e10vk
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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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, 2005
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 No. 001-11899
THE HOUSTON EXPLORATION COMPANY
(Exact name of registrant as specified in its charter)
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Delaware
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22-2674487 |
(State or Other Jurisdiction of
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(IRS Employer |
Incorporation or Organization)
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Identification No.) |
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1100 Louisiana, Suite 2000 |
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Houston, Texas
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77002-5215 |
(Address of Principal Executive Offices)
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(Zip Code) |
(713) 830-6800
(Registrants Telephone Number, including Area Code)
Securities Registered Pursuant to Section 12(b) of the Act:
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Name of Each |
Title of Each Class
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Exchange on Which Registered |
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Common Stock, $.01 par value
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New York Stock Exchange |
7% Senior Subordinated Notes due 2013 |
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Securities Registered Pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule
405 of the Securities Act. Yes 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. Yes
o No þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer,
or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Large accelerated filer
þ Accelerated filer
o Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Act). Yes o No þ
The aggregate market value of the voting stock held by non-affiliates of the registrant was
approximately $1.026 billion, based on the closing sales price of $53.05 per share of the
registrants common stock as reported by on the New York Stock Exchange as of June 30, 2005, the
last business day of the registrants most recently completed second fiscal quarter. As of March 1, 2006, 29,067,430
shares of common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrants Proxy Statement for the Annual Meeting of Stockholders to be held
April 28, 2006 are incorporated by reference into Part III of this Form 10-K.
Forward-Looking Statements
Certain statements in this Annual Report on Form 10-K (Annual Report) and the documents we have
incorporated by reference into this Annual Report, other than purely historical information,
including estimates, projections, statements relating to our business plans, strategies, objectives
and expected operating results, and the assumptions upon which those statements are based, are
forward-looking statements within the meaning of the Private Securities Litigation Reform Act of
1995, Section 27A of the Securities Act of 1933, as amended (the Securities Act) and Section 21E
of the Securities Exchange Act of 1934 (the Exchange Act). These forward-looking statements
generally are identified by the words believe, project, expect, anticipate, estimate,
intend, strategy, plan,
target, pursue,
may, will, would, will be, will continue, will
likely result, and similar expressions. Forward-looking statements are based on current
expectations and assumptions that are subject to risks and uncertainties which may cause actual
results to differ materially from the forward-looking statements. A detailed discussion of these
and other risks and uncertainties that could cause actual results and events to differ materially
from such forward-looking statements is included in Item 1A.
Risk Factors beginning on page 15 of
this Annual Report. We undertake no obligation to update or revise publicly any forward-looking
statements, whether as a result of new information, future events or otherwise.
Available Information
Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and
amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange
Act are made available free of charge on our website at http://www.houstonexploration.com as soon
as reasonably practicable after we electronically file such material with, or otherwise furnish it
to, the SEC.
We have adopted a Code of Business Conduct to provide guidance to our directors, officers and
employees on matters of business conduct and ethics, including compliance standards and procedures.
We have also adopted a Code of Ethics for Senior Financial Officers that applies to our principal
executive officer, principal financial officer, principal accounting officer and controller. Our
Code of Business Conduct and Code of Ethics for Senior Financial Officers are available on the
Shareholder/Financial section of our web site at www.houstonexploration.com under the heading
Corporate Governance. We intend to promptly disclose via a Current Report on Form 8-K or via an
update to our web site information about any amendment to or waiver of, these codes with respect to
our executive officers and directors. Our Corporate Governance Guidelines and the charters of our
Audit Committee, Nominating and Governance Committee, and Compensation and Management Development
Committee are also available on the Shareholder/Financial section of our web site at
www.houstonexploration.com under the heading Corporate Governance. In addition, a copy of our
Code of Business Conduct, Code of Ethics for Senior Financial Officers, Corporate Governance
Guidelines and the charters of the Committees referenced above are available in print at no cost to
any stockholder who requests them by writing or telephoning us at the following address or
telephone number:
The Houston Exploration Company
1100 Louisiana Street, Suite 2000
Houston, TX 77002 5215
Attention: Corporate Secretary
Telephone: (713) 830-6800
Information contained on or connected to our web site is not incorporated by reference into this
Annual Report and should not be considered part of this report or any other filing that we make
with the SEC.
In this Annual Report, unless the context requires otherwise, when we refer to we, us and
our, we are describing The Houston Exploration Company including, through May 31, 2004, our
former subsidiary Seneca-Upshur Petroleum, Inc., and subsequent to October 8, 2004, THEC, LLC and
THEC, LP on a consolidated basis.
If you are not familiar with the natural gas and oil terms used in this Annual Report, please refer
to the explanations of the terms under the caption Glossary of Natural Gas and Oil Terms included
on pages G-1 through G-2.
When we refer to equivalents, we are doing so to compare quantities of oil with quantities of
natural gas or to express these different commodities in a common unit. In calculating equivalents,
we use a generally recognized standard in which one barrel of oil is equal to six thousand cubic
feet of natural gas.
-2-
Part I.
Items 1. and 2. Business and Properties
Overview of Our Business
We are an independent natural gas and oil producer concentrating on growing reserves and production
through the exploration, development, exploitation and acquisition of natural gas and oil reserves
in North America. We were founded in December 1985 as a Delaware corporation and began exploring
for natural gas and oil on behalf of KeySpan Corporation, our then parent company. KeySpan is a
diversified energy provider whose principal natural gas distribution and electric generation
operations are located in the Northeastern United States. In September 1996, we completed our
initial public offering and sold approximately 31% of our shares to the public. Through three
separate transactions, the first in February 2003 and last in November 2004, KeySpan completely
divested its investment in the common stock of our company.
At December 31, 2005, we had operations in five producing regions within the United States: South
Texas; the Arkoma Basin of Arkansas and Oklahoma; East Texas; the Uinta and DJ Basins in the Rocky
Mountains; and the Gulf of Mexico.
Our total net proved reserves as of December 31, 2005 were 861 billion cubic feet equivalent or
Bcfe, with onshore reserves totaling 616 Bcfe. Our reserves are fully engineered on an annual
basis by independent petroleum engineers. Approximately 64% of our proved reserves at December 31,
2005, were classified as proved developed. Our daily production during 2005 averaged 313 million
cubic feet of natural gas equivalent or MMcfe and was significantly curtailed during the last four
months of 2005 and into the first quarter of 2006 primarily as a result of infrastructure damage to
third party pipelines and processing facilities caused by Hurricanes Katrina and Rita that hit the
Louisiana and Texas coasts in August and September 2005.
In November 2005, we announced our intent to explore the sale of our Gulf of Mexico assets and to
shift our operating focus onshore. This strategic change will leverage our strength of developing
complex, tight or low permeable natural gas reservoirs while providing flexibility to expand both
in our present core areas and other tight gas basins. During 2005, our offshore assets accounted
for 40% of our 2005 production and represented 245 Bcfe, or 28% of our proved reserves, at December
31, 2005.
On February 28, 2006, we entered into an agreement to sell the Texas portion of our Gulf of Mexico
assets to certain partnerships affiliated with Merit Energy Company for $220 million in cash,
subject to adjustment and customary closing conditions. The transaction is scheduled to close on or about March
31, 2006, with an effective date of January 1, 2006. The sale process with respect to our
remaining Gulf of Mexico assets is ongoing. If a sale is not consummated, we expect to
continue to operate and may consider other strategic alternatives
with respect to these assets.
The Texas portion of our Gulf of Mexico assets accounted for approximately 18% of our 2005
production and represented 58.5 Bcfe, or 7% of our total proved reserves, at December 31, 2005. We
expect to use the proceeds from the sale of the Texas portion of our Gulf of Mexico assets
primarily to acquire longer-lived natural gas assets onshore in North America and to repay
existing debt. Where possible, we plan to structure our asset reinvestment to minimize taxes on
any gain realized from the sale.
-3-
Business Strategy
Our goal is to create and maximize shareholder value by growing and/or optimizing reserves,
production and cash flow, while maintaining financial flexibility. To grow our business, we invest
primarily in natural gas projects within areas where we are presently successful or where we
believe our organizations skill set can produce successful results. To accomplish our goal, we
employ the following strategies:
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Balanced Growth. We pursue a balanced strategy of exploiting our existing
reserves, exploring for new reserves and acquiring new properties. Typically, at least 70%
of our annual capital expenditure program is dedicated to lower risk exploitation and
development projects intended to generate cash flows with which we can fund future expansion
opportunities. We supplement our exploitation activities by investing in exploratory
prospects. We enhance our exploration and exploitation activities with acquisitions of new
projects that we believe offer significant unexploited reserve potential and that conform to
our investment criteria and operating philosophy. |
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Focus on Natural Gas. Our assets are concentrated in natural gas prone areas in
the United States, and our production and reserve base is primarily natural gas. As of
December 31, 2005, approximately 92% of our proved reserves were natural gas and, for the
year ended December 31, 2005, approximately 93% of our production was natural gas. On an
equivalent unit of production basis, lease operating expense is typically lower for natural
gas properties as compared to oil properties allowing a higher cash margin. While we
believe that the pricing fundamentals for natural gas will remain strong for the foreseeable
future, we have explored and may continue to explore opportunities to balance our asset
portfolio with additional oil properties. Such activities depend on the relative pricing
outlook for both natural gas and oil, acquisition opportunities, and operational
considerations, including our objectives of shifting operations onshore, lowering finding
and development costs, and lengthening reserve life. |
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Concentrate on Core Areas. We focus our drilling activities on properties in
relatively concentrated areas in order to more efficiently utilize our base of geological,
engineering, drilling and production experience and expertise in these regions. By
concentrating our operations, we believe we are able to manage a large asset base with a
relatively small number of employees and to integrate additional properties at relatively
low incremental costs. At December 31, 2005, approximately 89% of our reserves were located
in three core areas: South Texas, the Gulf of Mexico and the Arkoma Basin. Upon completion
of the pending sale of the Texas portion of our Gulf of Mexico assets, South Texas and
the Arkoma Basin will comprise approximately 47% and 19%, respectively, of our reserves. In
addition, through our current activities in both the Rocky Mountains and East Texas, either
one or both of these regions could develop into a core area in the future. Further, we plan
to seek opportunities in one or more new areas where we believe we can utilize the strengths
of our existing workforce to sustain future growth. |
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Maintain Significant Operating Control. Whenever possible, we prefer to operate
our properties as it gives us more control over the nature and timing of capital
expenditures and overall operating expenses. At December 31, 2005, we operated approximately
80% of our wells and our average working interest was approximately 73%. |
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Focus on Low Costs. We seek to minimize operating costs through the
concentration of assets within geographic areas where we can leverage our operating control
and capture operating efficiencies. Although we expect our costs will increase in 2006, we
believe that our operating structure provides us a significant competitive advantage because
it maximizes our margins and cash flows. For 2005, our lease operating expense was $0.59
per Mcfe. |
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Employ Conservative Financial Policies. We typically fund our exploitation and
exploration activities out of cash flows from operations, while we have funded acquisitions
with borrowings under our revolving bank credit facility and through public debt offerings.
