
Accrued liabilities |
|
|
42,964 |
|
|
|
30,026 |
|
Liabilities of discontinued operation |
|
|
|
|
|
|
28,333 |
|
Accrued interest |
|
|
17,595 |
|
|
|
12,938 |
|
Unrealized derivative loss |
|
|
30,457 |
|
|
|
4,621 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
305,433 |
|
|
|
251,685 |
|
|
|
|
|
|
|
|
Bank debt |
|
|
303,500 |
|
|
|
452,000 |
|
Subordinated notes |
|
|
847,158 |
|
|
|
596,782 |
|
Deferred tax, net |
|
|
590,786 |
|
|
|
468,643 |
|
Unrealized derivative loss |
|
|
45,819 |
|
|
|
266 |
|
Deferred compensation liability |
|
|
120,223 |
|
|
|
90,094 |
|
Asset retirement obligations and other liabilities |
|
|
75,567 |
|
|
|
72,043 |
|
Commitments and contingencies |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders Equity |
|
|
|
|
|
|
|
|
Preferred stock, $1 par, 10,000,000 shares authorized, none issued and
outstanding |
|
|
|
|
|
|
|
|
Common stock, $.01 par, 250,000,000 shares authorized, 149,667,497 issued at
December 31, 2007 and 138,931,565 issued at December 31, 2006 |
|
|
1,497 |
|
|
|
1,389 |
|
Common stock held in treasury 155,500 shares at December 31, 2007 |
|
|
(5,334 |
) |
|
|
|
|
Additional paid-in capital |
|
|
1,386,884 |
|
|
|
1,057,938 |
|
Retained earnings |
|
|
371,800 |
|
|
|
160,313 |
|
Accumulated other comprehensive income (loss) |
|
|
(26,825 |
) |
|
|
36,521 |
|
|
|
|
|
|
|
|
Total stockholders equity |
|
|
1,728,022 |
|
|
|
1,256,161 |
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
4,016,508 |
|
|
$ |
3,187,674 |
|
|
|
|
|
|
|
|
See accompanying notes.
F-5
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales |
|
$ |
862,537 |
|
|
$ |
599,139 |
|
|
$ |
495,470 |
|
Transportation and gathering |
|
|
2,290 |
|
|
|
2,422 |
|
|
|
2,306 |
|
Derivative fair value (loss) income |
|
|
(7,767 |
) |
|
|
142,395 |
|
|
|
10,303 |
|
Other |
|
|
5,031 |
|
|
|
856 |
|
|
|
1,024 |
|
|
|
|
|
|
|
|
|
|
|
Total revenue |
|
|
862,091 |
|
|
|
744,812 |
|
|
|
509,103 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating |
|
|
108,741 |
|
|
|
81,261 |
|
|
|
57,866 |
|
Production and ad valorem taxes |
|
|
42,443 |
|
|
|
36,415 |
|
|
|
30,822 |
|
Exploration |
|
|
43,345 |
|
|
|
44,088 |
|
|
|
29,529 |
|
General and administrative |
|
|
68,428 |
|
|
|
49,886 |
|
|
|
33,444 |
|
Deferred compensation plan |
|
|
28,332 |
|
|
|
6,873 |
|
|
|
29,474 |
|
Interest expense |
|
|
77,737 |
|
|
|
55,849 |
|
|
|
37,619 |
|
Depletion, depreciation and amortization |
|
|
227,328 |
|
|
|
154,739 |
|
|
|
114,364 |
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
596,354 |
|
|
|
429,111 |
|
|
|
333,118 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes |
|
|
265,737 |
|
|
|
315,701 |
|
|
|
175,985 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax provision |
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
320 |
|
|
|
1,912 |
|
|
|
1,071 |
|
|
|
|
|
|
|
|
|
|
|
Deferred |
|
|
98,441 |
|
|
|
119,840 |
|
|
|
64,809 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
98,761 |
|
|
|
121,752 |
|
|
|
65,880 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
|
166,976 |
|
|
|
193,949 |
|
|
|
110,105 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued operations, net of taxes |
|
|
63,593 |
|
|
|
(35,247 |
) |
|
|
906 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
230,569 |
|
|
$ |
158,702 |
|
|
$ |
111,011 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic income from continuing operations |
|
$ |
1.16 |
|
|
$ |
1.45 |
|
|
$ |
0.89 |
|
discontinued operations |
|
|
0.44 |
|
|
|
(0.26 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net income |
|
$ |
1.60 |
|
|
$ |
1.19 |
|
|
$ |
0.89 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted income from continuing operations |
|
$ |
1.11 |
|
|
$ |
1.39 |
|
|
$ |
0.85 |
|
discontinued operations |
|
|
0.43 |
|
|
|
(0.25 |
) |
|
|
0.01 |
|
|
|
|
|
|
|
|
|
|
|
net income |
|
$ |
1.54 |
|
|
$ |
1.14 |
|
|
$ |
0.86 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
143,791 |
|
|
|
133,751 |
|
|
|
124,130 |
|
Diluted |
|
|
149,911 |
|
|
|
138,711 |
|
|
|
129,126 |
|
See accompanying notes.
F-6
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
230,569 |
|
|
$ |
158,702 |
|
|
$ |
111,011 |
|
Adjustments to reconcile net cash provided from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
(Income) loss from discontinued operations |
|
|
(63,593 |
) |
|
|
35,247 |
|
|
|
(906 |
) |
Income from equity method investments |
|
|
(974 |
) |
|
|
(548 |
) |
|
|
|
|
Deferred income tax expense |
|
|
98,441 |
|
|
|
119,840 |
|
|
|
64,809 |
|
Depletion, depreciation and amortization |
|
|
227,328 |
|
|
|
154,739 |
|
|
|
114,364 |
|
Exploration dry hole costs |
|
|
15,149 |
|
|
|
15,089 |
|
|
|
6,559 |
|
Mark-to-market on oil and gas derivatives not designated as hedges |
|
|
78,769 |
|
|
|
(86,491 |
) |
|
|
(10,868 |
) |
Unrealized derivative losses (gain) |
|
|
820 |
|
|
|
(5,654 |
) |
|
|
3,505 |
|
Allowance for bad debts |
|
|
|
|
|
|
80 |
|
|
|
675 |
|
Amortization of deferred financing costs and other |
|
|
2,277 |
|
|
|
1,827 |
|
|
|
1,662 |
|
Deferred and
stock-based compensation |
|
|
54,152 |
|
|
|
27,455 |
|
|
|
37,391 |
|
Losses (gain) on sale of assets and other |
|
|
2,212 |
|
|
|
940 |
|
|
|
(512 |
) |
Changes in working capital, net of amounts from business acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(50,570 |
) |
|
|
30,185 |
|
|
|
(64,333 |
) |
Inventory and other |
|
|
(1,040 |
) |
|
|
(1,157 |
) |
|
|
(3,452 |
) |
Accounts payable |
|
|
28,640 |
|
|
|
(5,049 |
) |
|
|
27,472 |
|
Accrued liabilities and other |
|
|
9,922 |
|
|
|
(3,696 |
) |
|
|
1,219 |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided from continuing operations |
|
|
632,102 |
|
|
|
441,509 |
|
|
|
288,596 |
|
Net cash provided from discontinued operations |
|
|
10,189 |
|
|
|
38,366 |
|
|
|
37,149 |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided from operating activities |
|
|
642,291 |
|
|
|
479,875 |
|
|
|
325,745 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Additions to oil and gas properties |
|
|
(782,398 |
) |
|
|
(487,245 |
) |
|
|
(266,396 |
) |
Additions to field service assets |
|
|
(26,044 |
) |
|
|
(14,449 |
) |
|
|
(11,310 |
) |
Acquisitions, net of cash acquired |
|
|
(336,453 |
) |
|
|
(360,149 |
) |
|
|
(153,600 |
) |
Investing activities of discontinued operations |
|
|
(7,375 |
) |
|
|
(29,195 |
) |
|
|
(10,511 |
) |
Investment in equity method investment and other assets |
|
|
(94,630 |
) |
|
|
(21,009 |
) |
|
|
|
|
Proceeds from disposal of assets and discontinued operations |
|
|
234,332 |
|
|
|
388 |
|
|
|
9,440 |
|
Purchases of marketable securities held by the deferred compensation plan |
|
|
(48,018 |
) |
|
|
|
|
|
|
|
|
Proceeds from the sales of marketable securities held by the deferred
compensation plan |
|
|
40,014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(1,020,572 |
) |
|
|
(911,659 |
) |
|
|
(432,377 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings on credit facilities |
|
|
864,500 |
|
|
|
802,500 |
|
|
|
299,000 |
|
Repayments on credit facilities |
|
|
(1,013,000 |
) |
|
|
(619,700 |
) |
|
|
(453,700 |
) |
Issuance of subordinated notes |
|
|
250,000 |
|
|
|
249,500 |
|
|
|
150,000 |
|
Dividends paid common stock |
|
|
(19,082 |
) |
|
|
(12,189 |
) |
|
|
(7,614 |
) |
preferred stock |
|
|
|
|
|
|
|
|
|
|
(2,213 |
) |
Debt issuance costs |
|
|
(3,686 |
) |
|
|
(6,960 |
) |
|
|
(4,119 |
) |
Issuance of common stock |
|
|
296,229 |
|
|
|
16,265 |
|
|
|
114,470 |
|
Other debt repayments/financing |
|
|
3,877 |
|
|
|
|
|
|
|
(16 |
) |
Proceeds from the sales of common stock held by the deferred compensation
plan |
|
|
6,505 |
|
|
|
|
|
|
|
|
|
Purchases of common stock held by the deferred compensation plan and
other treasury stock purchases |
|
|
(5,426 |
) |
|
|
|
|
|
|
(2,808 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash provided from financing activities |
|
|
379,917 |
|
|
|
429,416 |
|
|
|
93,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and equivalents |
|
|
1,636 |
|
|
|
(2,368 |
) |
|
|
(13,632 |
) |
Cash and equivalents at beginning of year |
|
|
2,382 |
|
|
|
4,750 |
|
|
|
18,382 |
|
|
|
|
|
|
|
|
|
|
|
Cash and equivalents at end of year |
|
$ |
4,018 |
|
|
$ |
2,382 |
|
|
$ |
4,750 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
F-7
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
Common stock |
|
Treasury |
|
Additional |
|
Retained |
|
|
|
|
|
other |
|
|
|
|
|
|
|
|
Par |
|
common |
|
paid-in |
|
earnings |
|
Deferred |
|
comprehensive |
|
|
|
|
Shares |
|
value |
|
stock |
|
capital |
|
(deficit) |
|
compensation |
|
(loss)
income |
|
Total |
Balance |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2004 |
|
|
121,829 |
|
|
$ |
1,218 |
|
|
$ |
|
|
|
$ |
699,277 |
|
|
$ |
(89,597 |
) |
|
$ |
(1,257 |
) |
|
$ |
(43,301 |
) |
|
$ |
566,340 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock |
|
|
8,084 |
|
|
|
81 |
|
|
|
|
|
|
|
124,929 |
|
|
|
|
|
|
|
(3,378 |
) |
|
|
|
|
|
|
121,632 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation
expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,461 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,461 |
|
Common dividends declared
($0.0599 per share) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,614 |
) |
|
|
|
|
|
|
|
|
|
|
(7,614 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury stock purchases |
|
|
|
|
|
|
|
|
|
|
(2,808 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,808 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury stock issuances |
|
|
|
|
|
|
|
|
|
|
2,727 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,727 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(103,826 |
) |
|
|
(103,826 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
111,011 |
|
|
|
|
|
|
|
|
|
|
|
111,011 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2005 |
|
|
129,913 |
|
|
|
1,299 |
|
|
|
(81 |
) |
|
|
833,667 |
|
|
|
13,800 |
|
|
|
(4,635 |
) |
|
|
(147,127 |
) |
|
|
696,923 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock |
|
|
9,018 |
|
|
|
90 |
|
|
|
|
|
|
|
203,280 |
|
|
|
|
|
|
|
4,635 |
|
|
|
|
|
|
|
208,005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation
expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,991 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,991 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common dividends declared
($0.09 per share) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,189 |
) |
|
|
|
|
|
|
|
|
|
|
(12,189 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury stock issuances |
|
|
|
|
|
|
|
|
|
|
81 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
81 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive gain |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
183,648 |
|
|
|
183,648 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
158,702 |
|
|
|
|
|
|
|
|
|
|
|
158,702 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006 |
|
|
138,931 |
|
|
|
1,389 |
|
|
|
|
|
|
|
1,057,938 |
|
|
|
160,313 |
|
|
|
|
|
|
|
36,521 |
|
|
|
1,256,161 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock |
|
|
10,736 |
|
|
|
108 |
|
|
|
|
|
|
|
312,427 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
312,535 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation
expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,519 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,519 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common dividends declared
($0.13 per share) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(19,082 |
) |
|
|
|
|
|
|
|
|
|
|
(19,082 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury stock purchases |
|
|
|
|
|
|
|
|
|
|
(5,334 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,334 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(63,346 |
) |
|
|
(63,346 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
230,569 |
|
|
|
|
|
|
|
|
|
|
|
230,569 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007 |
|
|
149,667 |
|
|
$ |
1,497 |
|
|
$ |
(5,334 |
) |
|
$ |
1,386,884 |
|
|
$ |
371,800 |
|
|
$ |
|
|
|
$ |
(26,825 |
) |
|
$ |
1,728,022 |
|
|
|
|
See accompanying notes.
F-8
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Net income |
|
$ |
230,569 |
|
|
$ |
158,702 |
|
|
$ |
111,011 |
|
Net deferred hedging (losses) gains, net of tax: |
|
|
|
|
|
|
|
|
|
|
|
|
Contract settlements reclassified to income |
|
|
(3,231 |
) |
|
|
60,764 |
|
|
|
109,887 |
|
Change in unrealized deferred hedging gains (losses) |
|
|
(54,954 |
) |
|
|
120,832 |
|
|
|
(215,026 |
) |
Change in unrealized (losses) gains on securities held by
deferred compensation plan, net of taxes |
|
|
(5,161 |
) |
|
|
2,052 |
|
|
|
1,313 |
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
$ |
167,223 |
|
|
$ |
342,350 |
|
|
$ |
7,185 |
|
|
|
|
|
|
|
|
|
|
|
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 engaged in the exploration,
development and acquisition of oil and gas properties primarily in the Southwestern, Appalachian
and Gulf Coast regions of the United States. We seek to increase our reserves and production
primarily through drilling and complementary acquisitions. Range is a Delaware corporation whose
common stock is traded on the New York Stock Exchange.
(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 other revenues on our
consolidated statement of operations. All material intercompany balances and transactions have
been eliminated.
During the first quarter of 2007, we sold our interests in our Austin Chalk properties that we
purchased as part of the Stroud acquisition. We also sold our Gulf of Mexico properties at the end
of the first quarter of 2007. In accordance with Financial Accounting Standards Board (FASB),
Statement of Financial Accounting Standards (SFAS) No. 144, Accounting for the Impairment of
Disposal of Long-Lived Assets, we have reflected the results of operations of the above
divestitures as discontinued operations, rather than a component of continuing operations. The
Austin Chalk properties were classified as assets held for sale since their purchase in 2006. All
periods presented include the reclassification of our Gulf of Mexico operations as discontinued
operations. See also Note 4 for additional information regarding discontinued operations.