Although our debt levels have historically increased periodically in connection with
acquisitions, and may increase from time to time in the future as we continue to make
acquisitions, we will seek to maintain conservative debt levels. Among other things, this
will provide us with flexibility to continually review and adjust our capital expenditure
program during the year based on operational developments, commodity prices, service costs,
acquisition opportunities and numerous other factors. In addition to bank borrowings and
public debt, we may also issue common stock in connection with future acquisitions, either
initially as an element of the transaction consideration or subsequently as part of a
financing plan. |
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Managing Commodity Price Risks. We have historically employed a hedging program
intended to reduce our exposure to adverse commodity price fluctuations and provide more
predictable cash flows that allow us to plan and fund our capital expenditure program.
While the use of derivative instruments has prevented us from realizing the full benefit of
upward price movements and may continue to do so in the future, we believe that price
volatility is likely to continue and that we can use this volatility to our benefit by
taking advantage of prices when they reach levels we believe lock in targeted rates of
return on our invested capital. |
-4-
Properties and Operating Areas
The table below summarizes certain data for our core operating areas for the year ended December
31, 2005:
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Activity and Balances as of or for the Year Ended December 31, 2005 |
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Average |
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Total |
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Percentage |
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Daily |
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Total |
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Proved |
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Total Proved |
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Production |
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Production |
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Reserves |
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Reserves |
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Wells Drilled |
Area |
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Total |
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Successful |
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(MMcfe/d) |
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(MMcfe) |
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(MMcfe) |
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(Gross) |
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(Gross) |
South Texas |
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134 |
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48,983 |
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374,163 |
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44 |
% |
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95 |
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82 |
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Arkoma Basin |
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43 |
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15,789 |
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151,054 |
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18 |
% |
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61 |
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60 |
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East Texas |
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5 |
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1,812 |
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61,308 |
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7 |
% |
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16 |
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16 |
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Rocky Mountains |
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5 |
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1,665 |
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26,713 |
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3 |
% |
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149 |
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128 |
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Other |
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1 |
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372 |
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2,986 |
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Total onshore |
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188 |
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68,621 |
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616,224 |
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72 |
% |
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321 |
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286 |
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Gulf of Mexico |
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125 |
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45,690 |
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244,596 |
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28 |
% |
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15 |
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12 |
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Total |
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313 |
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114,311 |
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860,820 |
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100 |
% |
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336 |
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298 |
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South Texas. Our South Texas properties are concentrated in the Charco, North Roleta, Haynes and
South Trevino Fields of Zapata County; the Alexander, Hubbard and South Laredo Fields of Webb
County; and the Northeast Thompsonville Field in Jim Hogg County. In November 2005, we spent
$159.0 million to expand our South Texas operating base by acquiring 62 Bcfe of proved reserves and
interests in 300 producing wells and 26,000 net acres covering the Rincon Field in Starr County,
the Tijerina-Canales-Blucher Field in Jim Wells and Kleberg Counties, the Vaquillas Ranch Field in
Webb County, and the San Carlos Field in Hidalgo County. These properties are expected to add
significant drilling opportunities for 2006. We plan to add a seventh drilling rig early in the
second quarter of 2006 at which time we expect to spud our first well in the Rincon Field.
As of December 31, 2005, our South Texas properties covered approximately 94,600 net acres and we
owned interests in 872 producing wells, 764 or 88% of which we operated. Our average working
interest is 84%. Well depths range from 5,000 to 17,000 feet with production from the Frio,
Vicksburg and Wilcox formations. In total, our net South Texas production has more than tripled
since we began operations in the area in July 1996, to an average of 134 MMcfe per day during 2005.
Over the course of nine and a half years, we drilled 451 wells, of which 366 were successful,
produced 342 Bcfe and added 603 Bcfe in reserves through drilling and acquisitions. South Texas
accounted for 43% of our total production during 2005 and approximately 44% of our reserve base as
of December 31, 2005
Gulf of Mexico. Our offshore properties are located in the shallow waters of the Outer Continental
Shelf. Our key producing properties are located in the
western and central Gulf of Mexico and include the Mustang Island, Matagorda Island, Galveston
Island, High Island, East Cameron, West Cameron, Eugene Island and Main Pass areas. Over the last
three years, our offshore operations have become less exploration-focused, as we have undertaken a
number of exploration and exploitation activities aimed at maximizing production from older,
previously produced fields acquired from third parties.
In November 2005, we announced our intent to explore the sale of our Gulf of Mexico assets and to
shift our operating focus onshore. On February 28, 2006, we announced the pending sale,
subject to customary closing
conditions, of the Texas portion of these assets. The sale process
with respect to our remaining Gulf of Mexico assets is ongoing and if
a sale is not consummated,
we expect to continue to operate and may
consider other strategic alternatives with respect to these assets.
As of December 31, 2005, we held interests in 136 blocks in federal and state waters, of which 78
were developed. As of December 31, 2005, we operated 45 of our developed blocks, which accounted
for approximately 80% of our offshore production during 2005. We had a total of 97 producing
platforms and production caissons, of which we operated 61. At December 31, 2005, we held
interests in 70 blocks in offshore Texas state and federal waters, of which 33 were developed. Our
Texas assets included 38 producing platforms and production caissons. During 2005, production from
our Gulf of Mexico properties comprised approximately 40% of our total production, averaging 125
MMcfe per day and was significantly curtailed during the last four months of 2005 as a result of
Hurricanes Katrina and Rita that hit the Louisiana and Texas Gulf coasts in August and September
2005.
-5-
Arkoma Basin. Our Arkoma Basin properties are located in two primary areas: the
Chismville/Massard Field located in Logan and Sebastian Counties of Arkansas and the Wilburton and
South Panola Fields located in Latimer County, Oklahoma. At December 31, 2005, we had
approximately 37,200 net acres under lease and we owned working interests in 411 producing natural
gas wells, 289 of which we operated. Wells average a depth of 5,500 feet and production is from
the Atoka formation. Beginning in 2003, we significantly increased our developmental drilling
program with the expansion of in-field drilling opportunities as a result of a series of
downspacing initiatives authorized by the Arkansas Oil and Gas Commission, first in September 2002
from 640 acres per well to 160 acres per well, again in September 2003 from 160 acres to 80 acres
per well, and finally in December 2004 to approximately 40 acres per well. During 2005, average
daily production increased by 13% from 38 MMcfe per day during 2004 to 43 MMcfe per day during
2005. Acquisition opportunities have been scarce or limited in the Arkoma Basin during 2005 and
2004 and, as a result, our current activities are focused on the substantial number of in-field
drilling opportunities within our existing acreage. During 2006, we plan to continue our in-field
drilling program with three rigs drilling during the year. In addition, during the fourth quarter
of 2005, we participated with a 40% working interest in a 13,000 foot exploration well that is
preparing to test Atoka sands.
East Texas. During 2005, we expanded our existing operations and reserve base located in the
Willow Springs Field in Gregg County, Texas through a series of three acquisitions totaling a $38.7
million where we added approximately 37.5 Bcfe in proved reserves. We purchased interests in
producing properties and undeveloped acreage in the South Oak Hill Field located in Rusk County and
the North Blocker Field in Harrison County. We began drilling within two months of the initial
acquisition of these properties in March 2005, and successfully drilled and completed 16 of 16 new
wells, adding approximately 13 Bcfe in proved reserves, and increased our average daily production
from 2 MMcfe per day in January 2005 to 8 MMcfe per day in December 2005. At December 31, 2005, we
had two rigs drilling and owned interests in 49 natural gas wells and
three oil wells. We operated
48 of the natural gas wells and all three of the oil wells. Our average working interest in all
52 wells was 80%.
Rocky Mountains. Our Rocky Mountain properties are located in the Uinta Basin of Northeastern Utah
and the DJ Basin in Eastern Colorado. At December 31, 2005, we had accumulated more than 566,000
net acres with estimated net proved reserves of 27 Bcfe. During 2005, production from our Rocky
Mountain properties averaged approximately 5 MMcfe per day, net to our interests.
During 2005, we continued proving up and delineating portions of our Uinta Basin acreage where we
actively began drilling during 2004. As part of this effort, we partnered with two different
groups in an effort to both optimize our capital utilization and accelerate our exploration efforts
in that area. We drilled or participated in the drilling of a total of 36 wells, of which 30, or
83%, were successful. As in the previous year, during 2005, we experienced delays in bringing new
production on-line, primarily due to difficulties in obtaining pipeline right-of-ways. At December
31, 2005, 12 of our newly completed Uinta wells were shut-in and awaiting approvals for pipeline
right-of-ways.
In the DJ Basin, we expanded our exploration efforts along the Niobrara Trend and drilled 107
wells, successfully completing 98, or 92%. We added approximately 18 Bcfe from drilling, with
first production in mid-July 2005. A second gathering system was completed in January 2006.
Subsequent to December 31, 2005, 30 of the 50 wells shut-in at year-end waiting connection to the
gathering system commenced production, adding approximately 2.4 MMcfe per day in new production,
net to our interest. For 2006, we plan to continue exploration and development programs in both the
Uinta and the DJ Basins in an effort to expand the known producing areas and to test new ideas.
Other. As of December 31, 2005, other primarily represents interests in one field in Central
Mississippi. The Oakvale Dome Field is located in Jefferson Davis County and has two producing
wells, both of which are non-operated. Production averaged approximately 1 MMcfe/day during 2005.
Our interests in the Oakvale Dome Field together with interests in the Wausau Field, located in
Wayne County Mississippi, were acquired in October 2004 as part of our acquisition of 10 offshore
blocks in the shallow waters of the Central Gulf of Mexico. We sold our interest in the Wausau
Field during 2005. In addition to our interests in the Oakvale Dome Field, we have interests or
rights of an immaterial nature in other prospective properties or projects with respect to which no
reserves are currently associated, and may make future investments of immaterial amounts in similar
such projects from time to time in the future.
-6-
Natural Gas and Oil Reserves
The following table summarizes the estimates of our historical net proved reserves as of December
31, 2005, 2004 and 2003, and the present values attributable to those reserves at those dates. For
the year ended December 31, 2005, the reserve data and present values were fully engineered by
independent petroleum engineering consultants Netherland, Sewell & Associates, Inc. For the years
ended December 31, 2004 and 2003, reserve data and present values were fully engineered by two
independent petroleum engineering firms: Netherland, Sewell & Associates, Inc. and Miller and
Lents, Ltd., with each evaluating approximately 80% and 20%, respectively, of the total reserve
quantities during 2004 and 75% and 25%, respectively, during 2003.