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 at
year-end, the reported amounts of revenues and expenses during the year and the reported amount of
proved oil and gas reserves. Actual results could differ from the estimates and assumptions used.
Income per Common Share
Basic net income per share is calculated based on the weighted average number of common shares
outstanding. Diluted net income per share assumes issuance of stock compensation awards, provided
the effect is not antidilutive. All common stock shares and per share amounts in the accompanying
financial statements have been adjusted for the three-for-two stock split effected on December 2,
2005.
Business Segment Information
SFAS No. 131, Disclosure about Segments of an Enterprise and Related Information,
establishes standards for reporting information about operating segments. 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 decision maker for the purpose of allocating
resources and assessing performance.
Segment reporting is not applicable to us as 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 or
segments.
F-10
Revenue Recognition and Gas Imbalances
Oil, gas and natural gas liquids revenues are recognized when the products are sold and
delivery to the purchaser has occurred. Although receivables are concentrated in the oil and gas
industry, we do not view this as 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 $583,400 at December 31, 2007 compared to $745,900 at December 31, 2006.
We use the sales method to account for gas imbalances, recognizing revenue based on gas
delivered rather than our working interest share of the gas produced. A liability is recognized
when the imbalance exceeds the estimate of remaining reserves. Gas imbalances at December 31, 2007
and December 31, 2006 were not significant. At December 31, 2007, we had recorded a net liability
of $533,000 for those wells where it was determined that there were insufficient reserves to
recover the imbalance situation.
Cash and 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.
Marketable Securities
Holdings of equity securities held in our deferred compensation plans qualify as
available-for-sale or trading and are recorded at fair value. Investments in the deferred
compensation plans are in mutual funds. As of December 31, 2007, there was an unrealized loss of
$2.0 million (pre-tax) in accumulated other comprehensive loss related to these investments.
Inventories
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 value.
Oil and Gas Properties
We follow the successful efforts method of accounting for oil and gas 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. Costs resulting in exploratory discoveries and
all development costs, whether successful or not, are capitalized. Oil and NGLs are converted to
gas equivalent basis or mcfe at the rate of one barrel equals 6 mcf. The depletion, depreciation
and amortization (DD&A) rates were $1.95 per mcfe in 2007 compared to $1.62 per mcfe in 2006 and
$1.41 per mcfe in 2005. Depletion is provided on the units of production method. Unproved
properties had a net book value of $271.4 million at December 31, 2007 compared to $226.2 million
at December 31, 2006 and $28.5 million at December 31, 2005. The increase in unproved properties
from 2005 to 2006 is primarily related to our Stroud acquisition completed in 2006. Unproved
properties are reviewed quarterly for impairment and impaired if conditions indicate we will not
explore the acreage before expiration or the carrying value is above fair value.
Our long-lived assets are reviewed for impairment periodically for events or changes in
circumstances that indicate that the carrying amount of an asset may not be recoverable.
Long-lived assets 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. 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 proved reserves. Expected future cash inflow from the sale of production of reserves is
calculated based on estimated future prices and estimated operating costs. We estimate prices
based upon market related information including published futures prices. The estimated future
level of production is based on assumptions surrounding future levels of prices and costs, field
decline rates, market demand and supply, and the economic and regulatory climates. 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) and the carrying value of the asset. In the fourth quarter of 2006, we lowered our salvage
value estimates on our Appalachia wells which increased DD&A expense by $4.6 million.
Proceeds from the disposal of miscellaneous properties are credited to the net book value of their
amortization group with no immediate effect on income. However, gain or loss is recognized from
the sale of less than an entire amortization group if the disposition is significant enough to
materially impact the depletion rate of the remaining properties in the amortization base.
F-11
Transportation and Field Assets
Our gas transportation and gathering systems are generally located in proximity to certain of
our principal fields. Depreciation on these systems is provided on the straight-line method based
on estimated useful lives of 10 to 15 years. We receive third-party income for providing certain
transportation and field services which is recognized as earned. Depreciation on the associated
assets is calculated on the straight-line method based on estimated useful lives ranging from five
to seven years. Buildings are depreciated over 10 to 15 years. Depreciation expense was $10.9
million in 2007 compared to $7.5 million in 2006 and $6.4 million in 2005.
Other Assets
The expenses of issuing debt are capitalized and included in other assets on our consolidated
balance sheet. These costs are amortized over the expected life of the related instruments. When
a security is retired before maturity or modifications significantly change the cash flows, related
unamortized costs are expensed. Other assets at December 31, 2007 include $15.3 million of
unamortized debt issuance costs, $51.5 million of marketable securities held in our deferred
compensation plans and $7.7 million of other investments.
Stock-based Compensation
The 2005 Equity Based Compensation Plan (the 2005 Plan) authorizes the Compensation
Committee of the Board of Directors to grant stock options, stock appreciation rights, restricted
stock awards, and phantom stock rights to employees. The Non-Employee Director Stock Plan (the
Director Plan) allows grants to our non-employee directors of our Board of Directors. The 2005
Plan was approved by shareholders in May 2005 and replaces our 1999 stock option plan. No new
grants will be 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 (15.0 million less the 2.2 million shares issued
under the 1999 Stock Options Plan prior to May 18, 2005, the effective date of the 2005 Plan and
less the 7.2 million shares issuable pursuant to awards under the 1999 Stock Option Plan
outstanding as of the effective date of the 2005 Plan) 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. The Director Plan was approved by stockholders in May
2004 and no more than 300,000 shares of common stock may be issued under the Plan.
Stock options represent the right to purchase shares of stock in the future at the fair market
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 are granted. Similar to
stock options, stock appreciation rights (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.
The Compensation Committee grants restricted stock to certain employees and to 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. All restricted shares that are granted are placed in the deferred compensation plan. See
additional information in Note 12.
Before January 1, 2006, we accounted for stock options granted under our stock-based compensation
plans under the recognition and measurement provisions of APB Opinion No. 25, Accounting for Stock
Issued to Employees and related Interpretations, as permitted by SFAS No. 123, Accounting for
Stock-Based Compensation. For our stock options, no stock-based compensation expense was
recognized in our statements of operations prior to January 1, 2006, as all stock options granted
had an exercise price equal to the market value of the underlying common stock on the date of
grant. Effective January 1, 2006, we adopted the fair value recognition provisions of SFAS No.
123(R), Share-Based Payment, using the modified prospective transition method. Under this
transition method, compensation cost for stock options and stock appreciation rights recognized in
2006 includes (a) compensation cost ($11.2 million) for all stock-based payments granted prior to,
but not yet vested as of December 31, 2005, based on the remaining service period and the grant
date fair value estimated in accordance with the original provisions of Statement No. 123 and (b)
compensation cost ($3.7 million) for all stock-based payments granted after December 31, 2005,
based on the service period (on a straight line basis) and the grant-date fair value estimated in
accordance with SFAS No. 123(R). Pursuant to SFAS No. 123(R), results for prior periods have not
been restated. In 2006, stockbased compensation has been allocated to direct operating expense
($1.4 million), exploration expense ($2.5 million) and general and administrative expense ($10.7
million) to align SFAS No. 123(R) expense with the employees cash compensation. In 2007,
stock-based compensation has been allocated to direct operating expense ($1.8 million), exploration
expense ($2.3 million) and general and administrative expense ($10.8 million). 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.S.CONT
F-12
We also began granting stock-settled SARs in July 2005 as part of our stock-based compensation
plans to reduce the dilutive impact of our equity plans. Before January 1, 2006, we accounted for
SARs grants under the recognition and measurement provisions of APB Opinion No. 25, which required
expense to be recognized equal to the amount by which the quoted market value exceeded the original
grant price on a mark-to-market basis. Therefore, we recognized $5.8 million of compensation cost
in the last six months of 2005 related to SARs. To present stock-based compensation expense on a
consistent basis, the $5.8 million of 2005 SARs related expense has been allocated to direct
operating expense ($480,000), exploration expense ($1.2 million), general and administrative
expense ($4.0 million) and a $117,000 reduction to transportation and gathering revenues.
Beginning January 1, 2006, as required under the provisions of SFAS No. 123(R), those SARs granted
prior to, but not yet vested as of December 31, 2005, are being expensed over the service period
based on grant date fair value estimated in accordance with the original provisions of SFAS No. 123
and all SARs granted after to December 31, 2005 are being expensed over the service period (on a
straight-line basis) based on grant-date fair value estimated in accordance with SFAS No. 123(R).
As a result of adopting SFAS No. 123(R) on January 1, 2006, our income from continuing
operations before income taxes and net income for 2006 is $18.2 million and $11.5 million lower,
respectively, than if we had continued to account for stock-based compensation under APB Opinion
No. 25. The following table illustrates the effect on net income and earnings per share if we had
applied the fair value recognition provisions of SFAS No. 123(R) to options and SARs granted under
our stock-based compensation plans in 2005. For the purposes of this pro forma disclosure, the
value is estimated using a Black-Scholes-Merton option-pricing formula and expensed over the
options vesting periods (in thousands, except per share data).
|
|
|
|
|
|
|
Year Ended |
|
|
|
December 31, |
|
|
|
2005 |
|
Net income, as reported |
|
$ |
111,011 |
|
Add: Total stock-based employee compensation expense
included in net income, net of tax |
|
|
23,556 |
|
|
|
|
|
|
Deduct: Total stock-based employee compensation
expense determined under fair value
based method, net of tax |
|
|
(29,235 |
) |
|
|
|
|
|
|
|
|
|
Pro forma net income |
|
$ |
105,332 |
|
|
|
|
|
|
|
|
|
|
Earnings per share: |
|
|
|
|
Basic as reported |
|
$ |
0.89 |
|
Basic pro forma |
|
|
0.85 |
|
Diluted as reported |
|
|
0.86 |
|
Diluted pro forma |
|
|
0.82 |
|
As required, the pro forma disclosures above included options and SARs granted since January
1, 1995. For purposes of pro forma disclosures, the estimated fair value is amortized to expense
over the vesting period. For options with graded vesting, expense is recognized on a straight-line
basis over the vesting period. The fair value of each option grant on the date of grant for the
disclosures is estimated by using the Black-Scholes-Merton option pricing model with the following
weighted-average assumptions used for 2005: fair value of $8.48 per share; expected dividend per
share of $0.08; expected historical volatility factors of 54%; risk-free interest rates of 4.1%,
and an average expected life of 5 years.
Derivative Financial Instruments and Hedging
We account for our derivative activities under the provisions of SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities, as amended by SFAS Nos. 137, 138 and 149. The
statement, as amended, establishes accounting and reporting standards requiring that every
derivative instrument be recorded on the balance sheet as either an asset or a liability measured
at its fair value. The statement requires that changes in the derivatives fair value be
recognized currently in earnings unless specific hedge accounting criteria are met. All of the
derivative instruments that we use are to manage the price risk attributable to our expected oil
and gas production. Cash flows from oil and gas derivative contract settlements are reflected in
operating activities in our statement of cash flows.
F-13
Historically, we applied hedge accounting to derivatives used to manage price risk associated
with our oil and gas production. Accordingly, we recorded changes in the fair value of our swap
and collar contracts, including changes associated with time value, under the caption Accumulated
other comprehensive income (loss) on our consolidated balance sheet. Gains or losses on these
swap and collar contracts are reclassified out of Accumulated other comprehensive income (loss)
and into oil and gas sales when the forecasted sale of production occurred. Any hedge
ineffectiveness associated with contracts qualifying for and designated as a cash flow hedge (which
represents the amount by which the change in the fair value of the derivative differs from the
change in the cash flows of the forecasted sale of production) is reported currently each period
under the caption Derivative fair value income (loss) in our consolidated statement of
operations.
Some of our derivatives do not qualify for hedge accounting but are effective as economic
hedges of our commodity price exposure. These contracts are accounted for using the mark-to-market
accounting method. Under this method, the contracts are carried at their fair value on our
consolidated balance sheet under the captions Unrealized derivative gains and Unrealized
derivative losses. We recognize all unrealized and realized gains and losses related to these
contracts in our consolidated statement of operations under the caption Derivative fair value
income (loss).
As of the fourth quarter of 2005, certain of our gas derivatives no longer qualified for hedge
accounting due to the effect of volatility of gas prices on the correlation between realized prices
and hedge reference prices. Also, as a result of the sale of our Gulf of Mexico assets in the
first quarter of 2007, the portion of derivatives which were designated to our Gulf Coast
production no longer qualified for hedge accounting resulting in derivative fair value income of
$209,000. In the fourth quarter of 2007, we began marking a portion of our oil hedges designated
as Permian Basin production to market due to the anticipated sale of a portion of our Permian
properties resulting in derivative fair value loss of $14.7 million. See also Note 17.
Derivatives that no longer qualify for hedge accounting under SFAS No. 133 are accounted for using
the mark-to-market accounting method described above.
During the third and fourth quarter of 2007, we entered into basis swap agreements which do
not qualify as hedges for hedge accounting and are also marked to market. The price we receive for
our gas production can be less than the NYMEX price because of adjustments for delivery location,
or basis, relative quality and other factors; therefore, we have entered into basis swap agreement
that effectively fix our basis adjustments.
Asset Retirement Obligations
The fair values of asset retirement obligations are 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 oil and gas 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 in plugging and abandoning wells,
estimated remaining lives of those wells based on reserve estimates, external estimates as to the
cost to plug and abandon the wells in the future and federal and state regulatory requirements.
Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations
are recorded over time. The depreciation will generally be determined on a units-of-production
basis while accretion to be recognized will escalate over the life of the producing assets. We do
not provide for a market risk premium associated with asset retirement obligations because a
reliable estimate cannot be determined.
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.
The realization of deferred tax assets is assessed periodically based on several interrelated
factors. These factors include our expectation to generate sufficient taxable income including tax
credits and operating loss carryforwards.
Accumulated Other Comprehensive Income (Loss)
We follow the provisions of SFAS No. 130, Reporting Comprehensive Income which establishes
standards for reporting comprehensive income. Comprehensive income includes net income as well as
all changes in equity during the period, except those resulting from investments and distributions
to owners. At December 31, 2007, we had a $41.1 million pre-tax loss in OCI relating to unrealized
commodity hedges. We also had a pre-tax loss of $2.0 million relating to our marketable securities
held in our deferred compensation plans.
F-14
The components of accumulated other comprehensive income (loss) and related tax effects
for three years ended December 31, 2007, were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross |
|
|
Tax Effect |
|
|
Net of Tax |
|
Accumulated other comprehensive loss at December 31, 2004 |
|
$ |
(69,231 |
) |
|
$ |
25,930 |
|
|
$ |
(43,301 |
) |
Contract settlements reclassified to income |
|
|
174,041 |
|
|
|
(64,154 |
) |
|
|
109,887 |
|
Change in unrealized deferred hedging losses |
|
|
(341,222 |
) |
|
|
126,196 |
|
|
|
(215,026 |
) |
Change in unrealized gains (losses) on
securities held by deferred compensation plan |
|
|
2,049 |
|
|
|
(736 |
) |
|
|
1,313 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive loss at December 31, 2005 |
|
|
(234,363 |
) |
|
|
87,236 |
|
|
|
(147,127 |
) |
Contract settlements reclassified to income |
|
|
96,450 |
|
|
|
(35,686 |
) |
|
|
60,764 |
|
Change in unrealized deferred hedging gains |
|
|
192,183 |
|
|
|
(71,351 |
) |
|
|
120,832 |
|
Change in unrealized gains (losses) on
securities held by deferred compensation plan |
|
|
3,203 |
|
|
|
(1,151 |
) |
|
|
2,052 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income at December 31, 2006 |
|
|
57,473 |
|
|
|
(20,952 |
) |
|
|
36,521 |
|
Contract settlements reclassified to income |
|
|
(5,129 |
) |
|
|
1,898 |
|
|
|
(3,231 |
) |
Change in unrealized deferred hedging gains |
|
|
(87,228 |
) |
|
|
32,274 |
|
|
|
(54,954 |
) |
Change in unrealized gains (losses) on securities held by
deferred compensation plan |
|
|
(8,194 |
) |
|
|
3,033 |
|
|
|
(5,161 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive loss at December 31, 2007 |
|
$ |
(43,078 |
) |
|
$ |
16,253 |
|
|
$ |
(26,825 |
) |
|
|
|
|
|
|
|
|
|
|
Reclassifications
Certain reclassifications of prior years data have been made to conform to our current year
classification. This includes the presentation of our Gulf of Mexico operations as discontinued
operations, the reclassification of gains of $49.9 million in
2006 and $2.9 million in 2005 related to settled derivatives that do not qualify for hedge accounting
from oil and gas sales to derivative fair value income (loss) and the
reclassification of gains of $6.0 million in 2006 and a loss of
$3.5 million in 2005 related to hedge ineffectiveness from
other revenue to derivative fair value income (loss). These reclassifications did not impact our net income,
stockholders equity or cash flows. See also Note 12 for further discussion of reclassifications
related to our deferred compensation plan.
Accounting Pronouncements Implemented
In July 2006, the FASB issued FASB Interpretation (FIN) 48, Accounting for Uncertainty in
Income Taxes An Interpretation of FASB Statement No. 109. FIN No. 48 clarifies the accounting
for uncertainty in income taxes recognized in an enterprises financial statements in accordance
with SFAS No. 109, Accounting for Income Taxes. FIN No. 48 prescribes a recognition threshold
and measurement attribute for the financial statement recognition and measurement of a tax position
taken or expected to be taken in a tax return. The new standard also provides guidance on
derecognition, classification, interest and penalties, accounting in interim periods, transition
and disclosure. We adopted FIN No. 48 effective January 1, 2007, and adoption did not have a
significant effect on its consolidated results of operations, financial position or cash flows.
See Note 5 for other disclosures required by FIN No. 48.
Accounting Pronouncements Not Yet Adopted
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This statement
defines fair value, establishes a framework for measuring fair value in generally accepted
accounting principles and expands disclosures about fair value measurements. SFAS No. 157 does not
require any new fair value measurements but may require some entities to change their measurement
practices. For Range, SFAS No. 157 will be effective January 1, 2008. We have not yet determined
whether SFAS No. 157 will have a material impact on our financial condition, results of operations
or cash flow. However, we believe we will be required to provide additional disclosures as part of
future financial statements, beginning with the first quarter 2008.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets
and Financial Liabilities. This statement permits entities to choose to measure many financial
instruments and certain other items at fair value that are not currently required to be measured at
fair value. It requires that unrealized gains and losses on items for which the fair value option
has
been elected be recorded in net income. The statement also establishes presentation and disclosure
requirements designed to facilitate comparison between entities that choose different measurement
attributes for similar types of assets and liabilities. For us, SFAS No.
F-15
159 will be
effective January 1, 2008, and retrospective application is not permitted. Should we elect to
apply the fair value option to any eligible items that exist at January 1, 2008, the effect of the
first remeasurement to fair value would be reported as a cumulative effect adjustment to the
opening balance of retained earnings. We will adopt SFAS No. 159 as
of January 1, 2008 and the impact of the adoption will result in
a reclassification of a $2.0 million pre-tax loss related to our
investment securities from accumulated other
comprehensive loss to retained earnings.
In December 2007, the FASB issued SFAS No. 141(R), Business Combinations. SFAS No. 141(R)
replaces SFAS No. 141. The statement retains the purchase method of accounting for acquisitions,
but requires a number of changes, including changes in the way assets and liabilities are
recognized in the purchase accounting. It changes the recognition of assets acquired and
liabilities assumed arising from contingencies, requires the capitalization of in-process research
and development at fair value, and requires the expensing of acquisition-related costs as incurred.
The statement will apply prospectively to business combinations occurring in our fiscal year
beginning January 1, 2009. We are currently evaluating the provisions of this statement.
(3) ACQUISITIONS AND DISPOSITIONS
Acquisitions
Acquisitions are accounted for as purchases, and accordingly, the results of operations are
included in our statement of operations 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. Acquisitions have been funded with internal cash flow, bank borrowings
and the issuance of debt and equity securities.
In May 2007, we acquired additional interests in the Nora field of Virginia and entered into a
joint development plan with Equitable Resources, Inc. (Equitable). As a result of this
transaction, Equitable and Range equalized their working interests in the Nora field, including
producing wells, undrilled acreage and gathering systems. Range retained its separately owned
royalty interest in the Nora field. Equitable will operate the producing wells, manage the
drilling operations of all future coal bed methane wells and the gathering system. Range will
oversee the drilling of formations below the coal bed methane formations, including tight gas,
shale and deeper formations. A newly formed limited liability corporation will hold the investment
in the gathering system which is owned 50% by Equitable and 50% by Range. All business decisions
require the unanimous consent of both parties. The gathering system investment is accounted for as
an equity method investment. Including estimated transaction costs, we paid $281.8 million which
includes $190.2 million allocated to oil and gas properties, $94.7 million allocated to our equity
method investment and a $3.1 million asset retirement obligation. In December 2007, we paid an
additional $7.1 million for interests in the same field. No pro forma information has been
provided as the acquisition was not considered significant.
Our purchases in 2006 included the acquisition in June of Stroud Energy, Inc. (Stroud), a
private oil and gas company with operations in the Barnett Shale in North Texas, the Cotton Valley
in East Texas and the Austin Chalk in Central Texas. To acquire Stroud, we paid $171.5 million of
cash (including transaction costs) and issued 6.5 million shares of our common stock. The cash
portion of the acquisition was funded with borrowings under our bank facility. We also assumed
$106.7 million of Strouds debt which was retired with borrowings under our bank facility. The
fair value of consideration issued was based on the average of our stock price for the five day
period before and after May 11, 2006, the date the acquisition was announced. See also Note 4 for
discussion of assets held for sale and discontinued operations.
The following table summarizes the final purchase price allocation of fair value of assets
acquired and liabilities assumed at closing (in thousands):
|
|
|
|
|
Purchase price: |
|
|
|
|
Cash paid (including transaction costs) |
|
$ |
171,529 |
|
6.5 million shares of common stock (at fair value of $27.26
per share) |
|
|
177,641 |
|
Stock options assumed (652,000 options) |
|
|
9,478 |
|
Debt retired |
|
|
106,700 |
|
|
|
|
|
Total |
|
$ |
465,348 |
|
|
|
|
|
|
|
|
|
|
Allocation of purchase price: |
|
|
|
|
Working capital deficit |
|
$ |
(13,557 |
) |
Other long-term assets |
|
|
55 |
|
Oil and gas properties |
|
|
487,345 |
|
Assets held for sale |
|
|
140,000 |
|
Deferred income taxes |
|
|
(147,062 |
) |
Asset retirement obligations |
|
|
(1,433 |
) |
|
|
|
|
Total |
|
$ |
465,348 |
|
|
|
|
|
F-16
Pro forma
The following unaudited pro forma data include the results of operations as if the Stroud
acquisition had been consummated at the beginning of 2005. The pro forma information for 2005,
which is based on the historical results of Stroud, includes two material non-recurring amounts
recognized by Stroud not directly related to the transaction and not expected to reoccur. The year
ended December 31, 2005 pro forma information includes an $18.4 million pre-tax stock compensation
expense related to restricted and unrestricted shares issued to Stroud management and employees and
a pre-tax $6.2 million loss on repurchase of mandatorily redeemable preferred units. The pro forma
data is based on historical information and does not necessarily reflect the actual results that
would have occurred nor are they necessarily indicative of future results of operations (in
thousands, except per share data).
|
|
|
|
|
|
|
|
|
|
|
Year Ended |
|
|
December 31, |
|
|
2006 |
|
2005 |
Revenues |
|
$ |
779,487 |
|
|
$ |
526,491 |
|
Income from continuing operations |
|
$ |
315,220 |
|
|
$ |
132,039 |
|
Net income |
|
$ |
161,998 |
|
|
$ |
95,086 |
|
|
|
|
|
|
|
|
|
|
Per share data: |
|
|
|
|
|
|
|
|
Income from continuing operations-basic |
|
$ |
1.41 |
|
|
$ |
0.63 |
|
Income from continuing operations-diluted |
|
$ |
1.36 |
|
|
$ |
0.60 |
|
|
|
|
|
|
|
|
|
|
Net income basic |
|
$ |
1.18 |
|
|
$ |
0.73 |
|
Net income diluted |
|
$ |
1.14 |
|
|
$ |
0.70 |
|
Dispositions
In February 2007, we sold the Stroud Austin Chalk properties for proceeds of $80.4 million and
recorded a loss on the sale of $2.3 million. These properties were acquired in 2006 as part of our
Stroud acquisition and were classified as assets held for sale on the acquisition date. In March
2007, we sold our Gulf of Mexico properties for proceeds of $155.0 million and recorded a gain on
the sale of $95.1 million. The sale included properties within the waters of the Gulf of Mexico
(either state or federal). We have reflected the results of operations of the above divestitures
as discontinued operations rather than a component of continuing operations for 2007 and all prior
years. See Note 4 for additional information.
F-17
(4) DISCONTINUED OPERATIONS
As part of the Stroud acquisition (also see discussion in Note 3), we purchased Austin Chalk
properties in Central Texas which were sold in February 2007 for proceeds of $80.4 million. We
originally allocated $140.0 million to these properties as part of the purchase price allocation.
However, after the acquisition, natural gas prices started to decline. As a result, during 2006 we
recognized impairment expense of $74.9 million. In March 2007, we also sold our Gulf of Mexico
properties for proceeds of $155.0 million. All prior year periods include the reclassification of
our Gulf of Mexico operations to discontinued operations. Discontinued operations for the years
ended December 31, 2007, 2006 and 2005 are summarized as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales (a) |
|
$ |
15,187 |
|
|
$ |
54,192 |
|
|
$ |
26,698 |
|
Transportation and gathering |
|
|
10 |
|
|
|
85 |
|
|
|
155 |
|
Other |
|
|
310 |
|
|
|
(19 |
) |
|
|
(116 |
) |
Gain on disposition of assets |
|
|
92,757 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
108,264 |
|
|
|
54,258 |
|
|
|
26,737 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating |
|
|
2,559 |
|
|
|
12,201 |
|
|
|
9,246 |
|
Production and ad valorem taxes |
|
|
141 |
|
|
|
1,065 |
|
|
|
694 |
|
Exploration and other |
|
|
215 |
|
|
|
2,400 |
|
|
|
1,075 |
|
Interest expense (b) |
|
|
845 |
|
|
|
3,232 |
|
|
|
1,178 |
|
Depletion, depreciation and amortization |
|
|
6,672 |
|
|
|
14,953 |
|
|
|
13,150 |
|
Impairment (c) |
|
|
|
|
|
|
74,910 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
10,432 |
|
|
|
108,761 |
|
|
|
25,343 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from discontinued operations before income taxes |
|
|
97,832 |
|
|
|
(54,503 |
) |
|
|
1,394 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit) |
|
|
34,239 |
|
|
|
(19,256 |
) |
|
|
488 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from discontinued operations, net of taxes |
|
$ |
63,593 |
|
|
$ |
(35,247 |
) |
|
$ |
906 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls) |
|
|
40,634 |
|
|
|
139,189 |
|
|
|
102,455 |
|
Natural gas (mcf) |
|
|
1,990,277 |
|
|
|
7,927,557 |
|
|
|
5,394,784 |
|
Total (mcfe) (d) |
|
|
2,234,081 |
|
|
|
8,762,691 |
|
|
|
6,009,514 |
|
|
|
|
a) |
|
Realized hedging gains and losses for the Gulf of Mexico properties have been
allocated to discontinued operations based on the designated hedge values for those assets. |
|
b) |
|
Interest expense is allocated to discontinued operations for our Austin Chalk
properties based on the debt incurred at the time of the acquisition and for the Gulf of
Mexico properties, interest expense was allocated based upon the ratio of the Gulf of Mexico
properties to our total oil and gas properties at December 31, 2006. |
|
c) |
|
Impairment expenses for the Austin Chalk properties includes losses in fair value
resulting from lower oil and gas prices and amortization of the carrying value for volumes
produced since the acquisition date. |
|
d) |
|
Oil is converted to mcfe at the rate of one barrel equals six mcfe. |
(5) INCOME TAXES
Our income tax expense from continuing operations was $98.8 million for the year ended
December 31, 2007 compared to $121.8 million in 2006 and $65.9 million in 2005. A reconciliation
between the statutory federal income tax rate and our effective income tax rate is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Federal statutory tax rate |
|
|
35 |
% |
|
|
35 |
% |
|
|
35 |
% |
State |
|
|
3 |
|
|
|
4 |
|
|
|
2 |
|
Texas Margin tax credit |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated effective tax rate |
|
|
37 |
% |
|
|
39 |
% |
|
|
37 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes (refunded) paid (in thousands) |
|
$ |
(571 |
) |
|
$ |
1,973 |
|
|
$ |
615 |
|
|
|
|
|
|
|
|
|
|
|
F-18
Income tax provision (benefit) attributable to income from continuing operations consists of
the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
(in thousands) |
|
Current: |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal |
|
$ |
(129 |
) |
|
$ |
150 |
|
|
$ |
|
|
U.S. state and local |
|
|
449 |
|
|
|
1,762 |
|
|
|
1,071 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
320 |
|
|
$ |
1,912 |
|
|
$ |
1,071 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred: |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal |
|
$ |
94,310 |
|
|
$ |
110,296 |
|
|
$ |
61,279 |
|
U.S. state and local |
|
|
4,131 |
|
|
|
9,544 |
|
|
|
3,530 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
98,441 |
|
|
$ |
119,840 |
|
|
$ |
64,809 |
|
|
|
|
|
|
|
|
|
|
|
Significant components of deferred tax assets and liabilities are as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
|
(in thousands) |
|
Deferred tax assets: |
|
|
|
|
|
|
|
|
Current |
|
|
|
|
|
|
|
|
Current net unrealized loss in OCI |
|
$ |
5,195 |
|
|
$ |
|
|
Deferred compensation |
|
|
3,981 |
|
|
|
|
|
Current portion of SFAS No. 143 liability |
|
|
704 |
|
|
|
|
|
Other |
|
|
2,967 |
|
|
|
|
|
Current portion of net operating loss carryforward |
|
|
14,060 |
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal |
|
|
26,907 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-current |
|
|
|
|
|
|
|
|
Net operating loss carryforward |
|
|
25,675 |
|
|
|
69,141 |
|
Net unrealized loss in OCI |
|
|
11,060 |
|
|
|
|
|
Deferred compensation |
|
|
41,255 |
|
|
|
38,664 |
|
AMT credits and other credits |
|
|
4,546 |
|
|
|
804 |
|
Non-current portion of SFAS No. 143 liability |
|
27,302 |
|
|
20,775 |
|
Other |
|
|
9,046 |
|
|
|
14,671 |
|
Valuation allowance |
|
|
(3,101 |
) |
|
|
(3,101 |
) |
|
|
|
|
|
|
|
Subtotal |
|
|
115,783 |
|
|
|
140,954 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities: |
|
|
|
|
|
|
|
|
Non-current |
|
|
|
|
|
|
|
|
Depreciation, depletion and investments |
|
|
(697,491 |
) |
|
|
(547,899 |
) |
Net unrealized gain in OCI |
|
|
|
|
|
|
(21,264 |
) |
Cumulative ineffectiveness SFAS No. 133 |
|
|
(6,812 |
) |
|
|
(35,788 |
) |
Other |
|
|
(2,266 |
) |
|
|
(4,646 |
) |
|
|
|
|
|
|
|
Subtotal |
|
|
(706,569 |
) |
|
|
(609,597 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability |
|
$ |
(563,879 |
) |
|
$ |
(468,643 |
) |
|
|
|
|
|
|
|
F - 19
At December 31, 2007, deferred tax liabilities exceeded deferred tax assets by $563.9 million,
with $16.3 million of deferred tax assets related to net deferred hedging losses included in OCI.