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As of December 31, |
Net Proved Reserves: |
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2005(1) |
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2004 |
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2003 |
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(in thousands) |
Natural gas (MMcf) |
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793,074 |
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749,114 |
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709,883 |
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Oil and natural gas liquids (MBbls) |
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11,291 |
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7,335 |
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7,481 |
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Total (MMcfe) |
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860,820 |
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793,124 |
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754,769 |
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Standardized measure of discounted future net cash flows (2) |
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$ |
1,967,024 |
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$ |
1,440,055 |
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$ |
1,504,406 |
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(1) |
|
At December 31, 2005, net proved reserves attributable to our Gulf of Mexico
assets totaled 244,596 MMcfe and included 196,488 MMcf of natural gas and 8,018 MBbls of
oil and natural gas liquids. The pending sale of the Texas portion of our Gulf of Mexico
assets represents approximately 58,463 MMcfe and includes 54,728 MMcf of natural gas and
622.5 MBbls of oil and natural gas liquids. |
|
(2) |
|
The standardized measure of discounted future net cash flows has been calculated
in accordance with SFAS 69, Disclosures About Oil and Gas Producing Activities (see Note
12 Supplemental Information on Natural Gas and Oil Exploration, Development and
Production Activities (Unaudited)) and, in accordance with current SEC guidelines, does
not include estimated future cash flows from our hedging program. Year-end prices per Mcf
of natural gas used in making the standardized measure determinations as of December 31, 2005,
2004 and 2003 were $8.15, $5.68 and $5.79, respectively. Year-end prices per Bbl of oil
used in making the standardized measure determinations as of December 31, 2005, 2004 and
2003 were $53.27, $41.67 and $30.27, respectively. |
In accordance with applicable requirements of the SEC, we estimate net proved reserves and future
net revenues using sales prices estimated to be in effect as of the date we make the reserve
estimates. Sales price estimates are held constant throughout the life of the properties, except to
the extent a contract specifically provides for escalation. Natural gas and oil prices have
fluctuated widely in recent years and volatility is expected to continue. Future prices and costs
may be materially higher or lower than prices and costs as of the date of any estimate. Price
fluctuations will directly affect estimated quantities of proved reserves and future net revenues.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in
projecting future rates of production and timing of development expenditures, including many
factors beyond our control.
The reserve data contained in this Annual Report represent only estimates. Reservoir engineering
is a complex and subjective process of estimating underground accumulations of natural gas and oil
that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of
the quality of available data and of engineering and geological interpretation and judgment. As a
result, estimates prepared by one engineer may vary from those prepared by another. Estimates are
subject to revision based on numerous factors including reservoir performance, prices and economic
conditions. In addition, results of drilling, testing and actual production subsequent to the date
of estimate may justify revision of that estimate. Revisions to prior estimates may be material.
Reserve estimates are often different from the quantities of natural gas and oil that we are
ultimately able to recover and are highly dependent upon the accuracy of the underlying
assumptions. Our estimated proved reserves have not been filed with or included in reports to any
federal agency. See Item 1A. Risk Factors Estimates of proved reserves and future net revenues
may change if the assumptions on which such estimates are based prove to be inaccurate.
-7-
Drilling Activity
We engage in numerous drilling activities on properties presently owned by us and intend to drill
or develop other properties we may acquire in the future. The following table sets forth the
results of our drilling activities for the years ended December 31, 2005, 2004 and 2003. Gross
wells are the sum of all wells in which we owned an interest. Net wells are the sum of our working
interests in the gross wells.
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory Wells |
|
|
Development Wells |
|
|
Total Wells |
|
|
|
Successful |
|
|
Dry |
|
|
Successful |
|
|
Dry |
|
|
Successful |
|
|
Dry |
|
|
Total |
|
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South Texas |
|
|
1 |
|
|
|
1.0 |
|
|
|
|
|
|
|
|
|
|
|
81 |
|
|
|
79.8 |
|
|
|
13 |
|
|
|
13.0 |
|
|
|
82 |
|
|
|
80.8 |
|
|
|
13 |
|
|
|
13.0 |
|
|
|
95 |
|
|
|
93.8 |
|
Arkoma Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
60 |
|
|
|
36.8 |
|
|
|
1 |
|
|
|
0.8 |
|
|
|
60 |
|
|
|
36.8 |
|
|
|
1 |
|
|
|
0.8 |
|
|
|
61 |
|
|
|
37.6 |
|
East Texas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16 |
|
|
|
16.0 |
|
|
|
|
|
|
|
|
|
|
|
16 |
|
|
|
16.0 |
|
|
|
|
|
|
|
|
|
|
|
16 |
|
|
|
16.0 |
|
Rocky Mountains |
|
|
128 |
|
|
|
96.4 |
|
|
|
21 |
|
|
|
15.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
128 |
|
|
|
96.4 |
|
|
|
21 |
|
|
|
15.7 |
|
|
|
149 |
|
|
|
112.1 |
|
Gulf of Mexico |
|
|
5 |
|
|
|
2.4 |
|
|
|
2 |
|
|
|
1.3 |
|
|
|
7 |
|
|
|
6.1 |
|
|
|
1 |
|
|
|
0.5 |
|
|
|
12 |
|
|
|
8.5 |
|
|
|
3 |
|
|
|
1.8 |
|
|
|
15 |
|
|
|
10.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total areas 2005 |
|
|
134 |
|
|
|
99.8 |
|
|
|
23 |
|
|
|
17.0 |
|
|
|
164 |
|
|
|
138.7 |
|
|
|
15 |
|
|
|
14.3 |
|
|
|
298 |
|
|
|
238.5 |
|
|
|
38 |
|
|
|
31.3 |
|
|
|
336 |
|
|
|
269.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South Texas |
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
1.0 |
|
|
|
56 |
|
|
|
54.6 |
|
|
|
19 |
|
|
|
18.0 |
|
|
|
56 |
|
|
|
54.6 |
|
|
|
20 |
|
|
|
19.0 |
|
|
|
76 |
|
|
|
73.6 |
|
Arkoma Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
73 |
|
|
|
45.8 |
|
|
|
6 |
|
|
|
3.0 |
|
|
|
73 |
|
|
|
45.8 |
|
|
|
6 |
|
|
|
3.0 |
|
|
|
79 |
|
|
|
48.8 |
|
Rocky Mountains |
|
|
26 |
|
|
|
25.4 |
|
|
|
3 |
|
|
|
2.3 |
|
|
|
2 |
|
|
|
2.0 |
|
|
|
|
|
|
|
|
|
|
|
28 |
|
|
|
27.4 |
|
|
|
3 |
|
|
|
2.3 |
|
|
|
31 |
|
|
|
29.7 |
|
Other |
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
0.5 |
|
|
|
5 |
|
|
|
5.0 |
|
|
|
|
|
|
|
|
|
|
|
5 |
|
|
|
5.0 |
|
|
|
1 |
|
|
|
0.5 |
|
|
|
6 |
|
|
|
5.5 |
|
Gulf of Mexico |
|
|
3 |
|
|
|
1.4 |
|
|
|
4 |
|
|
|
2.2 |
|
|
|
12 |
|
|
|
9.3 |
|
|
|
|
|
|
|
|
|
|
|
15 |
|
|
|
10.7 |
|
|
|
4 |
|
|
|
2.2 |
|
|
|
19 |
|
|
|
12.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total areas 2004 |
|
|
29 |
|
|
|
26.8 |
|
|
|
9 |
|
|
|
6.0 |
|
|
|
148 |
|
|
|
116.7 |
|
|
|
25 |
|
|
|
21.0 |
|
|
|
177 |
|
|
|
143.5 |
|
|
|
34 |
|
|
|
27.0 |
|
|
|
211 |
|
|
|
170.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South Texas |
|
|
3 |
|
|
|
3.0 |
|
|
|
3 |
|
|
|
3.0 |
|
|
|
53 |
|
|
|
51.3 |
|
|
|
18 |
|
|
|
17.5 |
|
|
|
56 |
|
|
|
54.3 |
|
|
|
21 |
|
|
|
20.5 |
|
|
|
77 |
|
|
|
74.8 |
|
Arkoma Basin |
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
0.4 |
|
|
|
46 |
|
|
|
28.6 |
|
|
|
4 |
|
|
|
2.5 |
|
|
|
46 |
|
|
|
28.6 |
|
|
|
5 |
|
|
|
2.9 |
|
|
|
51 |
|
|
|
31.5 |
|
Other onshore |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
2.0 |
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
2.0 |
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
2.0 |
|
Gulf of Mexico |
|
|
6 |
|
|
|
2.4 |
|
|
|
8 |
|
|
|
3.6 |
|
|
|
3 |
|
|
|
2.0 |
|
|
|
|
|
|
|
|
|
|
|
9 |
|
|
|
4.4 |
|
|
|
8 |
|
|
|
3.6 |
|
|
|
17 |
|
|
|
8.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total areas 2003 |
|
|
9 |
|
|
|
5.4 |
|
|
|
12 |
|
|
|
7.0 |
|
|
|
104 |
|
|
|
83.9 |
|
|
|
22 |
|
|
|
20.0 |
|
|
|
113 |
|
|
|
89.3 |
|
|
|
34 |
|
|
|
27.0 |
|
|
|
147 |
|
|
|
116.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2005, we were drilling or participating in the drilling of 13 gross (8.86 net)
wells. Of these wells, through March 1, 2006, 9 gross (7.0 net) wells have been determined to be
successful, with the remaining 4 gross (1.8 net) wells still in progress as of the date of our
Annual Report.