A portion of our deferred tax assets relate to items which are capital assets, which upon
disposition will result in capital losses. Due to the uncertainty related to the utilization of
the capital loss, a valuation allowance was recognized in the amount of $3.1 million.
At December 31, 2007, we had regular net operating loss (NOL) carryforwards of $204.4
million and alternative minimum tax (AMT) NOL carryforwards of $149.7 million that expire between
2012 and 2027. Our deferred tax asset related to regular NOL carryforwards at December 31, 2007
was $39.7 million, net of the SFAS No. 123(R) reduction for unrealized benefits. Regular NOLs
generally offset taxable income and to such extent, no income tax payments are required. We have
$26.9 million of NOLs generated in years before 1998 which are subject to yearly limitations due to
IRC Section 382. We do not believe the application of the Section 382 limitation hinders our
ability to use such NOLs and therefore, no valuation allowance has been provided. At December 31,
2007, we have AMT credit carryforwards of $777,000 that are not subject to limitation or
expiration.
We file consolidated tax returns in the United States federal jurisdiction and separate income
tax returns in many state jurisdictions. We are subject to U.S. Federal income tax examinations
for the years after 2002 and we are subject to various state tax examinations for years after 2001.
Our continuing 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, 2007. Throughout 2007, our unrecognized tax
benefits were not material.
(6) EARNINGS PER COMMON SHARE
The following table sets forth the computation of basic and diluted earnings per common share
(in thousands, except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Numerator: |
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
$ |
166,976 |
|
|
$ |
193,949 |
|
|
$ |
110,105 |
|
Income (loss) from discontinued operations |
|
|
63,593 |
|
|
|
(35,247 |
) |
|
|
906 |
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
230,569 |
|
|
$ |
158,702 |
|
|
$ |
111,011 |
|
|
|
|
|
|
|
|
|
|
|
|
Denominator: |
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding |
|
|
145,869 |
|
|
|
135,016 |
|
|
|
126,339 |
|
Stock held in deferred compensation plan and treasury shares |
|
|
(2,078 |
) |
|
|
(1,265 |
) |
|
|
(2,209 |
) |
|
|
|
|
|
|
|
|
|
|
Weighted average shares, basic |
|
|
143,791 |
|
|
|
133,751 |
|
|
|
124,130 |
|
|
|
|
|
|
|
|
|
|
|
|
Effect of dilutive securities: |
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding |
|
|
145,869 |
|
|
|
135,016 |
|
|
|
126,339 |
|
Employee
stock options, SARs and stock held in deferred compensation plan |
|
|
4,100 |
|
|
|
3,696 |
|
|
|
2,863 |
|
Treasury shares |
|
|
(58 |
) |
|
|
(1 |
) |
|
|
(76 |
) |
|
|
|
|
|
|
|
|
|
|
Dilutive potential common shares for diluted earnings per share |
|
|
149,911 |
|
|
|
138,711 |
|
|
|
129,126 |
|
|
|
|
|
|
|
|
|
|
|
|
Basic income from continuing operations |
|
$ |
1.16 |
|
|
$ |
1.45 |
|
|
$ |
0.89 |
|
discontinued operations |
|
|
0.44 |
|
|
|
(0.26 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net income |
|
$ |
$1.60 |
|
|
$ |
1.19 |
|
|
$ |
0.89 |
|
|
|
|
|
|
|
|
|
|
|
|
Diluted income from continuing operations |
|
$ |
1.11 |
|
|
$ |
1.39 |
|
|
$ |
0.85 |
|
discontinued operations |
|
|
0.43 |
|
|
|
(0.25 |
) |
|
|
0.01 |
|
|
|
|
|
|
|
|
|
|
|
net income |
|
$ |
1.54 |
|
|
$ |
1.14 |
|
|
$ |
0.86 |
|
|
|
|
|
|
|
|
|
|
|
F - 20
Stock appreciation rights for 345,000 shares were outstanding but not included in the
computations of diluted net income per share for the year ended December 31, 2007 because the
exercise price of the SARs was greater than the average price of the common shares and would be
anti-dilutive to the computations. Stock appreciation rights for 88,500 shares were outstanding
but not included in the computations of diluted net income per share for the year ended December
31, 2006 because the exercise price of the SARs was greater than the average price of the common
shares and would be anti-dilutive to the computations.
(7) SUSPENDED EXPLORATORY WELL COSTS
The following table reflects the changes in capitalized exploratory well costs for the year
ended December 31, 2007, 2006 and 2005 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Balance at beginning of period |
|
$ |
9,984 |
|
|
$ |
25,340 |
|
|
$ |
7,332 |
|
Additions to capitalized exploratory well costs pending the
determination of proved reserves |
|
|
14,428 |
|
|
|
4,695 |
|
|
|
26,915 |
|
Divested wells |
|
|
(1,325 |
) |
|
|
|
|
|
|
|
|
Reclassifications to wells, facilities and equipment based
on determination of proved reserves |
|
|
|
|
|
|
(16,710 |
) |
|
|
(8,614 |
) |
Capitalized exploratory well costs charged to expense |
|
|
(8,034 |
) |
|
|
(3,341 |
) |
|
|
(293 |
) |
|
|
|
|
|
|
|
|
|
|
Balance at end of period |
|
|
15,053 |
|
|
|
9,984 |
|
|
|
25,340 |
|
Less exploratory well costs that have been capitalized for
a period of one year or less |
|
|
(12,067 |
) |
|
|
(4,792 |
) |
|
|
(21,589 |
) |
|
|
|
|
|
|
|
|
|
|
Capitalized exploratory well costs that have been capitalized for
a period greater than one year |
|
$ |
2,986 |
|
|
$ |
5,192 |
|
|
$ |
3,751 |
|
|
|
|
|
|
|
|
|
|
|
Number of projects that have exploratory well costs that have
been capitalized for a period greater than one year |
|
|
2 |
|
|
|
3 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2007, of the $3.0 million of capitalized exploratory well costs that have
been capitalized for more than one year, all of the wells have additional exploratory wells in the
same prospect area drilling or firmly planned. One of the wells is not operated by us. Of the
$15.1 million of capitalized exploratory well costs at December 31, 2007, $12.1 million was
incurred in 2007 and $3.0 million in 2006.
(8) INDEBTEDNESS
We had the following debt outstanding as of the dates shown below (bank debt interest rate at
December 31, 2007 is shown parenthetically). No interest was capitalized during 2007, 2006, and
2005 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
Bank debt (6.2%) |
|
$ |
303,500 |
|
|
$ |
452,000 |
|
Senior subordinated notes: |
|
|
|
|
|
|
|
|
7.375% senior subordinated notes due 2013, net
of $2.4 million and $2.7 million discount, respectively |
|
|
197,602 |
|
|
|
197,262 |
|
6.375% senior subordinated notes due 2015 |
|
|
150,000 |
|
|
|
150,000 |
|
7.5% senior subordinated notes
due 2016, net of $444,000 and $480,000 discount |
|
|
249,556 |
|
|
|
249,520 |
|
7.5% senior subordinated notes due 2017 |
|
|
250,000 |
|
|
|
|
|
|
|
|
|
|
|
|
Total debt |
|
$ |
1,150,658 |
|
|
$ |
1,048,782 |
|
|
|
|
|
|
|
|
F - 21
Bank Debt
In October 2006, we entered into an amended and restated $900.0 million revolving bank credit
facility, which we refer to as our bank debt or bank credit facility, which is secured by
substantially all of our assets. The bank credit facility provides for an initial commitment equal
to the lesser of the facility amount or the borrowing base. On December 31, 2007, the facility
amount was $900.0 million and the borrowing base was $1.5 billion. The bank credit facility
provides for a borrowing base subject to redeterminations semi-annually each April and October and
pursuant to certain unscheduled redeterminations. The facility amount may be increased to the
borrowing base amount with twenty-days notice. As of December 31, 2007, the outstanding balance
under the bank credit facility was $303.5 million and there was $596.5 million of borrowing
capacity available under the facility amount. The loan matures on October 25, 2012. Borrowing
under the bank credit facility can either be base rate loans or LIBOR loans. On all base rate
loans, the rate per annum is equal to the lesser of (i) the maximum rate (the weekly ceiling as
defined in Section 303 of the Texas Finance Code or other applicable laws if greater) (the Maximum
Rate) or, (ii) the sum of the higher of (1) the prime rate for such date, or (2) the sum of the
federal funds effective rate for such date plus one-half of one percent (0.50%) per annum, plus a
base rate margin of between 0.0% to 0.5% per annum depending on the total outstanding under the
bank credit facility relative to the borrowing base. On all LIBOR loans, we pay a varying rate per
annum equal to the lesser of (i) the Maximum Rate, or (ii) the sum of the quotient of (A) the LIBOR
base rate, divided by (B) one minus the reserve requirement applicable to such interest period,
plus a LIBOR margin of between 1.0% and 1.75% per annum depending on the total outstanding under
the bank credit facility relative to the borrowing base. We may elect, from time-to-time, to
convert all or any part of our LIBOR loans to base rate loans or to convert all or any of the base
rate loans to LIBOR loans. The weighted average interest rate was 6.4% for the year ended December
31, 2007 compared to 6.4% for the year ended December 31, 2006. A commitment fee is paid on the
undrawn balance based on an annual rate of 0.25% to 0.375%. At December 31, 2007, the commitment
fee was 0.25% and the interest rate margin was 1.0%.
Senior Subordinated Notes
In 2003, we issued $100.0 million aggregate principal amount of 7.375% senior subordinated
notes due 2013 (7.375% Notes). In 2004, we issued an additional $100.0 million of 7.375% Notes;
therefore, $200.0 million of the 7.375% Notes are currently outstanding. The 7.375% Notes were
issued at a discount which will be amortized over the life of the 7.375% Notes into interest
expense. In 2005, we issued $150.0 million aggregate principal amount of 6.375% senior
subordinated notes due 2015 (6.375% Notes). In May 2006, we issued $150.0 million aggregate
principal amount of the 7.5% senior subordinated notes due 2016 (the 7.5% Notes due 2016). In
August 2006, we issued an additional $100.0 million of the 7.5% Notes due 2016; therefore, $250.0
million of the 7.5% Notes due 2016 are currently outstanding. The 7.5% Notes due 2016 were also
issued at a discount, which is being amortized over the life of the 7.5% Notes due 2016. In
September 2007, we issued $250.0 million principal amount of 7.5% senior subordinated notes due
2017 (7.5% Notes due 2017). Interest on our senior subordinated notes is payable semi-annually,
at varying times, and each of the notes are guaranteed by certain of our subsidiaries.
We may redeem the 7.375% Notes, in whole or in part, at any time on or after July 15, 2008, at
redemption prices of 103.7% of the principal amount as of July 15, 2008, and declining to 100.0% on
July 15, 2011 and thereafter. We may redeem the 6.375% Notes, in whole or in part, at any time on
or after March 15, 2010, at redemption prices from 103.2% of the principal amount as of March 15,
2010 and declining to 100% on March 15, 2013 and thereafter. Before March 15, 2008, we may redeem
up to 35% of the original aggregate principal amount of the 6.375% Notes at a redemption price of
106.4% of the principal amount thereof plus accrued and unpaid interest, if any, with the proceeds
of certain equity offerings. We may redeem the 7.5% Notes due 2016, in whole or in part, at any
time on or after May 15, 2011 at redemption prices from 103.75% of the principal amount as of May
15, 2011 and declining to 100% on May 15, 2014 and thereafter. Before May 15, 2009, we may redeem
up to 35% of the original aggregate principal amount of the 7.5% Notes due 2016 at a redemption
price of 107.5% of principal amount thereof plus accrued and unpaid interest if any, with the
proceeds of certain equity offerings; provided that at least 65% of the original aggregate
principal amount of our 7.5% Notes 2016 remains outstanding immediately after the occurrence of
such redemption and provided that such redemption occurs within 60 days of the date of closing the
equity sale. We may redeem the 7.5% Notes due 2017, in whole or in part, at any time on or after
October 1, 2012 at redemption prices ranging from 103.75% of the principal amount as of October 1,
2012 and declining to 100% on October 1, 2015 and thereafter. Before October 1, 2010, we may
redeem up to 35% of the original aggregate principal amount of the 7.5% Notes due 2017 at a
redemption price of 107.5% of principal amount thereof plus accrued and unpaid interest, if any,
with the proceeds of certain equity offerings provided that at least 65% of the original aggregate
principal amount of our 7.5% Notes due 2017 remains outstanding immediately after the occurrence of
such redemption and provided that such redemption occurs 60 days of the date of closing the equity
sale.
If we experience a change of control, there may be a requirement to repurchase all or a
portion of the 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.
F - 22
Guarantees
Range Resources Corporation is a holding company which owns no operating assets and has no
significant operations independent of its subsidiaries. The guarantees of the 7.375% Notes, the
6.375% Notes, the 7.5% Notes due 2016 and the 7.5% Notes due 2017 are full and unconditional and
joint and several; any subsidiaries other than the subsidiary guarantors are minor subsidiaries.
Debt Covenants
The debt agreements contain covenants relating to working capital, dividends and financial
ratios. We were in compliance with all covenants at December 31, 2007. Under the bank credit
facility, common and preferred dividends are permitted, subject to the provisions of the restricted
payment basket. The bank credit facility provides for a restricted payment basket of $20.0 million
plus 50% of net income plus 66-2/3% of net cash proceeds from common stock issuances.
Approximately $735.2 million was available under the bank credit facilitys restricted payment
basket on December 31, 2007. The terms of each of our subordinated notes limit restricted payments
(including dividends) to the greater of $20.0 million or a formula based on earnings and equity
issuances since the original issuances of the notes. The 7.5% Notes due 2016 allows for any cash
proceeds received from the sale of oil and gas property purchased in the Stroud acquisition to be
added to the restricted payment basket. At December 31, 2007, approximately $922.4 million was
available under the restricted payment baskets for each of the 7.375% Notes, 6.375% Notes and the
7.5% Notes due 2017. There was $1.0 billion available under the restricted payment basket for the
7.5% Notes due 2016.
Following is the principal maturity schedule for the long-term debt outstanding as of December
31, 2007 (in thousands):
|
|
|
|
|
|
Year Ended December 31, |
2008 |
|
$ |
|
|
2009 |
|
|
|
|
2010 |
|
|
|
|
2011 |
|
|
|
|
2012 |
|
|
303,500 |
|
2013 |
|
|
200,000 |
|
Thereafter |
|
|
650,000 |
|
|
|
|
|
|
|
$ |
1,153,500 |
|
|
|
|
|
(9) ASSET RETIREMENT OBLIGATION
A reconciliation of our liability for plugging and abandonment costs for the years ended
December 31, 2007 and 2006 is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
Beginning of period |
|
$ |
95,588 |
|
|
$ |
68,063 |
|
|
Liabilities incurred |
|
|
3,118 |
|
|
|
4,006 |
|
|
Acquisitions continuing operations |
|
|
3,301 |
|
|
|
790 |
|
Acquisitions discontinued operations |
|
|
|
|
|
|
742 |
|
Liabilities settled |
|
|
(2,782 |
) |
|
|
(3,057 |
) |
Disposition of wells |
|
|
(20,066 |
) |
|
|
|
|
Accretion expense continuing operations |
|
|
5,960 |
|
|
|
4,824 |
|
Accretion expense discontinued operations |
|
|
382 |
|
|
|
37 |
|
Change in estimate |
|
|
(10,193 |
) |
|
|
20,183 |
|
|
|
|
|
|
|
|
End of period |
|
|
75,308 |
|
|
|
95,588 |
|
|
|
|
|
|
|
|
|
Less current portion |
|
|
(1,903 |
) |
|
|
(4,216 |
) |
|
|
|
|
|
|
|
|
Long-term asset retirement obligation |
|
$ |
73,405 |
|
|
$ |
91,372 |
|
|
|
|
|
|
|
|
Accretion expense is recognized as a component of depreciation, depletion and amortization.
December 31, 2006 includes $20.1 million related to discontinued operations ($363,000 current
portion).
F - 23
(10) CAPITAL STOCK
We have authorized capital stock of 260.0 million shares which includes 250.0 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 issued since the beginning of 2006:
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
Beginning balance |
|
|
138,931,565 |
|
|
|
129,913,046 |
|
Public offerings |
|
|
8,050,000 |
|
|
|
|
|
Shares issued for Stroud acquisition |
|
|
|
|
|
|
6,517,498 |
|
Shares issued in lieu of bonuses |
|
|
29,483 |
|
|
|
20,686 |
|
Stock options/SARs exercised |
|
|
2,220,627 |
|
|
|
1,956,164 |
|
Restricted stock grants |
|
|
408,067 |
|
|
|
487,607 |
|
Shares contributed to 401(k) plan |
|
|
27,755 |
|
|
|
36,564 |
|
|
|
|
|
|
|
|
Ending balance |
|
|
149,667,497 |
|
|
|
138,931,565 |
|
|
|
|
|
|
|
|
In April 2007, we completed a public offering of 8.1 million shares of common stock at $36.28
per share. Total proceeds from the offering of $280.4 million funded our acquisition of additional
interests in certain properties in Virginia and an associated equity interest in a gathering
system.
Treasury Stock
During 2007, we bought in open market purchases, 155,500 shares at an average price of $34.30.
The board of directors has approved up to $10.0 million of repurchases of common stock based on
market conditions and opportunities. As of December 31, 2007, we have $4.7 million remaining
authorization.
(11) FINANCIAL INSTRUMENTS
Fair Value of Financial Instruments
Financial instruments include cash and equivalents, receivables, payables, marketable
securities, debt and commodity derivatives. The carrying value of cash and equivalents,
receivables, payables is considered to be representative of fair value because of their short
maturity.
F - 24
The following table sets forth our other financial instruments fair values at each of these
dates (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007 |
|
|
December 31, 2006 |
|
|
|
Book |
|
|
Fair |
|
|
Book |
|
|
Fair |
|
|
|
Value |
|
|
Value |
|
|
Value |
|
|
Value |
|
Derivative assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity swaps and collars (a) |
|
$ |
54,100 |
|
|
$ |
54,100 |
|
|
$ |
154,656 |
|
|
$ |
154,656 |
|
Derivative liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity swaps and collars (a) |
|
|
(76,276 |
) |
|
|
(76,276 |
) |
|
|
(4,887 |
) |
|
|
(4,887 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net derivative asset (liability) |
|
$ |
(22,176 |
) |
|
$ |
(22,176 |
) |
|
$ |
149,769 |
|
|
$ |
149,769 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketable securities (b) |
|
$ |
51,482 |
|
|
$ |
51,482 |
|
|
$ |
44,226 |
|
|
$ |
44,226 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt (c) |
|
$ |
1,150,658 |
|
|
$ |
1,158,033 |
|
|
$ |
1,048,782 |
|
|
$ |
1,058,069 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
All derivatives are marked to market and therefore their book value is
assumed to be equal to fair value. |
|
(b) |
|
Marketable securities held in our deferred compensation plans which are
marked to market. |
|
(c) |
|
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
current market quotes. |
Commodity Derivative Instruments
We use swap and collar derivative contracts to hedge against the variability in cash flows
associated with the forecasted sale of our future oil and gas production. While the use of these
derivative instruments limit the downside risk of adverse price movements, their use also may limit
future revenues from favorable price movements. We do not hold or issue derivative financial
instruments for speculative or trading purposes.
At December 31, 2007, we had open swap contracts covering 71.3 Bcf of gas at prices averaging
$8.82 per mcf. We also had collars covering 54.8 Bcf of gas at weighted average floor and cap
prices of $8.07 to $9.73 per mcf and 6.2 million barrels of oil at weighted average floor and cap
prices of $61.54 to $75.72 per barrel. 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 loss of $22.3 million at December 31,
2007. These contracts expire monthly through December 2009. The following table sets forth the
derivative volumes by year as of December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
Period |
|
Contract Type |
|
Volume Hedged |
|
Average Hedge Price |
Natural Gas |
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
Swaps |
|
155,000 Mmbtu/day |
|
$ |
8.97 |
|
2008 |
|
Collars |
|
70,000 Mmbtu/day |
|
$ |
8.01 $10.83 |
|
2009 |
|
Swaps |
|
40,000 Mmbtu/day |
|
$ |
8.24 |
|
2009 |
|
Collars |
|
80,000 Mmbtu/day |
|
$ |
8.12 $8.76 |
|
|
Crude Oil |
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
Collars |
|
9,000 bbl/day |
|
$ |
59.34 $75.48 |
|
2009 |
|
Collars |
|
8,000 bbl/day |
|
$ |
64.01 $76.00 |
|
Under SFAS No. 133, every derivative instrument is required to be recorded on the balance
sheet as either an asset or a liability measured at its fair value. Fair value is generally
determined based on the difference between the fixed contract price and the underlying market price
at the determination date, and/or the value confirmed by the counterparty. If the derivative does
not qualify as a hedge or is not designated as a hedge, the change in fair value of the derivative
is recognized in earnings. As of December 31, 2007, an unrealized pre-tax derivative loss of $41.1
million was recorded in accumulated other comprehensive income (loss). This loss is expected to be
reclassified into earnings in 2008 ($7.2 million) and 2009 ($33.9 million). The actual
reclassification to earnings will be based on mark-to-market prices at the contract settlement
date.
F - 25
For those derivative instruments that qualify for hedge accounting, settled transaction gains
and losses are determined monthly and are included as increases or decreases to oil and gas sales
in the period the hedged production is sold. Oil and gas sales include $4.2 million of gains in
2007 compared to losses of $93.2 million in 2006 and losses of $153.7 million in 2005. Any
ineffectiveness associated with these hedges is reflected in derivative fair value income (loss) in
our statement of operations. The year ended December 31, 2007 includes ineffective unrealized
losses of $820,000 compared to gains of $6.0 million in 2006 and losses of $3.5 million in 2005.
In the fourth quarter of 2005, certain of our gas hedges no longer qualified for hedge accounting
due to the effect of gas price volatility on the correlation between realized prices and hedge
reference prices and are marked to market. Also, as a result of the sale of our Gulf of Mexico
assets in the first quarter of 2007, a portion of our derivatives which were designated to our Gulf
Coast production was marked to market resulting in derivative fair value income of $209,000. In
the fourth quarter of 2007, we began marking a portion of our oil hedges designated as Permian
Basin production to market due to the anticipated sale of a portion of our Permian properties
resulting in derivative fair value loss of $14.7 million. These derivatives have been retained to
serve as economic hedges for our production even though we can no longer apply hedge accounting.
We recognize all unrealized and realized gains and losses related to these contracts in our
consolidated statement of operations under the caption Derivative fair value income (loss) (see
table below).
During the third quarter of 2007, in addition to the swaps and collars above, we 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 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. The fair value of the basis
swaps was a net unrealized pre-tax gain of $145,000 at December 31, 2007.
Derivative fair value income (loss)
The following table presents information about the components of derivative fair value income
(loss) in the three-year period ended December 31, 2007 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Hedge ineffectiveness realized |
|
$ |
968 |
|
|
$ |
|
|
|
$ |
|
|
unrealized |
|
|
(820 |
) |
|
|
5,965 |
|
|
|
(3,471 |
) |
Change in fair value of derivatives that do not qualify for hedge accounting |
|
|
(78,769 |
) |
|
|
86,491 |
|
|
|
10,868 |
|
Realized gain on settlement-gas (a) |
|
|
71,098 |
|
|
|
49,939 |
|
|
|
2,906 |
|
Realized loss on settlement-oil (a) |
|
|
(244 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative fair value (loss) income |
|
$ |
(7,767 |
) |
|
$ |
142,395 |
|
|
$ |
10,303 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
These amounts represent the realized gains and losses on settled derivatives that
do not qualify for hedge accounting, which before settlement are included in the category
above called the change in fair value of derivatives that do not qualify for hedge
accounting. |
The combined fair value of derivatives included in our consolidated balance sheets as of
December 31, 2007 and 2006 is summarized below (in thousands). Derivative activities are conducted
with major financial and commodities trading institutions which we believe are acceptable credit
risks. At times, such risks may be concentrated with certain counterparties. We have master
netting agreements with our counterparties and the credit worthiness of our counterparties is
subject to continuing review.
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
Derivative assets: |
|
|
|
|
|
|
|
|
Natural gas swaps |
|
$ |
54,577 |
|
|
$ |
121,792 |
|
collars |
|
|
4,916 |
|
|
|
36,973 |
|
basis swaps |
|
|
1,082 |
|
|
|
|
|
Crude oil collars |
|
|
(6,475 |
) |
|
|
(4,109 |
) |
|
|
|
|
|
|
|
|
|
$ |
54,100 |
|
|
$ |
154,656 |
|
|
|
|
|
|
|
|
|
Derivative liabilities: |
|
|
|
|
|
|
|
|
Natural gas swaps |
|
$ |
6,594 |
|
|
$ |
(248 |
) |
collars |
|
|
11,302 |
|
|
|
2,337 |
|
basis swap |
|
|
(937 |
) |
|
|
|
|
Crude oil collars |
|
|
(93,235 |
) |
|
|
(6,976 |
) |
|
|
|
|
|
|
|
|
|
$ |
(76,276 |
) |
|
$ |
(4,887 |
) |
|
|
|
|
|
|
|
F - 26
(12) EMPLOYEE BENEFIT AND EQUITY PLANS
Stock and Option Plans
We have six equity-based stock plans, of which two are active. Under the active plans,
incentive and non-qualified options, stock appreciation rights (SARs), restricted stock awards,
phantom stock rights and annual cash incentive awards may be issued to directors and employees
pursuant to decisions of the Compensation Committee which is made up of outside independent
directors from the Board of Directors. All awards granted under these plans have been issued at
the prevailing market price at the time of the grant. During 2007 and 2006, only SARs have been
granted under the plans to limit the dilutive impact of our equity plans. Information with respect
to stock option and SAR activities is summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
Exercise |
|
|
|
Shares |
|
|
Price |
|
Outstanding at December 31, 2004 |
|
|
6,873,105 |
|
|
$ |
5.09 |
|
Granted |
|
|
3,141,937 |
|
|
|
16.96 |
|
Exercised |
|
|
(1,105,549 |
) |
|
|
4.84 |
|
Expired/forfeited |
|
|
(167,188 |
) |
|
|
9.08 |
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2005 |
|
|
8,742,305 |
|
|
|
9.31 |
|
Granted |
|
|
1,658,160 |
|
|
|
24.36 |
|
Stock options assumed in Stroud acquisition |
|
|
652,062 |
|
|
|
19.67 |
|
Exercised |
|
|
(2,051,237 |
) |
|
|
9.22 |
|
Expired/forfeited |
|
|
(149,164 |
) |
|
|
18.32 |
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2006 |
|
|
8,852,126 |
|
|
|
12.76 |
|
Granted |
|
|
1,680,643 |
|
|
|
33.78 |
|
Exercised |
|
|
(2,461,689 |
) |
|
|
9.45 |
|
Expired/forfeited |
|
|
(298,755 |
) |
|
|
23.42 |
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2007 |
|
|
7,772,325 |
|
|
$ |
17.95 |
|
|
|
|
|
|
|
|
The following table shows information with respect to outstanding stock options and SARs at
December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding |
|
|
Exercisable |
|
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
Average |
|
|
Weighted- |
|
|
|
|
|
|
Average |
|
Range of Exercise |
|
|
|
|
|
Remaining |
|
|
Average |
|
|
|
|
|
|
Exercise |
|
Prices |
|
Shares |
|
|
Contractual Life |
|
|
Exercise Price |
|
|
Shares |
|
|
Price |
|
$1.29 $9.99 |
|
|
2,378,044 |
|
|
|
2.31 |
|
|
$ |
4.84 |
|
|
|
2,378,044 |
|
|
$ |
4.84 |
|
10.00 19.99 |
|
|
2,322,548 |
|
|
|
2.40 |
|
|
|
16.29 |
|
|
|
1,307,911 |
|
|
|
15.95 |
|
20.00 29.99 |
|
|
1,477,365 |
|
|
|
3.24 |
|
|
|
24.44 |
|
|
|
453,157 |
|
|
|
24.47 |
|
30.00 39.99 |
|
|
1,576,468 |
|
|
|
4.23 |
|
|
|
33.80 |
|
|
|
44,550 |
|
|
|
37.95 |
|
40.00 44.75 |
|
|
17,900 |
|
|
|
4.80 |
|
|
|
42.56 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
7,772,325 |
|
|
|
2.91 |
|
|
$ |
17.95 |
|
|
|
4,183,662 |
|
|
$ |
10.79 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The weighted average fair value of a SAR to purchase one share of common stock during 2007 was
$10.67. The fair value of each SAR granted during 2007 was estimated as of the date of grant using
the Black-Scholes-Merton option pricing model based on the following assumptions: risk-free
interest rate of 4.73%; dividend yield of 0.36%; expected volatility of 35.67%; and an expected
life of 3.54 years. The 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
dividend yield is based on the current annual dividend at the time of grant. For SARs granted in
2007 and 2006, we used the simplified method prescribed by SEC Staff Accounting Bulletin No. 107
to estimate the expected term of the options, which is calculated based on the midpoint between the
vesting date and the life of the SAR. The risk-free 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. Of
the 7.8 million outstanding at December 31, 2007, 3.7 million relates to stock options with the
remainder of 4.1 million relating to SARs.
F - 27
The total intrinsic value (the difference in value between exercise and market price) of stock
options and SARs exercised during the years ended December 31, 2007 was $67.2 million compared to
$37.1 million in 2006 and $15.2 million in 2005. As of December 31, 2007, the aggregate intrinsic
value of the awards outstanding was $259.7 million. The aggregate intrinsic value and weighted
average remaining contractual life of stock option awards currently exercisable was $169.7 million
and 2.49 years. As of December 31, 2007, the number of fully-vested awards and awards expected to
vest was 7.6 million. The weighted average exercise price and weighted average remaining
contractual life of these awards were $17.70 and 2.89 years and the aggregate intrinsic value was
$256.6 million. As of December 31, 2007, unrecognized compensation cost related to the awards was
$17.6 million, which is expected to be recognized over a weighted average period of 0.84 years.