Productive Wells
The following table sets forth the number of productive wells in which we owned an interest as of
December 31, 2005. Productive wells consist of producing wells and wells capable of production,
including 62 wells located in the Rocky Mountains (50 in the DJ Basin and 12 in Uinta), awaiting
connections at December 31, 2005. Wells that are completed in more than one producing horizon are
counted as one well. As operator, we are designated the party under the terms of an operating
agreement that manages the day-to-day operations of the well.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2005 |
|
|
|
Natural Gas Wells |
|
|
Oil Wells |
|
|
Total Wells |
|
|
|
Operated |
|
|
Non-Operated |
|
|
Operated |
|
|
Non-Operated |
|
|
|
|
|
|
|
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
South Texas |
|
|
743 |
|
|
|
707.8 |
|
|
|
108 |
|
|
|
14.9 |
|
|
|
21 |
|
|
|
12.4 |
|
|
|
|
|
|
|
|
|
|
|
872 |
|
|
|
735.1 |
|
Arkoma Basin |
|
|
289 |
|
|
|
197.1 |
|
|
|
122 |
|
|
|
26.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
411 |
|
|
|
223.2 |
|
East Texas |
|
|
48 |
|
|
|
38.7 |
|
|
|
1 |
|
|
|
0.4 |
|
|
|
3 |
|
|
|
2.2 |
|
|
|
|
|
|
|
|
|
|
|
52 |
|
|
|
41.3 |
|
Rocky Mountains |
|
|
117 |
|
|
|
96.2 |
|
|
|
42 |
|
|
|
21.0 |
|
|
|
2 |
|
|
|
1.0 |
|
|
|
|
|
|
|
|
|
|
|
161 |
|
|
|
118.2 |
|
Other |
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
1.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
1.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total onshore |
|
|
1,197 |
|
|
|
1,039.8 |
|
|
|
275 |
|
|
|
63.5 |
|
|
|
26 |
|
|
|
15.6 |
|
|
|
|
|
|
|
|
|
|
|
1,498 |
|
|
|
1,118.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf of Mexico |
|
|
91 |
|
|
|
71.9 |
|
|
|
54 |
|
|
|
15.4 |
|
|
|
18 |
|
|
|
14.1 |
|
|
|
6 |
|
|
|
0.9 |
|
|
|
169 |
|
|
|
102.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
1,288 |
|
|
|
1,111.7 |
|
|
|
329 |
|
|
|
78.9 |
|
|
|
44 |
|
|
|
29.7 |
|
|
|
6 |
|
|
|
0.9 |
|
|
|
1,667 |
|
|
|
1,221.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-8-
Acreage Data
The following table sets forth the approximate developed and undeveloped acreage in which we held a
leasehold mineral or other interest as of December 31, 2005. 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. Gulf of Mexico acreage includes leases in federal and state waters.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2005 |
|
|
|
Undeveloped |
|
|
Developed |
|
|
Total Acreage |
|
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
South Texas |
|
|
14,606 |
|
|
|
12,978 |
|
|
|
107,299 |
|
|
|
81,672 |
|
|
|
121,905 |
|
|
|
94,650 |
|
Arkoma Basin |
|
|
25,624 |
|
|
|
8,857 |
|
|
|
59,707 |
|
|
|
28,322 |
|
|
|
85,331 |
|
|
|
37,179 |
|
East Texas |
|
|
5,547 |
|
|
|
3,488 |
|
|
|
10,746 |
|
|
|
6,670 |
|
|
|
16,293 |
|
|
|
10,158 |
|
Rocky Mountains |
|
|
703,196 |
|
|
|
543,380 |
|
|
|
41,943 |
|
|
|
22,937 |
|
|
|
745,139 |
|
|
|
566,317 |
|
Other onshore |
|
|
|
|
|
|
|
|
|
|
1,740 |
|
|
|
620 |
|
|
|
1,740 |
|
|
|
620 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total onshore |
|
|
748,973 |
|
|
|
568,703 |
|
|
|
221,435 |
|
|
|
140,221 |
|
|
|
970,408 |
|
|
|
708,924 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf of Mexico |
|
|
227,062 |
|
|
|
159,521 |
|
|
|
314,886 |
|
|
|
200,926 |
|
|
|
541,948 |
|
|
|
360,447 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
976,035 |
|
|
|
728,224 |
|
|
|
536,321 |
|
|
|
341,147 |
|
|
|
1,512,356 |
|
|
|
1,069,371 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Undeveloped Acreage Expirations
The table below summarizes by year and area our undeveloped acreage scheduled to expire in the next
five years.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2005 |
|
|
|
2006 |
|
|
2007 |
|
|
2008 |
|
|
2009 |
|
|
2010 |
|
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
South Texas |
|
|
3,686 |
|
|
|
3,064 |
|
|
|
5,399 |
|
|
|
5,240 |
|
|
|
1,111 |
|
|
|
1,076 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Arkoma Basin |
|
|
|
|
|
|
|
|
|
|
2,816 |
|
|
|
932 |
|
|
|
|
|
|
|
|
|
|
|
614 |
|
|
|
238 |
|
|
|
4,088 |
|
|
|
1,154 |
|
East Texas |
|
|
|
|
|
|
|
|
|
|
3,592 |
|
|
|
2,734 |
|
|
|
60 |
|
|
|
40 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rocky Mountains |
|
|
193,559 |
|
|
|
129,257 |
|
|
|
110,287 |
|
|
|
84,391 |
|
|
|
150,362 |
|
|
|
120,943 |
|
|
|
35,399 |
|
|
|
27,213 |
|
|
|
16,171 |
|
|
|
5,713 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total onshore |
|
|
197,245 |
|
|
|
132,321 |
|
|
|
122,094 |
|
|
|
93,297 |
|
|
|
151,533 |
|
|
|
122,059 |
|
|
|
36,013 |
|
|
|
27,451 |
|
|
|
20,259 |
|
|
|
6,867 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf of Mexico |
|
|
32,257 |
|
|
|
24,897 |
|
|
|
46,181 |
|
|
|
37,921 |
|
|
|
62,824 |
|
|
|
34,756 |
|
|
|
42,280 |
|
|
|
26,324 |
|
|
|
15,000 |
|
|
|
12,500 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
229,502 |
|
|
|
157,218 |
|
|
|
168,275 |
|
|
|
131,218 |
|
|
|
214,357 |
|
|
|
156,815 |
|
|
|
78,293 |
|
|
|
53,775 |
|
|
|
35,259 |
|
|
|
19,367 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketing and Customers
We market the majority of the natural gas and oil production from properties we operate for both
our account and the account of the other working interest owners in these properties. We typically
sell a substantial portion of our production under short-term (usually one-month) contracts tied to
a local index. We do not have any material long-term, fixed price sales contracts. The remaining
portion of our production is sold on a daily basis into local spot markets in order to accommodate
fluctuations in daily production volumes. We normally sell production to a relatively small number
of customers, as is customary in the exploration, development and production business. However,
based on the current demand for natural gas and oil, we believe that the loss of any one or all of
our major purchasers would not have a material adverse effect on our financial condition and
results of operations. For a list of our purchasers that accounted for 10% or more of our natural
gas and oil revenues during the preceding last three calendar years, see Notes to Consolidated
Financial Statements Note 8 Sales to Major Customers.
We enter into hedging transactions with unaffiliated third parties for significant portions of our
natural gas production. For a more detailed discussion, see Item 7. Managements Discussion and
Analysis of Financial Condition and Results of Operations and Item 7A. Quantitative and
Qualitative Disclosures About Market Risk.
We incur gathering and transportation expenses to move our natural gas from the wellhead to a
purchaser-specified delivery point. These expenses vary based on the volume and distance shipped,
and the fee charged by the third party transporter. We do not have any material transportation
agreements and we have not contracted for firm capacity for which we would pay monthly demand
charges. Our natural gas and oil are transported through third party gathering systems and
pipelines.
-9-
Transportation space on these gathering systems and pipelines is occasionally limited and at times
unavailable because of repairs or improvements, or as a result of priority transportation
agreements with other gas shippers. While our ability to market our natural gas has only been
infrequently limited or delayed, if transportation space is restricted or is unavailable, our cash
flow from the affected properties could be adversely affected. See the section entitled Item 1A.
Risk Factors Our business depends on oil and natural gas transportation facilities that are
owned by others.
Title to Properties
As is customary in the oil and gas industry, we initially conduct only a cursory review of the
title to undeveloped acreage in farm-out agreements and natural gas and oil leases. Prior to the
commencement of drilling operations, we conduct a thorough title examination and perform curative
work with respect to significant defects. To the extent title opinions or other investigations
reflect title defects, we, rather than the seller/lessor of the undeveloped property, are typically
responsible for curing any title defects at our expense. If we were unable to remedy or cure any
title defect of a nature such that it would not be prudent to commence drilling operations on the
property, we could suffer a loss of our entire investment in the property. Prior to completing an
acquisition of producing natural gas and oil leases, we perform title reviews on the most
significant leases and, depending on the materiality of properties, we may obtain a title opinion.
Our natural gas and oil properties are subject to customary royalty and other interests, liens for
current taxes and other burdens which we believe do not materially interfere with the use of or
affect our carrying value of the properties.
Competition
We encounter intense competition from other oil and gas companies in all areas of our operations,
including the acquisition of additional properties and acreage. This competition has intensified
in response to rising natural gas price levels and the natural maturation of several of our key
fields. Our competitors include major integrated oil and gas companies and numerous independent
oil and gas companies, individuals and drilling and income programs. Many of our competitors are
large, well-established companies with substantially greater capital resources than our own. Our
ability to acquire additional properties and to discover new reserves in the future will depend on
our ability to evaluate and select suitable properties and to consummate transactions in this
highly competitive environment. See Item 1A. Risk Factors We face strong competition.
Seasonal Nature of Business
Generally, but not always, the demand for natural gas increases during the winter months as a
result of heating applications and decreases during the summer months. Seasonal anomalies such as
mild winters or cool summers sometimes lessen this fluctuation. In addition, as the industrial use
of natural gas has expanded in recent years, weather related demand and seasonal fluctuations are
diminishing. However, seasonal weather conditions, such as recent severe tropical storms and
hurricanes in the Gulf of Mexico and winter weather in the Rocky Mountain region can pose
challenges for meeting our well drilling and production objectives.
Employees
As of December 31, 2005, we had 167 full time employees, 134 of whom are located at our
headquarters in Houston, Texas and the remainder of whom are located in our South Texas, Arkansas,
Denver and East Texas field offices. None of our employees are represented by a labor union or
other collective bargaining arrangement. We employ the services of independent consultants and
contractors to perform various professional services, particularly in the areas of construction,
design and well-site surveillance, permitting and environmental assessment. At our direction,
independent contractors usually perform field and on-site production operation services, including
pumping, maintenance, dispatching, inspection and testing.
Offices
Our corporate offices are located at 1100 Louisiana Street, Suite 2000, Houston, Texas 77002. Our
telephone number is (713) 830-6800. We maintain field operations and other offices in South Texas,
Arkansas, East Texas and Alabama. We currently lease approximately 114,000 square feet of office
space in Houston, Texas, at 1100 Louisiana Street, where our principal offices are located. We
lease approximately 2,250 square feet of office space in Denver, Colorado, at 700 17th
Street.
Regulation
The oil and gas industry is extensively regulated by numerous federal, state and local authorities,
including Native American tribes. Legislation affecting the oil and gas industry is under constant
review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous
departments and agencies, both federal and state, and Native
-10-
American tribes are authorized by statute to issue rules and regulations binding on the oil and gas
industry and its individual members, some of which carry substantial penalties for failure to
comply. Although the regulatory burden on the oil and gas industry increases our cost of doing
business and, consequently, affects our profitability, generally, these burdens do not appear to
materially affect us any differently or to any greater or lesser extent than they affect other
companies in the industry with similar types, quantities and locations of production.
Drilling and Production. Our operations are subject to various types of regulation at federal,
state and local levels. These types of regulation include requiring permits for the drilling of
wells, drilling bonds and reports concerning operations. Most states, and some counties,
municipalities and Native American tribes, in which we operate also regulate one or more of the
following:
|
§ |
|
the location of wells; |
|
|
§ |
|
the method of drilling and casing wells; |
|
|
§ |
|
the rates of production or allowables; |
|
|
§ |
|
the surface use and restoration of properties upon which wells are drilled; and |
|
|
§ |
|
the plugging and abandoning of wells. |
State laws regulate the size and shape of drilling and spacing units or proration units governing
the pooling of oil and gas properties. Some states allow forced pooling or integration of tracts to
facilitate exploration while other states rely on voluntary pooling of lands and leases. In some
instances, forced pooling or unitization may be implemented by third parties and may reduce our
interest in the unitized properties. In addition, state conservation laws establish maximum rates
of production from oil and gas wells, generally prohibit the venting or flaring of natural gas and
impose requirements regarding the ratability of production. These laws and regulations may limit
the amount of oil and gas we can produce from our wells or limit the number of wells or the
locations at which we can drill. Our properties located in federal waters are regulated by the
Minerals Management Service and are not subject to regulation by state agencies.