For the year ended December 31, 2007, total stock-based compensation expense for stock options
and SARs under SFAS No. 123(R) was $15.2 million compared to $14.8 million in 2006. The total
related tax benefits were $3.9 million. For the year ended December 31, 2007, cash received upon
exercise of stock option awards was $16.2 million. Due to the
net operating loss carryforward for tax
purposes, tax benefits realized for deductions that were in excess of the stock-based compensation
expense were not recognized.
Restricted Stock Grants
In 2007, we issued 435,000 shares of restricted stock grants as compensation to directors and
employees, at an average price of $34.85. The restricted grants included 15,900 issued to
directors, which vest immediately, and 419,100 to employees with vesting over a three-year period.
In 2006, we issued 499,200 shares of restricted stock grants as compensation to directors and
employees, at an average price of $24.43. The restricted grants included 15,000 issued to
directors, which vest immediately, and 484,200 to employees with vesting over a three-to-four year
period. We recorded compensation expense for restricted stock grants of $8.7 million in the year
ended December 31, 2007 compared to $4.3 million in 2006 and $942,000 in 2005. As of December 31,
2007, there was $28.5 million of unrecognized compensation related to restricted stock awards
expected to be recognized over the next three years. The vesting of these shares is dependent only
upon the employees continued service with us. For restricted stock grants, the fair value is
equal to the closing price of our common stock on the grant date. All of our restricted stock
grants are held in our deferred compensation plan (see discussion below). The proceeds received
from the sale of stock held in our deferred compensation plan was $6.5 million in 2007. All awards
are issued at the market price at the time of the grant.
A summary of the status of our non-vested restricted stock outstanding at December 31, 2007
and changes during the twelve months then ended, is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
Average Grant |
|
|
|
Shares |
|
|
Date Fair Value |
|
Non-vested shares |
|
|
470,297 |
|
|
$ |
24.00 |
|
outstanding at December
31, 2006 |
|
|
|
|
|
|
|
|
Granted |
|
|
435,841 |
|
|
|
34.85 |
|
Vested |
|
|
(302,617 |
) |
|
|
27.59 |
|
Forfeited |
|
|
(39,861 |
) |
|
|
24.61 |
|
|
|
|
|
|
|
|
Non-vested
shares outstanding at December
31, 2007 |
|
|
563,660 |
|
|
$ |
30.42 |
|
|
|
|
|
|
|
|
401(k) Plan
We maintain a 401(k) Plan for our employees. The 401(k) Plan permits employees to contribute
up to 50% of their salary (subject to Internal Revenue Service limitations) on a pretax basis.
Historically, we have made discretionary contributions of our common stock to the 401(k) Plan
annually. In 2005, we began matching contributions of up to 3% of salary in cash. Beginning in
2008, we will match up to 6% of salary in cash. All our contributions become fully vested after
the individual employee has three years of service with us. In 2007, we contributed $2.3 million
to the 401(k) Plan compared to $1.9 million in 2006 and $1.5 million in 2005. We do not require
that employees hold the contributed Range stock in their account. Employees have a variety of
investment options in the 401(k) Plan. Employees may, at any time, diversify out of our stock,
based on their personal investment strategy.
Deferred Compensation Plan
In 1996, the Board of Directors adopted a deferred compensation plan (the Plan). The Plan gave
directors, certain officers and key employees the ability to defer all or a portion of their
salaries and bonuses and invests in Range common stock or makes other investments at the
individuals discretion. Great Lakes Energy Partners (which we purchased in 2004) also had a
deferred compensation plan that allowed certain employees to defer all or a portion of their
salaries and bonuses and invest such amounts in certain investments at the employees discretion.
In December 2004, we adopted the Range Resources Corporation Deferred Compensation Plan (2005
Deferred Compensation Plan). The 2005 Deferred Compensation Plan is intended to operate in a
manner substantially similar to the old plans, subject to new requirements and changes mandated
under Section 409A of the Internal Revenue Code. The old plans will not receive additional
contributions. The assets of all of the plans are held in a rabbi 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
F - 28
istreated as a liability award
(as defined by SFAS No. 123(R)) as employees are allowed to take withdrawals from the Rabbi Trust
either in cash or in Range stock. The vested portion of the stock held in the Rabbi Trust is
adjusted to fair value each reporting period by a charge or credit to deferred compensation plan
expense on our consolidated statement of operations. The assets of the Rabbi Trust, other than our
common stock, are invested in marketable securities and reported at market value in other assets on
our consolidated balance sheet. The deferred compensation liability on our consolidated balance
sheet reflects the vested market value of the marketable securities held in the Rabbi Trust and the market
value of the vested Range stock held in the Rabbi Trust. Changes in the market value of the
marketable securities are reflected in accumulated other comprehensive income (loss), while changes
in the fair value of the liability are charged or credited to deferred compensation plan expense
each quarter. We recorded mark-to-market expenses of $28.3 million in 2007 compared to $6.9
million in 2006 and $29.5 million in 2005. The Rabbi Trust held 2,111,565 shares of Range stock at
December 31, 2007 compared to 1,853,279 at December 31, 2006.
In the fourth quarter of 2007, we recorded adjustments that decreased deferred compensation
plan expense by $12.4 million, decreased common stock held by deferred compensation plan ( a
contra-equity account) to zero, decreased the deferred compensation liability by $26.2 million,
decreased additional paid-in capital by $16.8 million and increased accumulated other comprehensive
income (loss) by $5.6 million. Such reclassifications and adjustments were the result of
inappropriately adjusting our deferred compensation liability for market value changes in unvested
shares held in the Rabbi Trust and inappropriately recording our common stock issued to the Rabbi
Trust at grant date fair value as opposed to our cost basis. In addition, interest and dividends
related to the marketable securities held in the Rabbi Trust were inappropriately recorded in
accumulated other comprehensive loss. Of the $12.4 million decrease in deferred compensation
expense, $7.1 million is related to periods prior to 2007 and $5.3 million is related to the first
three quarters of 2007. We have also reclassified the December 31, 2006 common stock held by
deferred compensation plan (a contra-equity account) of $22.1 million to additional paid-in capital
along with $11.9 million in December 31, 2005 to conform to
the 2007 balance sheet presentation.
(13) SUPPLEMENTAL CASH FLOW INFORMATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2007 |
|
2006 |
|
2005 |
|
|
|
|
|
|
(in thousands) |
|
|
|
|
Net cash provided from continuing operations included: |
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes paid (refunded from) to taxing authorities |
|
$ |
(572 |
) |
|
$ |
1,973 |
|
|
$ |
615 |
|
Interest paid |
|
|
71,708 |
|
|
|
55,925 |
|
|
|
34,148 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash investing and finance activities: |
|
|
|
|
|
|
|
|
|
|
|
|
6.5 million shares issued for Stroud acquisition |
|
$ |
|
|
|
$ |
177,641 |
|
|
$ |
|
|
Stock options (652,000) issued in Stroud acquisition |
|
|
|
|
|
|
9,478 |
|
|
|
|
|
Asset retirement costs capitalized, excluding acquisitions (a) |
|
|
(7,075 |
) |
|
|
25,821 |
|
|
|
(1,730 |
) |
|
|
|
(a) |
|
For information regarding purchase price allocations of businesses acquired
see Note 3. |
(14) COMMITMENTS AND CONTINGENCIES
Litigation
We are involved in various legal actions and claims arising in the ordinary course of our
business. While the outcome of these lawsuits cannot be predicted with certainty, we do not expect
these matters to have a material adverse effect on our financial position, cash flows or results of
operations.
F-29
Lease Commitments
We lease certain office space and equipment under cancelable and non-cancelable leases. Rent
expense under such arrangements totaled $5.4 million in 2007 compared to $5.0 million in 2006 and
$2.2 million in 2005. Future minimum rental commitments under non-cancelable leases having
remaining lease terms in excess of one year are as follows (in thousands):
|
|
|
|
|
|
|
Operating |
|
|
|
Lease |
|
|
|
Obligations |
|
2008 |
|
$ |
9,657 |
|
2009 |
|
|
9,730 |
|
2010 |
|
|
9,491 |
|
2011 |
|
|
8,081 |
|
2012 |
|
|
4,720 |
|
Thereafter |
|
|
8,568 |
|
Sublease rentals |
|
|
(1,045 |
) |
|
|
|
|
|
|
$ |
49,202 |
|
|
|
|
|
Other Commitments
We also have agreements in place to purchase seismic data. These agreements total $500,000 in
2008 and $300,000 in 2009. We have lease acreage that is generally subject to lease expiration if
initial wells are not drilled within a specified period, generally two to three 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 likely allow additional acreage to expire in the future.
(15) MAJOR CUSTOMERS
We market our production on a competitive basis. Gas is sold under various types of contracts
including month-to-month, and one-to-five-year contracts. Oil purchasers may be changed on 30 days
notice. The price for oil is generally equal to a posted price set by major purchasers in the area
or is based on NYMEX pricing, adjusted for quality and transportation. We sell to oil and gas
purchasers on the basis of price, credit quality and service. For the year ended December 31,
2007, we had no customers that accounted for 10% or more of total oil and gas revenues. For the
year ended December 31, 2006, two customers each accounted for 10% or more of total oil and gas
revenues and the combined sales to those customers accounted for 25% of total oil and gas revenues.
For the year ended December 31, 2005, four customers each accounted for 10% or more of total oil
and gas revenue and combined sales to those four customers accounted for 56% of total oil and gas
revenues. We believe that the loss of any one customer would not have a material adverse effect on
our results.
(16) EQUITY METHOD INVESTMENTS
We account for our investments in entities over which we have significant influence, but not
control, using the equity method of accounting. Under the equity method of accounting, we record
our proportionate share of the net earnings, declared dividends and partnership distributions based
on the most recently available financial statements of the investee. We also evaluate 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 may include
sustained operating losses by the investee or long-term negative changes in the investees
industry. These indicators were not present, and as a result, we did not recognize any impairment
charges related to our equity method investments for the years ended December 31, 2007 or 2006.
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.
F-30
Whipstock follows a calendar year basis of financial reporting consistent with Range and our
equity in Whipstocks earnings from the acquisition date is included in other revenue in our
results of operations for 2007 and 2006, respectively. There were no dividends or partnership
distributions received from Whipstock during the years ended December 31, 2007 or 2006. In
determining our proportionate share of the net earnings of Whipstock, certain adjustments are
required to be made to Whipstocks reported results to eliminate the profits recognized by
Whipstock for services provided to Range. For the years ended December 31, 2007 and 2006, our
equity in the earnings of Whipstock totaled $132,000 and $548,000, respectively. Our equity in the
earnings of Whipstock was reduced by $2.7 million and $1.1 million, respectively to eliminate the
profit on services provided to Range. Range and Whipstock have entered into an agreement whereby
Whipstock will provide Range with the right of first refusal such that Range will have the
opportunity to secure services from Whipstock in preference to and in advance of Whipstock entering
into additional commitments for services with other customers. All services provided to Range are
based on Whipstocks usual and customary terms.
Investment in Nora Gathering, LLC
In May 2007, we completed the initial closing of a joint development arrangement with
Equitable. Pursuant to the terms of the arrangement, Range and Equitable (the parties) agreed to
among other things, form a new pipeline and natural gas gathering operations entity, Nora
Gathering, LLC (NGLLC). NGLLC is 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 acquisition,
we contributed cash of $94.7 million for a 50% membership interest in NGLLC.
NGLLC follows a calendar year basis of financial reporting consistent with Range and our
equity in NGLLC earnings from the acquisition date is included in other revenue in our results of
operations for 2007. There were no dividends or partnership distributions received from NGLLC
during the year ended December 31, 2007. In determining our proportionate share of the net
earnings of NGLLC, certain adjustments are required to be made to NGLLCs reported results to
eliminate the profits recognized by NGLLC included in the gathering and transportation fees charged
to Range on production in the Nora field. For the year ended December 31, 2007, our equity in the
earnings of NGLLC of $841,000 was reduced by $1.8 million to eliminate the profit on gathering and
transportation fees charged to Range. The gathering and transportation rate charged by NGLLC to
Range on our production in the Nora field is considered to be at market.
(17) SUBSEQUENT EVENTS
In January 2008, we purchased producing and non-producing Barnett Shale properties for $284.2
million. The properties are located in Tarrant, Johnson, Ellis, Parker and Hill counties. Also in
January 2008, we sold non-core oil properties located in East Texas for proceeds of $64.0 million.
These properties included 99 shallow oil wells covering 5,600 net acres.