We conduct our operations in the Gulf of Mexico on oil and natural gas leases that are granted by the
U.S. federal government and are administered by the Minerals Management Service. The Minerals
Management Service issues leases through competitive bidding. The lease contracts contain
relatively standardized terms and require compliance with detailed regulations of the Minerals
Management Service. For offshore operations, lessees must obtain Minerals Management Service
approval for exploration plans and development and production plans prior to the commencement of
the operations. In addition to permits required from other agencies, such as the Coast Guard, the
Army Corps of Engineers and the Environmental Protection Agency, lessees must obtain a permit from
the Minerals Management Service prior to the commencement of drilling. In certain instances,
substantial Certificates of Financial Responsibility or other acceptable assurances must be
provided and maintained under the federal Oil Pollution Act of 1990.
The Minerals Management Service promulgates and enforces regulations that require offshore
production facilities located on the Outer Continental Shelf to meet stringent engineering,
construction, and safety specifications, that impose strong restrictions on the flaring or venting
of natural gas, that prohibit the burning of liquid hydrocarbons and oil without prior
authorization, and that govern the plugging and abandonment of offshore wells and removal of
offshore production facilities. To cover the various obligations of lessees on the Outer
Continental Shelf, the Minerals Management Service generally requires that lessees post and
maintain substantial bonds or other acceptable assurances that these obligations will be met. The
Outer Continental Shelf Lands Act may generally impose liabilities on us for our offshore
operations conducted on federal leases for clean-up costs and damages caused by pollution resulting
from our operations. Under circumstances such as conditions deemed to be a threat or harm to the
environment, the Minerals Management Service may suspend or terminate any of our operations in the
affected area.
Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls
have affected the price of the natural gas we produce and the manner in which we market our
production. The Federal Energy Regulatory Commission, or FERC, has jurisdiction over the
transportation and sale for resale of natural gas in interstate commerce by natural gas companies
under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various
federal laws have been enacted which have resulted in the complete removal of all price and
non-price controls for sales of domestic natural gas sold in first sales, which include all of
our sales of our own production.
FERC also regulates interstate natural gas transportation rates and service conditions, which
affects the marketing of natural gas that we produce, as well as the revenues we receive for sales
of our natural gas. Commencing in 1985, FERC
-11-
promulgated a series of orders, regulations and rule makings that significantly fostered
competition in the business of transporting and marketing gas. Today, interstate pipeline companies
are required to provide nondiscriminatory transportation services to producers, marketers and other
shippers, regardless of whether such shippers are affiliated with an interstate pipeline company.
FERCs initiatives have led to the development of a competitive, open access market for gas
purchases and sales that permits all purchasers of gas to buy gas directly from third party sellers
other than pipelines. However, the natural gas industry historically has been very heavily
regulated; therefore, we cannot guarantee that the current regulatory approach will continue
indefinitely into the future nor can we determine what affect, if any, future regulatory changes
might have on our natural gas related activities.
Under FERCs current regulatory regime, interstate transmission services must be provided on an
open-access, non-discriminatory basis at cost-based rates or at market-based rates if the
transportation market at issue is sufficiently competitive. Gathering service, which occurs
upstream of jurisdictional transmission services, is regulated by the states onshore and in state
waters. In offshore Federal waters, the Outer Continental Shelf Lands Act requires every permit or
other grant of authority for the transportation of oil or gas by pipeline on or across the Outer
Continental Shelf to require the pipeline to provide open and nondiscriminatory access, but does
not authorized FERC to create and enforce open access rules or to regulate rates for gathering on
the Outer Continental Shelf. The lack of federal oversight over the rates charged for gathering on
the Outer Continental Shelf affects our costs of getting the gas we produce on the Outer
Continental Shelf to point-of-sale locations.
Environmental Matters and Regulation
General. Our operations are subject to and must comply with the same federal, state and local laws
and regulations governing the discharge of materials into the environment or otherwise relating to
environmental protection as other companies in the oil and gas exploration and production industry.
These laws and regulations may:
|
§ |
|
require the acquisition of a permit before drilling commences; |
|
|
§ |
|
require the installation of expensive pollution control measures; |
|
|
§ |
|
restrict the types, quantities and concentration of various substances that can
be released into the environment in connection with drilling and production activities; |
|
|
§ |
|
limit or prohibit drilling activities on lands lying within wilderness, wetlands
and other protected areas; |
|
|
§ |
|
require remedial measures to prevent pollution from former operations, such as
pit closure and plugging of abandoned wells; and |
|
|
§ |
|
impose substantial liabilities for pollution resulting from our operations. |
These laws, rules and regulations may also restrict the rate of oil and natural gas production
below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry
increases the cost of doing business in the industry and consequently affects profitability.
Additionally, Congress and the federal and state agencies frequently revise the environmental laws
and regulations. Any changes that result in more stringent and costly waste handling, disposal and
clean-up requirements could have a significant impact on the oil and gas industrys operating
costs, including ours. We believe that we substantially comply with all current applicable
environmental laws and regulations and that our continued compliance with existing requirements
will not have a material adverse impact on our financial condition and results of operations.
However, we cannot predict the passage of or quantify the potential impact of more stringent future
laws and regulations at this time. For the year ended December 31, 2005, we did not incur any
material capital expenditures for environmental control facilities. As of the date of our Annual
Report, we are not aware of any environmental issues or claims that will require material
expenditures during 2006 and 2007 or that will have a material impact on our financial position or
results of operations.
-12-
The most significant of these environmental laws and regulations include, among others, the:
Resource Conservation and Recovery Act. The Resource Conservation and Recovery Act, or RCRA,
affects oil and gas production activities by imposing regulations on the generation,
transportation, treatment, storage, disposal and cleanup of hazardous wastes and on the disposal
of non-hazardous wastes. Under the auspices of the Environmental Protection Agency, or the EPA, the
individual states administer some or all of the provisions of the Resource Conservation and
Recovery Act, sometimes in conjunction with their own, more stringent requirements. Drilling
fluids, produced waters, and most of the other wastes associated with the exploration, development,
and production of crude oil, natural gas, or geothermal energy constitute solid wastes, which are
regulated under the less stringent non-hazardous waste provisions, but there is no guarantee that
the EPA or the individual states will not adopt more stringent requirements for the handling of
non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation.
Indeed, legislation has been proposed from time to time in Congress to recategorize certain oil and
gas exploration and production wastes as hazardous wastes.
We believe that we are currently in substantial compliance with the requirements of the Resource
Conservation and Recovery Act and related state and local laws and regulations and that we hold all
necessary and up-to-date permits, registrations and other authorizations to the extent that our
operations require them under the Resource Conservation and Recovery Act.
Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive
Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund
law, imposes joint and several liability, without regard to fault or legality of conduct, on
classes of persons who are considered to be responsible for the release of a hazardous substance
into the environment. These persons include the owner or operator of the disposal site, or site
where the release occurred and companies that disposed or arranged for the disposal of the
hazardous substance. CERCLA also authorizes the EPA and affected parties to respond to threats to
the public health or the environment and to seek recovery from responsible classes of persons for
the costs of the response actions.
In the course of our operations, we generate wastes that may fall within CERCLAs definition of
hazardous substances. Therefore, governmental agencies or third parties may seek to hold us
responsible under CERCLA for all or part of the costs to clean up sites at which such hazardous
substances have been deposited. As of the date of our report, however, we have no knowledge of
having been named by the EPA or alleged by any third party as being responsible for costs and
liability associated with alleged releases of any hazardous substance at any superfund site.
Oil Pollution Act. The Oil Pollution Act imposes on responsible parties strict, joint and several,
and potentially unlimited liability for removal costs and other damages caused by an oil spill
covered by the Oil Pollution Act and offers few defenses to such liability. The Oil Pollution Act
also requires the lessee of an offshore area or a permittee whose operations take place within a
covered offshore facility to establish and maintain financial responsibility of at least $35
million, which may be increased to $150 million for facilities with large worst-case spill
potentials and under other circumstances, to cover liabilities related to an oil spill for which
the lessee or permittee of the offshore area is statutorily responsible. Owners of multiple
facilities are required to maintain financial responsibility for only the facility with the largest
potential worst-case spill. We have received certification from the Minerals Management Service
that due to our financial status, we are able to cover a minimum of $35 million per occurrence and
because we do not have major oil producing facilities, the maximum certification of $150 million in
coverage is not currently required. As such, we currently believe we are in substantial compliance
with the financial responsibility provisions of the Oil Pollution Act. If we completely divest our
Gulf of Mexico assets, we would no longer be subject to the provisions of the Oil Pollution Act.
Federal Water Pollution Control Act/Clean Water Act. The Federal Water Pollution Control Act or
Clean Water Act and related state laws provide varying civil and criminal penalties and liabilities
for the unauthorized discharge of petroleum products and other pollutants to surface waters. The
federal discharge permitting program also prohibits the discharge of produced water, sand and other
substances related to the oil and gas industry to coastal waters. Regulations governing water
discharges also impose other requirements, such as the obligation to prepare spill response plans.
We currently believe that we are in substantial compliance with all pollutant, wastewater, and
stormwater discharge regulations and that we hold all necessary and valid permits, other required
authorizations, and spill response plans for the discharge of such materials from our operations.
Federal Clean Air Act. The Federal Clean Air Act restricts the emission of air pollutants and
affects both onshore and offshore oil and gas operations. New facilities may be required to obtain
permits before work can begin, and existing facilities may be required to incur capital costs in
order to remain in compliance. In addition, EPA has developed and continues to develop more
stringent regulations governing emissions of toxic air pollutants. These regulations may
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increase the costs of compliance for some facilities. We currently believe that we are in
substantial compliance with all air emissions regulations and that we hold all necessary and valid
construction and operating permits for our operations.
In 1997, numerous countries participated in an international conference under the United Nations
Framework Convention on Climate Change and concluded an agreement, known as the Kyoto Protocol.
The Protocol became effective February 14, 2005, and will require reductions of certain emissions
that contribute to atmospheric levels of greenhouse gases. The United States has not ratified the
Protocol but may in the future. Presently, it is not possible to accurately estimate the costs we
could incur to comply with any laws or regulations developed to achieve such emissions reductions,
but such expenditures could be substantial.
Legislation continues to be introduced in Congress and development of regulations continues in the
Department of Homeland Security and other agencies concerning the security of industrial
facilities, including oil and gas facilities. Our operations may be subject to such laws and
regulations. Presently, it is not possible to accurately estimate the costs we could incur to
comply with any such facility security laws or regulations, but such expenditures could be
substantial.
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Item 1A. Risk Factors
The volatility of natural gas and oil prices may affect our financial results.
As an independent natural gas and oil producer, our revenues, operating results, profitability and
future rate of growth are highly dependent on the price of, and demand for, the natural gas and oil
that we sell. Prices also affect the amount of cash flow available for capital expenditures and our
ability to borrow money or raise additional capital. Even relatively modest changes in natural gas
and oil prices may significantly change our revenues, results of operations, cash flows and proved
reserves.
Historically, the markets for natural gas and oil have been volatile and are likely to continue to
be volatile in the future. Prices for natural gas and oil may fluctuate widely in response to
relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty
and a variety of additional factors that are beyond our control, such as:
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the domestic and foreign supply of natural gas and oil; |
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weather conditions; |
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the price of foreign imports; |
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overall domestic and global economic conditions; |
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terrorist attacks or military conflicts; |
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political and economic conditions in oil producing countries; |
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the ability of members of the Organization of Petroleum Exporting Countries to
agree to and maintain oil price and production controls; |
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the level of demand and the price and availability of alternative fuels; |
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speculation in the commodity futures markets; |
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technological advances affecting energy consumption; |
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domestic and foreign governmental regulations, including regulations imposed by Native American tribes; and |
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approvals, proximity and capacity of natural gas and oil pipelines and other transportation facilities. |
These factors and the volatility of the energy markets make it extremely difficult to predict
future natural gas and oil price movements with any certainty. Declines in natural gas and oil
prices would not only reduce our revenues, but could reduce the amount of natural gas and oil we
can economically produce. This may result in our having to make substantial downward adjustments
to our estimated proved reserves and could have a material adverse effect on our financial
condition and results of operations. Further, market prices for natural gas and oil do not
necessarily move in direct relationship to each other. We are more affected by movements in the
price and demand for natural gas, as approximately 92% of our total proved reserves at December 31,
2005 were natural gas.
Our
ability to sell assets and replace revenues generated from any sale of our Gulf of Mexico properties depends
upon market conditions and numerous uncertainties.
In
November 2005, we announced our intent to explore the sale of our Gulf of Mexico assets and to shift our operating focus onshore.
While we have announced the pending sale of the Texas portion of our Gulf of Mexico assets and the sale process for the remaining
offshore assets is ongoing, there can be no assurance that we will
sell our remaining offshore assets. Although we plan to reinvest the proceeds from any sale of our Gulf of Mexico assets in onshore
producing assets, there can be no assurance that we will be able to find suitable properties on
attractive terms. Our operating revenues and cash flows are expected to decrease significantly
following the sale of these assets and are expected to remain at lower levels until we are able to
replace the lost production with production from new properties.
Our level of indebtedness may limit our financial flexibility.
As of December 31, 2005, we had long-term indebtedness of $597 million, with $422 million drawn
under our revolving bank credit facility and $175 million of 7% senior subordinated notes. Our
long-term indebtedness represented 46% of our total book capitalization at December 31, 2005.
As of the date of this Annual Report, outstanding borrowings under
our revolving bank credit facility were $407 million.
Our level of indebtedness affects our operations in several ways, including the following:
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a portion of our cash flows from operating activities must be used to service
our debt and is therefore not available for other purposes; |
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we may be at a competitive disadvantage as compared to similar companies that
have less debt; |
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the covenants contained in the agreements governing our outstanding debt require
us to meet certain financial tests and may limit our ability to borrow additional funds,
sell assets, repurchase shares of company stock, pay dividends |
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and make certain investments and may also affect our flexibility in planning for, and
reacting to, changes in the economy and in our industry; |
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we may not be able to easily divest or exchange our onshore assets because these
assets have been mortgaged to secure borrowings under our revolving bank credit facility; |
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additional financing in the future for working capital, capital expenditures,
acquisitions, general corporate or other purposes may have higher costs and more restrictive
covenants; and, |
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changes in the credit ratings of our debt may negatively affect the cost, terms,
conditions and availability of future financing. |
We may incur additional debt in order to make future acquisitions or develop our properties. A
higher level of indebtedness increases the risk that we may default on our debt obligations. Our
ability to meet our debt service obligations and to reduce our level of indebtedness depends on our
future performance. General economic conditions, commodity prices and financial, business and
other factors affect our operations and our future performance. Many of these factors are beyond
our control. We may not be able to generate sufficient cash flow to pay the interest on our debt,
and future working capital, borrowings or equity financing may not be available to pay or refinance
such debt. Factors that will affect our ability to raise cash through an offering of our stock or
a refinancing of our debt include financial market conditions, the value of our assets and our
performance at the time we need capital.
We may be required to take writedowns if natural gas and oil prices decline.
We may be required under full cost accounting rules to write down the carrying value of our natural
gas and oil properties if natural gas and oil prices decline or if we have substantial downward
adjustments to our estimated proved reserves, increases in our estimates of development costs or
deterioration in our exploration results.
We utilize the full cost method of accounting for natural gas and oil exploration and development
activities. Under full cost accounting, we are required by SEC regulations to perform a ceiling
test each quarter. The ceiling test is an impairment test and generally establishes a maximum, or
ceiling, of the book value of our natural gas and oil properties that is equal to the expected
after tax present value (discounted at 10%) of the future net cash flows from proved reserves,
including the effect of cash flow hedges, calculated using prevailing prices on the last day of the
period. If the net book value of our natural gas and oil properties (reduced by any related net
deferred income tax liability and asset retirement obligation) exceeds our ceiling limitation, SEC
regulations require us to impair or writedown the book value of our natural gas and oil
properties. Depending on the magnitude of any future impairments, a ceiling test writedown could
significantly reduce our income, or produce a loss. As ceiling test computations involve the
prevailing price on the last day of the quarter, it is impossible to predict the timing and
magnitude of any future impairments. The book value of our proved natural gas and oil properties
increased in 2005 as a function of our higher acquisition, exploration and development costs for
the year and the increase in future development costs associated with reserves added during the
year. To the extent our finding and development costs continue to increase as we expect, we will
become more susceptible to ceiling test writedowns in low price environments.
Lower natural gas and oil prices could negatively impact our ability to borrow.
The amount of borrowings available to us under our revolving bank credit facility is
determined by reference to a borrowing base. The amount of our borrowing base is established by
our banks and is primarily a function of the quantity and value of our reserves. Our borrowing
base is re-determined at least twice a year to take into account changes in our reserve base and
prevailing commodity prices. Our current borrowing base is $600 million and is expected to be
reduced upon completion of the pending sale of the Texas portion of our Gulf of Mexico assets and
likely would be reduced further upon any sale of our remaining Gulf of Mexico assets. Commodity prices can
affect both the value as well as the quantity of our reserves for borrowing base purposes as
certain reserves may not be economic at lower price levels. Additionally, the indenture governing
our 7% senior subordinated notes due 2013 conditions our ability to incur additional indebtedness
on our satisfaction of tests relating to earnings before interest, taxes and depreciation,
depletion and amortization expense and consolidated net tangible assets (as defined in the
indenture), both of which are sensitive to commodity prices. Consequently, the amount of borrowing
available to us under our revolving bank credit facility as well as our ability to incur additional
indebtedness without violating the indenture governing our senior subordinated notes could be
adversely affected by extended periods of low commodity prices.
Our hedging activities have resulted in financial losses and reduced our income and may continue to
do so in the future.
To achieve more predictable cash flow and to reduce our exposure to downward fluctuations in the
prices of natural gas, we have historically entered into hedging arrangements for a significant
portion, between 70% and 80%, of our production. As
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of the date of our Annual Report, we have approximately 250 MMBtu per day, or approximately 75% of
our projected 2006 natural gas production hedged and less than 10%, or 30 MMBtu per day and 20
MMBtu per day, respectively, hedged for 2007 and 2008. In connection with the possible divestiture
of our Gulf of Mexico assets, and after taking into account the impact of any such sale on our
production levels and any acquisitions that appear imminent at the time of any such sale, we may
and may be required under our revolving bank credit facility to liquidate a portion of our 2006
hedge position. Specifically, if we were to sell all of our Gulf of Mexico assets, we estimate
that we would liquidate at least 70 MMBtu per day. Depending on prices in effect at the time of
liquidation, we could be required to make a significant payment to settle the open contracts, which
payment we would expect to finance with proceeds from the sale of any Gulf of Mexico assets and/or
borrowings under our revolving bank credit facility.
The derivative instruments that we typically employ require us to make cash payments to the extent
the NYMEX price exceeds a predetermined price, thereby limiting our ability to realize the benefit
of increases in natural gas prices. As we typically tie our derivative instruments to NYMEX prices
as opposed to the local indices where we sell our gas, our hedging strategy may not protect our
cash flows if basis differentials increase between the NYMEX and local prices. Under SFAS 133, our
income could be negatively affected to the extent our NYMEX-based derivative instruments are deemed
ineffective in hedging price fluctuations at our sales points. Historically, our basis
differential between the NYMEX price and the Houston Ship Channel index, where approximately 30% of
our production is hedged, averaged not more than $0.30 per MMBtu. However, market conditions and
extreme price volatility during the fourth quarter of 2005 created in the aftermath of Hurricanes
Katrina and Rita, caused our average basis differential to increase to $2.40 per MMBtu, causing us
to realize significantly lower sales prices for natural gas during the fourth quarter of 2005. In
addition, this extreme widening of the basis differential between NYMEX and Houston Ship Channel
created a loss of correlation. As a result, our hedged production allocated to the Houston Ship
Channel index failed to qualify for hedge accounting. We were required to recognize the change in
the fair value of these contracts during the fourth quarter of 2005 as an unrealized gain of $26.1
million ($16.9 million net of tax) in fourth quarter earnings. In future periods, our earnings
could fluctuate significantly if these contracts can not be re-designated as cash flow hedges as
the mark-to-market changes in the fair value at the end of each future period would be recognized
in the income statement. Further, if we experience a sustained material interruption in our
production, we might be forced to satisfy all or a portion of our hedging obligations without the
benefit of the cash flow from our sale of the underlying physical commodity, resulting in a
substantial reduction in our liquidity as was the case during the fourth quarter of 2005 when
offshore production was significantly curtailed due to Hurricanes Katrina and Rita. Finally,
another risk of hedging activities is that the counterparty in any derivative transaction cannot or
will not perform under the hedge contract and that we will not realize the benefit of the hedge.
The high-rate production characteristics of our properties subject us to high reserve replacement
needs and require significant capital expenditures to replace our reserves at a faster rate than
companies whose reserves have longer-life production profiles.
Our proved reserve quantities decline as they are produced. To prevent decline in our reserve
base, we must conduct successful development, exploitation and exploration activities or acquire
properties containing proved reserves. Producing natural gas and oil reservoirs are generally
characterized by declining production rates that vary depending on reservoir characteristics and
other factors. Virtually all of our onshore production is located in prolific natural gas
producing regions where completion techniques result in hyperbolic production decline profiles
characterized by high initial production rates, followed by rapid intermediate production declines,
and culminating in a long-term low production rate subject to a shallow decline. Likewise, our
offshore production (as to which we are pursuing a sale) is generally characterized by small
reservoirs with high porosity and permeability that produce at very high rates but typically
deplete rapidly. Because of the high-rate production profiles of our properties, replacing
produced reserves is more important for us than for companies whose reserves have longer-life
production profiles. This imposes greater reinvestment risk for our company as we may not be able
to continue to replace our reserves or may not be able to do so at an acceptable finding cost.