F-31
(18) SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
The following tables set forth unaudited financial information on a quarterly basis for each
of the last two years. As discussed in Note 2, certain reclassifications have been made to conform
to our current year classifications. This includes the presentation of our Gulf of Mexico
operations as discontinued operations, the reclassification of settled derivatives that do not
qualify for hedge accounting from oil and gas sales to derivative fair value income (loss) and the
reclassification of hedge ineffectiveness from other revenue to derivative fair value income
(loss). These reclassifications did not impact net income. See also Note 12 for additional
information on fourth quarter 2007 adjustments related to our deferred compensation plan.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
|
March |
|
|
June |
|
|
September |
|
|
December |
|
|
Total |
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales |
|
$ |
193,316 |
|
|
$ |
213,896 |
|
|
$ |
214,424 |
|
|
$ |
240,901 |
|
|
$ |
862,537 |
|
Transportation and gathering |
|
|
184 |
|
|
|
511 |
|
|
|
508 |
|
|
|
1,087 |
|
|
|
2,290 |
|
Derivative fair value (loss) income |
|
|
(42,620 |
) |
|
|
28,766 |
|
|
|
24,974 |
|
|
|
(18,887 |
) |
|
|
(7,767 |
) |
Other |
|
|
1,961 |
|
|
|
341 |
|
|
|
2,447 |
|
|
|
282 |
|
|
|
5,031 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
152,841 |
|
|
|
243,514 |
|
|
|
242,353 |
|
|
|
223,383 |
|
|
|
862,091 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating |
|
|
25,414 |
|
|
|
24,816 |
|
|
|
28,003 |
|
|
|
30,508 |
|
|
|
108,741 |
|
Production and ad valorem taxes |
|
|
10,412 |
|
|
|
11,230 |
|
|
|
11,316 |
|
|
|
9,485 |
|
|
|
42,443 |
|
Exploration |
|
|
11,710 |
|
|
|
11,725 |
|
|
|
6,233 |
|
|
|
13,677 |
|
|
|
43,345 |
|
General and administrative |
|
|
14,678 |
|
|
|
17,838 |
|
|
|
18,058 |
|
|
|
17,854 |
|
|
|
68,428 |
|
Deferred compensation plan |
|
|
11,247 |
|
|
|
9,334 |
|
|
|
7,761 |
|
|
|
(10 |
) |
|
|
28,332 |
|
Interest expense |
|
|
18,848 |
|
|
|
17,573 |
|
|
|
19,935 |
|
|
|
21,381 |
|
|
|
77,737 |
|
Depletion, depreciation and amortization |
|
|
47,332 |
|
|
|
51,465 |
|
|
|
57,001 |
|
|
|
71,530 |
|
|
|
227,328 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
139,641 |
|
|
|
143,981 |
|
|
|
148,307 |
|
|
|
164,425 |
|
|
|
596,354 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes |
|
|
13,200 |
|
|
|
99,533 |
|
|
|
94,046 |
|
|
|
58,958 |
|
|
|
265,737 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax provision (benefit) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
384 |
|
|
|
(101 |
) |
|
|
133 |
|
|
|
(96 |
) |
|
|
320 |
|
Deferred |
|
|
4,447 |
|
|
|
34,449 |
|
|
|
34,802 |
|
|
|
24,743 |
|
|
|
98,441 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,831 |
|
|
|
34,348 |
|
|
|
34,935 |
|
|
|
24,647 |
|
|
|
98,761 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
|
8,369 |
|
|
|
65,185 |
|
|
|
59,111 |
|
|
|
34,311 |
|
|
|
166,976 |
|
Discontinued operations, net of taxes |
|
|
64,768 |
|
|
|
(979 |
) |
|
|
(196 |
) |
|
|
|
|
|
|
63,593 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
73,137 |
|
|
$ |
64,206 |
|
|
$ |
58,915 |
|
|
$ |
34,311 |
|
|
$ |
230,569 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic income from continuing operations |
|
$ |
0.06 |
|
|
$ |
0.45 |
|
|
$ |
0.40 |
|
|
$ |
0.23 |
|
|
$ |
1.16 |
|
discontinued operations |
|
|
0.47 |
|
|
|
(0.01 |
) |
|
|
|
|
|
|
|
|
|
|
0.44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net income |
|
$ |
0.53 |
|
|
$ |
0.44 |
|
|
$ |
0.40 |
|
|
$ |
0.23 |
|
|
$ |
1.60 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted income from continuing operations |
|
$ |
0.06 |
|
|
$ |
0.43 |
|
|
$ |
0.39 |
|
|
$ |
0.22 |
|
|
$ |
1.11 |
|
discontinued operations |
|
|
0.45 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.43 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net income |
|
$ |
0.51 |
|
|
$ |
0.43 |
|
|
$ |
0.39 |
|
|
$ |
0.22 |
|
|
$ |
1.54 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
|
March |
|
|
June |
|
|
September |
|
|
December |
|
|
Total |
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales |
|
$ |
150,658 |
|
|
$ |
139,431 |
|
|
$ |
153,054 |
|
|
$ |
155,996 |
|
|
$ |
599,139 |
|
Transportation and gathering |
|
|
(39 |
) |
|
|
957 |
|
|
|
1,015 |
|
|
|
489 |
|
|
|
2,422 |
|
Derivative fair value income (loss) |
|
|
28,598 |
|
|
|
29,316 |
|
|
|
65,490 |
|
|
|
18,991 |
|
|
|
142,395 |
|
Other |
|
|
13 |
|
|
|
(314 |
) |
|
|
66 |
|
|
|
1,091 |
|
|
|
856 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
179,230 |
|
|
|
169,390 |
|
|
|
219,625 |
|
|
|
176,567 |
|
|
|
744,812 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating |
|
|
18,133 |
|
|
|
16,933 |
|
|
|
22,336 |
|
|
|
23,859 |
|
|
|
81,261 |
|
Production and ad valorem taxes |
|
|
9,551 |
|
|
|
8,545 |
|
|
|
9,874 |
|
|
|
8,445 |
|
|
|
36,415 |
|
Exploration |
|
|
8,922 |
|
|
|
7,763 |
|
|
|
16,508 |
|
|
|
10,895 |
|
|
|
44,088 |
|
General and administrative |
|
|
11,330 |
|
|
|
12,514 |
|
|
|
12,170 |
|
|
|
13,872 |
|
|
|
49,886 |
|
Deferred compensation plan |
|
|
4,479 |
|
|
|
(2,188 |
) |
|
|
(2,638 |
) |
|
|
7,220 |
|
|
|
6,873 |
|
Interest expense |
|
|
10,234 |
|
|
|
11,643 |
|
|
|
16,389 |
|
|
|
17,583 |
|
|
|
55,849 |
|
Depletion, depreciation and amortization |
|
|
31,651 |
|
|
|
33,995 |
|
|
|
40,606 |
|
|
|
48,487 |
|
|
|
154,739 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
94,300 |
|
|
|
89,205 |
|
|
|
115,245 |
|
|
|
130,361 |
|
|
|
429,111 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuous operations before income taxes |
|
|
84,930 |
|
|
|
80,185 |
|
|
|
104,380 |
|
|
|
46,206 |
|
|
|
315,701 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
578 |
|
|
|
622 |
|
|
|
615 |
|
|
|
97 |
|
|
|
1,912 |
|
Deferred |
|
|
31,150 |
|
|
|
29,676 |
|
|
|
38,707 |
|
|
|
20,307 |
|
|
|
119,840 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31,728 |
|
|
|
30,298 |
|
|
|
39,322 |
|
|
|
20,404 |
|
|
|
121,752 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
|
53,202 |
|
|
|
49,887 |
|
|
|
65,058 |
|
|
|
25,802 |
|
|
|
193,949 |
|
Discontinued operations, net of taxes |
|
|
2,473 |
|
|
|
1,383 |
|
|
|
(13,728 |
) |
|
|
(25,375 |
) |
|
|
(35,247 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
55,675 |
|
|
$ |
51,270 |
|
|
$ |
51,330 |
|
|
$ |
427 |
|
|
$ |
158,702 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic income from continuing operations |
|
$ |
0.41 |
|
|
$ |
0.38 |
|
|
$ |
0.47 |
|
|
$ |
0.19 |
|
|
$ |
1.45 |
|
discontinued operations |
|
|
0.02 |
|
|
|
0.01 |
|
|
|
(0.10 |
) |
|
|
(0.19 |
) |
|
|
(0.26 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net income |
|
$ |
0.43 |
|
|
$ |
0.39 |
|
|
$ |
0.37 |
|
|
$ |
|
|
|
$ |
1.19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted income from continuing operations |
|
$ |
0.40 |
|
|
$ |
0.37 |
|
|
$ |
0.46 |
|
|
$ |
0.18 |
|
|
$ |
1.39 |
|
discontinued operations |
|
|
0.01 |
|
|
|
0.01 |
|
|
|
(0.10 |
) |
|
|
(0.18 |
) |
|
|
(0.25 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net income |
|
$ |
0.41 |
|
|
$ |
0.38 |
|
|
$ |
0.36 |
|
|
$ |
|
|
|
$ |
1.14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Principal Unconsolidated Investees (unaudited)
|
|
|
|
|
|
|
December 31, |
|
|
Company |
|
2007 Ownership |
|
Activity |
|
|
|
|
|
Whipstock Natural Gas Services, LLC |
|
50% |
|
Drilling services |
Nora Gathering, LLC |
|
50% |
|
Gas gathering and transportation |
F-33
(19) SUPPLEMENTAL INFORMATION ON NATURAL GAS AND OIL EXPLORATION, DEVELOPMENT
AND PRODUCTION ACTIVITIES
The following information concerning our natural gas and oil operations has been provided
pursuant to Statement of Financial Accounting Standards No. 69, Disclosures about Oil and Gas
Producing Activities, (SFAS No. 69). Our natural gas and oil producing activities are conducted
onshore within the continental United States and offshore in the Gulf of Mexico. Our Gulf of
Mexico assets were sold in the first quarter of 2007.
Capitalized Costs and Accumulated Depreciation, Depletion and Amortization (a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
(in thousands) |
|
Oil and gas properties: |
|
|
|
|
|
|
|
|
|
|
|
|
Properties subject to depletion |
|
$ |
4,172,151 |
|
|
$ |
3,132,927 |
|
|
$ |
2,255,860 |
|
Unproved properties |
|
|
271,426 |
|
|
|
226,166 |
|
|
|
28,453 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
4,443,577 |
|
|
|
3,359,093 |
|
|
|
2,284,313 |
|
Accumulated depreciation, depletion and
amortization |
|
|
(939,769 |
) |
|
|
(751,005 |
) |
|
|
(604,720 |
) |
|
|
|
|
|
|
|
|
|
|
Net capitalized costs |
|
$ |
3,503,808 |
|
|
$ |
2,608,088 |
|
|
$ |
1,679,593 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Includes capitalized asset retirement costs and the associated
accumulated amortization. |
Costs Incurred for Property Acquisition, Exploration and Development (a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
(in thousands) |
|
Acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
Unproved leasehold |
|
$ |
4,552 |
|
|
$ |
132,821 |
|
|
$ |
|
|
Proved oil and gas properties |
|
|
253,064 |
|
|
|
209,262 |
|
|
|
131,748 |
|
Purchase price adjustment (b) |
|
|
|
|
|
|
147,062 |
|
|
|
20,966 |
|
Asset retirement obligations |
|
|
3,301 |
|
|
|
896 |
|
|
|
119 |
|
Acreage purchases |
|
|
78,095 |
|
|
|
79,762 |
|
|
|
20,674 |
|
Development |
|
|
734,987 |
|
|
|
464,586 |
|
|
|
252,574 |
|
Exploration: |
|
|
|
|
|
|
|
|
|
|
|
|
Drilling |
|
|
40,567 |
|
|
|
25,618 |
|
|
|
30,101 |
|
Expense |
|
|
39,872 |
|
|
|
42,173 |
|
|
|
29,354 |
|
Stock-based compensation expense |
|
|
3,473 |
|
|
|
3,079 |
|
|
|
1,250 |
|
Gas gathering facilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions |
|
|
|
|
|
|
|
|
|
|
8 |
|
Exploratory |
|
|
|
|
|
|
3,418 |
|
|
|
|
|
Development |
|
|
18,655 |
|
|
|
16,272 |
|
|
|
11,415 |
|
|
|
|
|
|
|
|
|
|
|
Subtotal |
|
|
1,176,566 |
|
|
|
1,124,949 |
|
|
|
498,209 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations |
|
|
(7,075 |
) |
|
|
25,821 |
|
|
|
(1,730 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred (c) |
|
$ |
1,169,491 |
|
|
$ |
1,150,770 |
|
|
$ |
496,479 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets held for sale: |
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions |
|
$ |
|
|
|
$ |
140,110 |
|
|
$ |
|
|
Development |
|
$ |
1,114 |
|
|
$ |
15,012 |
|
|
$ |
|
|
|
|
|
(a) |
|
Includes cost incurred whether capitalized or expensed. |
|
(b) |
|
Represents the offset to our deferred tax liability resulting from
differences in book and tax basis at date of acquisition. |
|
(c) |
|
2006 includes $21.5 million related to our divested Gulf of Mexico
properties compared to $14.8 million in 2005. |
F-34
Estimated Quantities of Proved Oil and Gas Reserves (Unaudited)
Reserves of crude oil, condensate, natural gas liquids and natural gas are estimated by our
engineers 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 and other economic factors.
The SEC defines proved reserves as those volumes of crude oil, condensate, natural gas liquids
and natural gas that geological and engineering data demonstrate with reasonable certainty are
recoverable 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 as a result of additional investments for drilling new wells to offset
productive units, recompleting existing wells, and/or installing facilities to collect and
transport production.
Production quantities shown are net volumes withdrawn from reservoirs. These may differ from
sales quantities due to inventory changes, and, especially in the case of natural gas, volumes
consumed for fuel and/or shrinkage from extraction of natural gas liquids.
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, 2007 to estimate reserve information were
$91.88 per barrel for oil, $52.64 per barrel for natural gas liquids and $6.44 per mcf for gas,
using benchmark prices of $95.98 per barrel and $6.80 per Mmbtu. The average realized prices used
at December 31, 2006 to estimate reserve information were $57.66 per barrel for oil, $25.98 per
barrel for natural gas liquids and $5.24 per mcf for gas, using benchmark prices of $61.05 per
barrel and $5.64 per Mmbtu. The average realized prices used at December 31, 2005 to estimate
reserve information were $57.80 per barrel for oil, $36.00 per barrel for natural gas liquids and
$9.83 per mcf for gas, using benchmark prices of $61.04 per barrel and $10.08 per Mmbtu. All of
our proved reserves are located within the United States.
F-35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil |
|
|
|
|
|
Natural Gas |
|
|
and NGLs |
|
Natural Gas |
|
Equivalents(b) |
|
|
(Mbbls) |
|
(Mmcf) |
|
(Mmcfe) |
Proved developed and undeveloped reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2004 |
|
|
38,166 |
|
|
|
946,428 |
|
|
|
1,175,425 |
|
Revisions |
|
|
2,499 |
|
|
|
809 |
|
|
|
15,802 |
|
Extensions, discoveries and additions |
|
|
7,932 |
|
|
|
169,785 |
|
|
|
217,377 |
|
Purchases |
|
|
2,343 |
|
|
|
71,569 |
|
|
|
85,626 |
|
Property sales |
|
|
(5 |
) |
|
|
(177 |
) |
|
|
(205 |
) |
Production |
|
|
(4,043 |
) |
|
|
(63,004 |
) |
|
|
(87,263 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2005 |
|
|
46,892 |
|
|
|
1,125,410 |
|
|
|
1,406,762 |
|
Revisions |
|
|
(42 |
) |
|
|
(48,609 |
) |
|
|
(48,863 |
) |
Extensions, discoveries and additions |
|
|
10,871 |
|
|
|
314,261 |
|
|
|
379,491 |
|
Purchases |
|
|
242 |
|
|
|
121,683 |
|
|
|
123,133 |
|
Property sales |
|
|
(4 |
) |
|
|
(1,500 |
) |
|
|
(1,522 |
) |
Production |
|
|
(4,252 |
) |
|
|
(75,267 |
) |
|
|
(100,775 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2006 (a) |
|
|
53,707 |
|
|
|
1,435,978 |
|
|
|
1,758,226 |
|
Revisions |
|
|
2,432 |
|
|
|
(386 |
) |
|
|
14,207 |
|
Extensions, discoveries and additions |
|
|
13,741 |
|
|
|
401,805 |
|
|
|
484,250 |
|
Purchases |
|
|
1,934 |
|
|
|
121,382 |
|
|
|
132,984 |
|
Property sales |
|
|
(649 |
) |
|
|
(35,362 |
) |
|
|
(39,254 |
) |
Production |
|
|
(4,505 |
) |
|
|
(90,620 |
) |
|
|
(117,651 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2007 |
|
|
66,660 |
|
|
|
1,832,797 |
|
|
|
2,232,762 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2005 |
|
|
33,029 |
|
|
|
724,876 |
|
|
|
923,050 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006 |
|
|
37,750 |
|
|
|
875,395 |
|
|
|
1,101,895 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007 |
|
|
47,015 |
|
|
|
1,144,709 |
|
|
|
1,426,802 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The December 31, 2006 balance excludes reserves associated with the Austin Chalk
properties that are shown as Assets Held for Sale on our balance sheet. The total proved
developed and undeveloped reserves for these assets at December 31, 2006 were 42.3 Bcfe
which is comprised of 39.3 Bcfe of gas. These assets were sold in the first quarter of
2007. |
|
(b) |
|
Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcfe. |
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 and oil reserve disclosures, standardized measures of discounted future net cash flows from
proved natural gas and oil reserves and the reconciliations of standardized measures from year to
year. The information disclosed, as prescribed by SFAS No. 69, 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 and crude oil which geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and operating conditions.