Rising finding and development costs may impair our profitability.
In order to continue to grow and to maintain our profitability, we must annually add new reserves
exceeding our yearly production at a finding and development cost that yields an acceptable
operating margin and depreciation, depletion and amortization rate. Without cost effective
exploration, development or acquisition activities, our production, reserves and profitability will
decline over time. Given the relative maturity of most gas basins in North America combined with an
overall increase in the demand for domestic production, the cost of finding new reserves through
exploration and development operations has been increasing. As commodity prices have continued to
remain strong, the costs for materials, equipment and services have increased. The acquisition
market for natural gas properties has become extremely competitive among producers for additional
production and expanded drilling opportunities in North America. Acquisition values on a per unit
basis are at or near record levels in certain areas, particularly in our focus areas of South Texas
and the Rocky Mountain regions, and we believe these values may continue to increase in 2006. For
full cost companies such as
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ours, this increase in finding and development costs results in higher depreciation, depletion and
amortization rates. If finding and development costs continue to increase, we and other full cost
companies will be exposed to an increased likelihood of a writedown in carrying value of our
natural gas and oil properties in response to falling prices, which would impair our profitability.
The success of our business depends upon our ability to find, replace, develop and acquire natural
gas and oil reserves.
Without successful exploration, development or acquisition activities, our oil and gas reserves and
our revenues will decline over time. In addition, we may not be able to maintain our current cost
structure while continuing to operate in mature producing basins. It is becoming more difficult to
find, replace and develop new reserves at historical costs. The continuing development of reserves
and acquisition activities require significant expenditures. Our cash flow from operations may not
be sufficient for this purpose, and we may not be able to obtain the necessary funds from other
sources. In addition, as discussed above, if we are not able to replace reserves, the amount of
credit available to us may decrease since the amount of borrowing capacity available under our
revolving bank credit facility is based, in large part, on the estimated quantities of our proved
reserves.
Estimates of proved reserves and future net revenue may change if the assumptions on which such
estimates are based prove to be inaccurate.
Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any
material inaccuracies in these reserve estimates or underlying assumptions will materially affect
the quantities and present value of our reserves. The accuracy of any reserve estimate is a
function of the quality of available data, engineering and geological interpretation and judgment
and the assumptions used regarding prices for oil and natural gas, production volumes, required
levels of operating and capital expenditures, and quantities of recoverable natural gas and oil
reserves. Natural gas and oil prices have fluctuated widely in recent years. Volatility is
expected to continue and price fluctuations directly affect estimated quantities of proved reserves
and future net revenues. Actual prices, production, development expenditures, operating expenses
and quantities of recoverable oil and natural gas reserves will vary from those assumed in our
estimates, and these variances may be significant. Also, we make certain assumptions regarding
future natural gas and oil prices, production levels, and operating and development costs that may
prove incorrect. Any significant variance from the assumptions used could result in the actual
quantity of our reserves and future net cash flow being materially different from the estimates in
our reserve reports. In addition, actual results of drilling, testing and production and changes in
natural gas and oil prices after the date of the estimate may result in revisions to our reserve
estimates. Revisions to prior estimates may be material. During 2005 and 2004, we incurred
downward revisions of our proved reserves of 60 Bcfe and 20 Bcfe, respectively, either from proved
undeveloped reserves that were determined to be depleted or otherwise not recoverable, or from
production performance indicating less gas in place or smaller reservoir size than initially
estimated.
We may not be able to meet our substantial capital requirements.
Our business is capital intensive. To maintain or increase our base of proved oil and gas reserves,
we must invest a significant amount of cash flow from operations in property acquisitions,
development and exploration activities. We are currently making and will continue to make
substantial capital expenditures to find, develop, acquire and produce natural gas and oil
reserves. If our revenues or borrowing base under our revolving bank credit facility decrease as a
result of lower natural gas and oil prices, operating difficulties or declines in reserves, we may
not be able to expend the capital necessary to undertake or complete future drilling programs or
acquisition opportunities unless we raise additional funds through debt or equity financings. We
may not be able to obtain such debt or equity financings, and cash generated by operations or
available under our revolving bank credit facility may not be sufficient to meet our capital
requirements.
Our business involves many operating risks that can cause substantial losses; insurance may not
protect us against all these risks.
In our operations we may experience hazards and risks inherent in drilling for, producing and
transporting natural gas and oil. These hazards and risks may result in loss of hydrocarbons,
environmental pollution, personal injury claims, and other damage to our properties and third
parties and include:
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fires; |
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natural disasters, including tropical storms, hurricanes and other adverse weather conditions; |
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explosions; |
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encountering formations with abnormal pressures; |
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encountering unusual or unexpected geological formations; |
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blowouts; |
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cratering; |
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unexpected operational events; |
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equipment malfunctions; |
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pipeline ruptures; |
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spills; |
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compliance with environmental and government regulations; and |
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title problems. |
We are insured against some, but not all, of the hazards associated with our business.. Because of
this practice, we may sustain losses that could be substantial due to events that are not insured
or are underinsured. The occurrence of an event that is not covered or not fully covered by
insurance could have a material adverse impact on our financial condition and results of
operations. In addition, because as we do not carry business interruption insurance, the loss and
delay of revenues resulting from curtailed production are not insured.
Our reserves, production and cash flow are highly dependent upon operations that are concentrated
in a small number of areas.
During 2005, we generated approximately 97% of our production from three primary areas of
operation, with 43% from South Texas, 40% from offshore Gulf of Mexico and 14% from the Arkoma
Basin. As we pursue divesting our Gulf of Mexico assets, our operations could become even more
geographically concentrated. The concentrated nature of our operations subjects us to the risk
that a regional event could cause a significant interruption in our production or otherwise have a
material affect on our profitability. This is particularly true of our offshore operations, which
are susceptible to hurricanes and other tropical weather disturbances, some of which can be severe
enough to cause substantial damage to facilities and production infrastructure. During 2005, we
estimate that approximately 10.6 Bcfe of offshore production was either curtailed or delayed as a
result of infrastructure damage to third party pipelines and processing facilities caused by
Hurricanes Katrina and Rita that struck the Texas and Louisiana coasts during August and September.
Drilling natural gas and oil wells is a high risk activity and subjects us to a variety of factors
that we cannot control.
Our drilling activities subject us to many risks, including the risk that we will not find
commercially productive reservoirs. Drilling for natural gas and oil can be unprofitable, not only
from dry wells, but also from productive wells that do not produce sufficient revenues to return a
profit. Also, title problems, weather conditions, governmental requirements and shortages or
delays in the delivery of equipment and services can delay our drilling operations or result in
their cancellation. The cost of drilling, completing and operating wells is often uncertain, and
new wells may not be productive. As a result, we may not recover all or any portion of our
investment.
The availability and cost of rigs, equipment, and personnel could adversely affect our
profitability and level of operations.
Driven by attractive commodity prices, domestic drilling activity measured as a function of rig
utilization has been at very high levels during the past two to three-year period. Given this
extended strong demand for drilling rigs and other oil field services necessary to our operation,
we experienced increased service and material costs, as well as longer lead times and reduced
service availability. We anticipate that this trend will continue in 2006. If current utilization
rates continue at levels seen during 2005 or increase, a general shortage of drilling and
completion rigs, field equipment and qualified personnel could develop, especially in the areas
where we operate. The costs and delivery times of rigs, equipment and personnel could be
substantially greater than in previous years. If we do not have access to necessary oil field
services at a reasonable cost, we could be forced to curtail certain operations and the
profitability of those operations that we do conduct could be materially impaired.
Our business depends on oil and natural gas transportation facilities that are owned by others.
The marketability of our natural gas and oil production depends, in part, on the availability,
proximity and capacity of pipeline systems owned by third parties. The lack of available capacity
on these systems and related facilities could result in the shut-in of our producing wells or the
delay or discontinuation of development plans for our properties. During 2005, we estimate that
approximately 10.6 Bcfe of offshore production was curtailed and delayed due damage to third-party
pipelines
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and processing facilities as a result of damage to Gulf of Mexico infrastructure after Hurricanes
Katrina and Rita that struck the Texas and Louisiana coasts during August and September of 2005.
Although we have some control over the transportation of our product, material changes in these
business relationships could materially affect our operations. 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.
Our acquisition and investment activities may be unsuccessful and costly.
The successful acquisition of producing properties requires assessment of reserves, future
commodity prices, operating costs and potential environmental and other liabilities. These
assessments may not be accurate. Our review of the properties we intend to acquire may not reveal
all existing or potential problems nor allow us to become sufficiently familiar with the properties
to fully assess their deficiencies and capabilities. We may not always perform inspections on every
property or well, and structural or environmental problems may not be observable even when an
inspection is undertaken. Accordingly, we may suffer the loss of one or more acquired properties
due to title deficiencies or may be required to make significant expenditures to cure environmental
contamination or other problems with respect to acquired properties. Even when problems are
identified, the seller may be unwilling or unable to provide effective contractual protection
against all or part of the problems. We are generally not entitled to contractual indemnification
for environmental liabilities and we typically acquire structures on a property on an as is
basis.
Our ability to maximize tax efficiencies with tax free asset exchange transactions following the
pending sale of our Gulf of Mexico assets is uncertain.
There are numerous uncertainties surrounding our ability to reinvest the proceeds from the pending
sale of the Texas portion of our Gulf of Mexico assets and any subsequent sale of the remaining portion of our offshore
assets into onshore natural gas and oil assets, including our ability to structure the reinvestment
in such a manner and within the required time frame such that it qualifies as a tax-free exchange
under Section 1031 of the Internal Revenue Code. In the event we are not able to reinvest the
proceeds from the pending sale and any subsequent sale within the time period prescribed under
Section 1031, we will bear the cost of the resulting tax liability, which could be significant.
Our investments in the Rocky Mountains may not be successful.
Our future growth plans rely in part on establishing significant production and reserves in the
Rocky Mountains, particularly the Uinta Basin in Utah and the DJ Basin in Colorado. To date, we
lack sufficient production history from these areas to accurately estimate the likelihood that our
endeavors will yield meaningful reserves and production with an acceptable rate of return. Certain
of our exploration objectives in the Rocky Mountain area involve geology types and mechanical
operations that differ substantially from our historic operations in South Texas and the Arkoma
Basin. In addition, operations in the Rocky Mountain region present unique operational challenges,
such as more acute transportation constraints, higher pricing differentials, and more extensive
regulatory oversight. Increased drilling in the vicinity of our Rocky Mountain acreage has also
resulted in the Bureau of Land Management (BLM) increasingly requiring the preparation of
environmental assessments or more comprehensive environmental impact statements, as a condition to
conducting operations on certain lands that the BLM administers. Any or all of these contingencies
could delay or halt our drilling activities or the construction of ancillary facilities necessary
for production, which would prevent us from developing our property interests in the Rocky
Mountains as planned and impede our growth.