F-36
The standardized measure of discounted future net cash flows from production of proved
reserves was developed as follows:
1. |
|
Estimates are made of quantities of proved reserves and future amounts expected to be
produced based on current year-end economic conditions. |
2. |
|
Estimated future cash inflows are calculated by applying current year-end prices of natural
gas and oil relating to our proved reserves to the quantities of those reserves produced in
each future year. |
3. |
|
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 and oil properties, other
deductions, credits and allowances relating to our proved natural gas and oil reserves. |
4. |
|
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 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.
The standardized measure of discounted future net cash flows relating to proved natural gas
and oil reserves is as follows and excludes cash flows associated with hedges outstanding at each
of the respective reporting dates.
|
|
|
|
|
|
|
|
|
|
|
As of December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
|
(in thousands) |
|
Future cash inflows |
|
$ |
17,231,826 |
|
|
$ |
10,192,067 |
|
Future costs: |
|
|
|
|
|
|
|
|
Production |
|
|
(3,859,591 |
) |
|
|
(2,575,212 |
) |
Development |
|
|
(1,464,229 |
) |
|
|
(1,225,710 |
) |
|
|
|
|
|
|
|
Future net cash flows before income taxes |
|
|
11,908,006 |
|
|
|
6,391,145 |
|
|
|
|
|
|
|
|
|
|
Future income tax expense |
|
|
(3,854,952 |
) |
|
|
(1,999,934 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total future net cash flows before 10% discount |
|
|
8,053,054 |
|
|
|
4,391,211 |
|
|
|
|
|
|
|
|
|
|
10% annual discount |
|
|
(4,386,691 |
) |
|
|
(2,388,987 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows |
|
$ |
3,666,363 |
|
|
$ |
2,002,224 |
|
|
|
|
|
|
|
|
F-37
The following table summarizes changes in the standardized measure of discounted future net
cash flows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
(in thousands) |
|
Beginning of period |
|
$ |
2,002,224 |
|
|
$ |
3,384,310 |
|
|
$ |
1,749,411 |
|
Revisions of previous estimates: |
|
|
|
|
|
|
|
|
|
|
|
|
Changes in prices |
|
|
1,310,378 |
|
|
|
(2,390,159 |
) |
|
|
1,633,812 |
|
Revisions in quantities |
|
|
37,188 |
|
|
|
(91,793 |
) |
|
|
59,244 |
|
Changes in future development costs |
|
|
(542,684 |
) |
|
|
(623,607 |
) |
|
|
(367,732 |
) |
Accretion of discount |
|
|
277,144 |
|
|
|
488,737 |
|
|
|
239,636 |
|
Net change in income taxes |
|
|
(769,242 |
) |
|
|
733,846 |
|
|
|
(856,115 |
) |
Purchases of reserves in place |
|
|
348,119 |
|
|
|
231,314 |
|
|
|
321,022 |
|
Additions to proved reserves from extensions,
discoveries and improved recovery |
|
|
1,267,649 |
|
|
|
712,902 |
|
|
|
814,973 |
|
Production |
|
|
(711,354 |
) |
|
|
(554,788 |
) |
|
|
(425,902 |
) |
Development costs incurred during the period |
|
|
304,165 |
|
|
|
223,158 |
|
|
|
143,918 |
|
Sales of natural gas and oil |
|
|
(102,757 |
) |
|
|
(2,859 |
) |
|
|
(769 |
) |
Timing and other |
|
|
245,533 |
|
|
|
(108,837 |
) |
|
|
72,812 |
|
|
|
|
|
|
|
|
|
|
|
End of period |
|
$ |
3,666,363 |
|
|
$ |
2,002,224 |
|
|
$ |
3,384,310 |
|
|
|
|
|
|
|
|
|
|
|
F-38
RANGE RESOURCES CORPORATION
INDEX TO EXHIBITS
|
|
|
Exhibit No. |
|
Description |
2.1
|
|
Agreement and Plan of Merger, dated May 10, 2006, by and among Range Resources Corporation,
Range Acquisition Texas, Inc. and Stroud Energy, Inc. (incorporated by reference to Exhibit 2.1
to our Form 8-K (File No. 001-12209) as filed with the SEC on May 16, 2006) |
|
|
|
3.1
|
|
Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference
to Exhibit 3.1.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on May 5, 2004) as
amended by the Certificate of First Amendment to Restated Certificate of Incorporation of Range
Resources Corporation (incorporated by reference to exhibit 3.1 to our Form 10-Q (File No.
001-12209) as filed with the SEC on July 28, 2005) |
|
|
|
3.2
|
|
Amended and Restated By-laws of Range (incorporated by reference to Exhibit 3.2 to our Form
10-K (File No. 001-12209) as filed with the SEC on March 3, 2004) |
|
|
|
4.1
|
|
Form of 7.375% Senior Subordinated Notes due 2013 (included as an exhibit to exhibit 4.2 hereto) |
|
|
|
4.2
|
|
Indenture dated July 21, 2003 by and among Range, as issuer, the Subsidiary Guarantors (as
defined herein), as guarantors, and Bank One, National Association, as trustee (incorporated by
reference to Exhibit 4.4.2 to our Form 10-Q (File No. 001-12209) as filed with the SEC on
August 6, 2003) |
|
|
|
4.3
|
|
Form of 6.375% Senior Subordinated Notes due 2015 (included as an exhibit to exhibit 4.4 hereto) |
|
|
|
4.4
|
|
Indenture dated March 9, 2005 by and among Range, as issuer, the Subsidiary Guarantors (as
defined herein), as guarantors and J.P.Morgan Trust Company, National Association, as trustee
(incorporated by reference to Exhibit 4.1 on our Form 8-K (File No. 001-12209) as filed with
the SEC on March 15, 2005) |
|
|
|
4.5
|
|
Form of 7.5% Senior Subordinated Notes due 2016 (included as an exhibit to exhibit 4.6 hereto) |
|
|
|
4.6
|
|
Indenture dated May 23, 2006 by and among Range, as issuer, the Subsidiary Guarantors (as
defined herein), as guarantors and J.P.Morgan Trust Company, National Association as trustee
(incorporated by reference to Exhibit 4.1 on our Form 8-K (File No. 001-12209) as filed with
the SEC on May 23, 2006) |
|
|
|
4.7
|
|
Form of 7.5% Senior Subordinated Notes due 2017 (included as exhibit 4.8 hereto) |
|
|
|
4.8
|
|
Indenture dated September 28, 2007 by and among Range, as issuer, the subsidiary Guarantors (as
defined herein), as guarantors and J.P.Morgan Trust Company, National Association as trustee
(incorporated by reference to Exhibit 4.1 on our Form 8-K (File No. 001-12209) as filed with
the SEC on October 1, 2007) |
|
|
|
10.1
|
|
Third Amended and Restated Credit Agreement as of October 25, 2006 among Range (as borrowers)
and J.P.Morgan Chase Bank, N.A. and the institutions named (therein) as lenders, J.P.Morgan
Chase as Administrative Agent |
|
|
|
10.2
|
|
First Amendment to the Third Amended and Restated Credit Agreement dated October 26, 2006 among
Range (as borrower) and J.P.Morgan Chase Bank, N.A. and institutions named (therein) as
lenders, J.P.Morgan Chase as Administrative Agent (incorporated by reference to exhibit 10.1 to
our Form-10Q (File No. 001-12209) as filed with the SEC April 26, 2007) |
|
|
|
10.3
|
|
Second Amendment to the Third Amended and Restated Credit Agreement dated October 26, 2006
among Range (as borrower) and J.P.Morgan Chase Bank, N.A. and institutions named (therein) as
lenders, J.P.Morgan Chase as Administrative Agent (incorporated by reference to exhibit 10.1 to
our Form-10Q (File No. 001-12209) as filed with the SEC April 26, 2007) |
|
|
|
10.4*
|
|
Third Amendment to the Third Amended and Restated Credit Agreement dated October 26, 2006 among
Range (as borrower) and J.P.Morgan Chase Bank, N.A. and institutions named (therein) as lenders |
|
|
|
10.5
|
|
Range Resources Corporation Deferred Compensation Plan for Directors and Select Employees
effective December 28, 2004 (incorporated by reference to Exhibit 10.2 to our Form 8-K (File
No. 001-12209) as filed with the SEC on January 3, 2005) |
|
|
|
10.6
|
|
Form of Indemnity Agreement (incorporated by reference to Exhibit 10.5 to our Form 8-K (File
No. 001-12209) as filed with the SEC on May 18, 2005) |
|
|
|
10.7
|
|
Range Resources Corporation 2005 Equity-Based Compensation (incorporated by reference to
Exhibit 10.7 to our Form 8-K (File No. 001-12209) as filed with the SEC on May 18, 2005) |
|
|
|
10.8
|
|
First Amendment to the Range Resources Corporation 2005 Equity-Based Compensation Plan
(incorporated by reference to Exhibit 10.8 to our Form 8-K (File No. 001-12209) as filed with
the SEC on May 18, 2005) |
|
|
|
10.9
|
|
Second Amendment to the Range Resources Corporation 2005 Equity-Based Compensation Plan
(incorporated by reference to Exhibit 10.2 to our Form 8-K (File No. 001-12209) as filed with
the SEC on May 26, 2006) |
|
|
|
10.10
|
|
Third Amendment to the Range Resources Corporation 2005 Equity-Based Compensation Plan
(incorporated by reference to Exhibit 10.3 to our Form 8-K (File No. 001-12209) as filed with
the SEC on May 26, 2006) |
|
|
|
10.11
|
|
Fourth Amendment to the Range Resources 2005 Equity-Based Compensation Plan (incorporated by
reference to Exhibit 4.5 to our Form S-8 (File No. 333-143875) as filed with the SEC on June
19, 2007) |
|
|
|
10.12
|
|
Fifth Amendment to the Range Resources 2005 Equity-Based Compensation Plan (incorporated by
reference to Exhibit 4.6 to our Form S-8 (File No. 333-143875) as filed with the SEC on June
19, 2007) |
50
|
|
|
Exhibit No. |
|
Description |
10.13
|
|
Lomak 1989 Stock Option Plan dated March 13, 1989 (incorporated by reference to Exhibit 10.1(d)
to Lomaks Form S-1 (File No. 33-31558) as filed with the SEC on October 13, 1989) |
|
|
|
10.14
|
|
Amendment to the Lomak 1989 Stock Option Plan, as amended (incorporated by reference to Exhibit
4.1 to Lomaks Form S-8 (File No. 333-10719) as filed with the SEC on August 23, 1996) |
|
|
|
10.15
|
|
Amendment to the Lomak 1989 Stock Option Plan, as amended (incorporated by reference to Exhibit
4.2 to Lomaks Form S-8 (File No. 333-44821) as filed with the SEC on January 23, 1998) |
|
|
|
10.16
|
|
Lomak 1994 Outside Directors Stock Option Plan (incorporated by reference to Exhibit 4.2 to
Lomaks Form S-8 (File No. 333-10719) as filed with the SEC on August 23, 1996) |
|
|
|
10.17
|
|
First Amendment to the Lomak 1994 Outside Directors Stock Option Plan dated June 8, 1995
(incorporated by reference to Exhibit 4.6 to our Form S-8 (File No. 333-40380) as filed with
the SEC on June 29, 2000) |
|
|
|
10.18
|
|
Second Amendment to the Lomak 1994 Outside Directors Stock Option Plan dated August 21, 1996
(incorporated by reference to Exhibit 4.7 to our Form S-8 (File No. 333-40380) as filed with
the SEC on June 29, 2000) |
|
|
|
10.19
|
|
Third Amendment to the Lomak 1994 Outside Directors Stock Option Plan dated June 1, 1999
(incorporated by reference to Exhibit 4.8 to our Form S-8 (File No. 333-40380) as filed with
the SEC on June 29, 2000) |
|
|
|
10.20
|
|
Fourth Amendment to the Lomak 1994 Outside Directors Stock Plan dated May 24, 2000
(incorporated by reference to Exhibit 4.9 to our Form S-8 (File No. 333-40380) as filed with
the SEC on June 29, 2000) |
|
|
|
10.21
|
|
2004 Non-Employee Director Stock Option Plan dated May 19, 2004 (incorporated by reference to
Exhibit 4.2 to our Form S-8 (File No. 333-116320) as filed with the SEC on June 9, 2004) |
|
|
|
10.22
|
|
Lomak 1997 Stock Purchase Plan, as amended, dated June 19, 1997 (incorporated by reference to
Exhibit 10.1(1) to Lomaks Form 10-K (File No. 001-12209) as filed with the SEC on March 20,
1998) |
|
|
|
10.23
|
|
First Amendment to the Lomak 1997 Stock Purchase Plan dated May 26, 1999 (incorporated by
reference to Exhibit 4.2 to our Form S-8 (File No. 333-40380) as filed with the SEC on June 29,
2000) |
|
|
|
10.24
|
|
Second Amendment to the Lomak 1997 Stock Purchase Plan dated September 28, 1999 (incorporated
by reference to Exhibit 4.3 to our Form S-8 (File No. 333-40380) as filed with the SEC on June
29, 2000) |
|
|
|
10.25
|
|
Third Amendment to the Lomak 1997 Stock Purchase Plan dated May 24, 2000 (incorporated by
reference to Exhibit 4.4 to our Form S-8 (File No. 333-40380) as filed with the SEC on June 29,
2000) |
|
|
|
10.26
|
|
Fourth Amendment to the Lomak 1997 Stock Purchase Plan dated May 24, 2001 (incorporated by
reference to Exhibit 4.7 to our Form S-8 (File No. 333-63764) as filed with the SEC on June 25,
2001) |
|
|
|
10.27
|
|
Amended and Restated 1999 Stock Option Plan (as amended May 21, 2003) (incorporated by
reference to Exhibit 4.1 to our Form S-8 (File No. 333-105895) as filed with the SEC on June 6,
2003) |
|
|
|
10.28
|
|
Fourth Amendment to the Amended and Restated 1999 Stock Option Plan dated May 19, 2004
(incorporated by reference to Exhibit 4.1 to our Form S-8 (File No. 333-116320) as filed with
the SEC on June 9, 2004) |
|
|
|
10.29
|
|
Range Resources Corporation 401(k) Plan (incorporated by reference to Exhibit 10.14 to our Form
S-4 (File No. 333-108516) as filed with the SEC on September 4, 2003) |
|
|
|
10.30
|
|
Range Resources Corporation Executive Change in Control Severance Benefit Plan dated March 28,
2005 (incorporated by reference to exhibit 10.1 to our Form 8-k (File No. 001-12209) as filed
with the SEC on March 31, 2005) |
|
|
|
21.1*
|
|
Subsidiaries of Registrant |
|
|
|
23.1*
|
|
Consent of Independent Registered Public Accounting Firm |
|
|
|
23.2*
|
|
Consent of H.J. Gruy and Associates, Inc., independent consulting engineers |
|
|
|
23.3*
|
|
Consent of DeGoyler and MacNaughton, independent consulting engineers |
|
|
|
23.4*
|
|
Consent of Wright and Company, independent consulting engineers |
|
|
|
31.1*
|
|
Certification by the President and Chief Executive Officer of Range Pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002 |
|
|
|
31.2*
|
|
Certification by the Chief Financial Officer of Range Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002 |
|
|
|
32.1**
|
|
Certification by the President and Chief Executive Officer of Range Pursuant to 18 U.S.C.
Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
|
|
|
32.2**
|
|
Certification by the Chief Financial Officer of Range Pursuant to 18 U.S.C. Section 350, as
adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
|
|
|
* |
|
Filed herewith. |
|
** |
|
Furnished herewith. |
51