We may incur substantial costs to comply with costly and stringent environmental and other
governmental laws and regulations.
Our exploration and production operations are regulated extensively at the federal, state, and
local levels. Environmental and other governmental laws and regulations have increased the costs
to plan, design, drill, install, operate and abandon oil and natural gas wells. Failure to comply
with these laws and regulations may result in the assessment of administrative, civil, and criminal
penalties, the imposition of investigatory and remedial obligations, and/or the issuance of
injunctions limiting or prohibiting our operations. However, environmental laws and regulations,
including those that may at some time arise to address global climate change or facility security
concerns, are expected to continue to have an increasingly costly and stringent impact on our
operations resulting in substantial costs and liabilities in the future.
We currently own and lease, and have in the past owned or leased, numerous properties that have
been used for the exploration and production of oil and natural gas for many years. Although we
believe we have 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, petroleum hydrocarbons or wastes may have been disposed of or released
by prior operators
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of properties that we have acquired or may acquire in the future as well as by current third party
operators of properties in which we have an ownership interest. Properties impacted by any such
disposals or releases could be subject to costly and stringent investigatory or remedial
requirements under environmental laws, some of which impose strict, joint and several liability
without regard to fault or the legality of the original conduct, including the federal
Comprehensive Environmental Response, Compensation, and Liability Act, the federal Oil Pollution
Act, the federal Resource Conservation and Recovery Act and analogous state laws. Under such laws
and any implementing regulations, we could be required to remediate contaminated properties and
take actions to compensate for damages to natural resources. In addition, it is not uncommon for
neighboring landowners and other third parties to file claims for personal injury or property
damages allegedly caused by the release of petroleum hydrocarbons or wastes into the environment.
We face strong competition.
As an independent natural gas and oil producer, we face strong competition in all aspects of our
business. Competition is particularly intense for prospective undeveloped leases and purchases of
proved oil and gas reserves. There is also competition for the rigs and related equipment and
services that are necessary for us to develop and operate our natural gas and oil properties. Our
competitive position is also highly dependent on our ability to recruit and retain geological,
geophysical and engineering expertise. We compete for prospects, proved reserves, field services
and qualified oil and gas professionals with major and diversified energy companies and other
independent operators that have financial, human and technological resources greater than ours.
These companies may be able to pay more for productive natural gas and oil properties and
exploratory prospects and to more successfully define, evaluate, bid for and purchase properties
and prospects than our financial and human resources permit. In addition, our competitors may have
an advantage due to their geographic focus and their mix of oil and natural gas reserves.
The inability of one or more of our customers to meet its obligations may adversely affect our
financial results.
Substantially all of our accounts receivable result from natural gas and oil sales or joint
interest billings to third parties in the energy industry. This concentration of customers and
joint interest owners may impact our overall credit risk in that these entities may be similarly
affected by changes in economic and other conditions.
Provisions in our Charter, Agreements, Stockholder Rights Plan and Delaware Law May Inhibit a
Takeover of Houston Exploration.
Under our Restated Certificate of Incorporation, our Board of Directors is authorized to issue
shares of our common or preferred stock without approval of our stockholders. Issuance of these
shares could make it more difficult to acquire our company without the approval of our Board of
Directors as more shares would have to be acquired to gain control. We also have a stockholder
rights plan, commonly known as a poison pill, that entitles our stockholders to acquire
additional shares of our company, or a potential acquirer of our company, at a substantial discount
from market value in the event of an attempted takeover without the approval of our Board. In
2005, we amended our rights plan to increase the ownership triggering threshold from 10% to 15%.
The indenture governing our 7% senior subordinated notes due 2013 also contains change of control
provisions that, among other things, allow the holders of the notes to require us to repurchase
them at 101% of their principal amount, and a change of control constitutes a default under our
revolving bank credit facility. Finally, Delaware law imposes restrictions on mergers and other
business combinations between us and a holder of 15% or more of our
outstanding common stock under certain circumstances.
These provisions may deter hostile takeover attempts that could result in an acquisition of us that
would have been financially beneficial to our stockholders.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties (see Item 1. Business and Properties)
Item 3. Legal Proceedings
We currently are not a party to any material pending legal or governmental proceedings, other than
ordinary and routine litigation incidental to our business. While the ultimate outcome and impact
of this litigation cannot be predicted with certainty, our management believes that the resolution
of any such litigation will not have a material adverse effect on our financial condition or
results of operations.
-21-
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of our security holders during the last quarter of the fiscal
year ended December 31, 2005.
Part II.
Item 5. Market for the Registrants Common Equity Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is traded on the New York Stock Exchange under the symbol THX. The following
table sets forth the range of high and low sales prices for each calendar quarterly period from
January 1, 2004, through December 31, 2005 as reported on the New York Stock Exchange:
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2005 |
|
High |
|
Low |
|
First Quarter |
|
$ |
62.29 |
|
|
$ |
51.14 |
|
Second Quarter |
|
|
59.40 |
|
|
|
45.60 |
|
Third Quarter |
|
|
71.47 |
|
|
|
53.30 |
|
Fourth Quarter |
|
|
67.83 |
|
|
|
49.86 |
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2004 |
|
High |
|
Low |
|
First Quarter |
|
$ |
45.85 |
|
|
$ |
35.79 |
|
Second Quarter |
|
|
52.47 |
|
|
|
41.40 |
|
Third Quarter |
|
|
59.79 |
|
|
|
48.30 |
|
Fourth Quarter |
|
|
61.80 |
|
|
|
53.65 |
|
As of March 1, 2006, 29,067,430 shares of common stock were outstanding, and we had approximately
51 stockholders of record and approximately 30,000 beneficial owners.
Dividends
We have not declared or paid any cash dividends and do not anticipate declaring any dividends in
the foreseeable future. We plan to retain our cash for the operation and expansion of our business,
including exploration, development and acquisition activities, retirement of debt or repurchase of
our common stock. In addition, our revolving bank credit facility and the indenture governing our
7% senior subordinated notes due June 15, 2013, contain restrictions on the payment of dividends to
holders of common stock. For more information, see Item 7. Managements Discussion and Analysis
of Financial Condition and Results of Operations and Consolidated Financial Statements, Note 2
Long-term debt.
-22-
Item 6. Selected Financial Data
The following table shows selected financial data derived from our consolidated financial
statements for each of the five years in the period ended December 31, 2005. You should read these
financial data in conjunction with Item 7. Managements Discussion and Analysis of Financial
Condition and Results of Operations and our Consolidated Financial Statements and the related
Notes.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
2002 |
|
|
2001 |
|
|
|
|
|
|
|
(in thousands, except per share data) |
|
Income Statement Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas and oil revenues |
|
$ |
620,271 |
|
|
$ |
649,087 |
|
|
$ |
491,440 |
|
|
$ |
344,295 |
|
|
$ |
387,156 |
|
Other |
|
|
1,272 |
|
|
|
1,352 |
|
|
|
1,312 |
|
|
|
1,086 |
|
|
|
1,353 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
621,543 |
|
|
|
650,439 |
|
|
|
492,752 |
|
|
|
345,381 |
|
|
|
388,509 |
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense |
|
|
67,796 |
|
|
|
55,925 |
|
|
|
47,072 |
|
|
|
33,976 |
|
|
|
25,291 |
|
Severance tax |
|
|
18,121 |
|
|
|
11,933 |
|
|
|
15,958 |
|
|
|
9,487 |
|
|
|
11,035 |
|
Transportation expense |
|
|
11,883 |
|
|
|
11,819 |
|
|
|
10,387 |
|
|
|
9,317 |
|
|
|
7,652 |
|
Asset retirement accretion expense(1) |
|
|
5,278 |
|
|
|
4,902 |
|
|
|
3,668 |
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
295,351 |
|
|
|
265,148 |
|
|
|
197,530 |
|
|
|
171,610 |
|
|
|
128,736 |
|
Writedown in carrying value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,170 |
|
General and administrative, net |
|
|
38,378 |
|
|
|
32,899 |
|
|
|
19,542 |
|
|
|
13,077 |
|
|
|
17,110 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses |
|
|
436,807 |
|
|
|
382,626 |
|
|
|
294,157 |
|
|
|
237,467 |
|
|
|
195,994 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations |
|
|
184,736 |
|
|
|
267,813 |
|
|
|
198,595 |
|
|
|
107,914 |
|
|
|
192,515 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other (income) expense (2) |
|
|
142 |
|
|
|
(1,058 |
) |
|
|
(15,746 |
) |
|
|
(9,070 |
) |
|
|
119 |
|
Interest expense, net |
|
|
16,535 |
|
|
|
9,455 |
|
|
|
8,342 |
|
|
|
7,398 |
|
|
|
2,992 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
168,059 |
|
|
|
259,416 |
|
|
|
205,999 |
|
|
|
109,586 |
|
|
|
189,404 |
|
Income tax provision |
|
|
62,890 |
|
|
|
96,592 |
|
|
|
72,187 |
|
|
|
39,092 |
|
|
|
66,803 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in
accounting principle |
|
$ |
105,169 |
|
|
$ |
162,824 |
|
|
$ |
133,812 |
|
|
$ |
70,494 |
|
|
$ |
122,601 |
|
Cumulative effect of change in accounting
principle (3) |
|
|
|
|
|
|
|
|
|
|
(2,772 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
105,169 |
|
|
$ |
162,824 |
|
|
$ |
131,040 |
|
|
$ |
70,494 |
|
|
$ |
122,601 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per share before cumulative effect of
change in accounting principle change |
|
$ |
3.66 |
|
|
$ |
5.50 |
|
|
$ |
4.30 |
|
|
$ |
2.31 |
|
|
$ |
4.06 |
|
Cumulative effect of change in accounting
principle (3) |
|
|
|
|
|
|
|
|
|
|
(0.09 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share basic |
|
$ |
3.66 |
|
|
$ |
5.50 |
|
|
$ |
4.21 |
|
|
$ |
2.31 |
|
|
$ |
4.06 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per share before cumulative effect of
change in accounting principle |
|
$ |
3.62 |
|
|
$ |
5.44 |
|
|
$ |
4.29 |
|
|
$ |
2.28 |
|
|
$ |
4.00 |
|
Cumulative effect of change in accounting
principle (3) |
|
|
|
|
|
|
|
|
|
|
(0.09 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share diluted |
|
$ |
3.62 |
|
|
$ |
5.44 |
|
|
$ |
4.20 |
|
|
$ |
2.28 |
|
|
$ |
4.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares basic |
|
|
28,707 |
|
|
|
29,616 |
|
|
|
31,097 |
|
|
|
30,569 |
|
|
|
30,228 |
|
Weighted average shares diluted |
|
|
29,037 |
|
|
|
29,932 |
|
|
|
31,213 |
|
|
|
30,878 |
|
|
|
30,645 |
|
|
Ratio of earnings to fixed charges (4) |
|
|
7.2 |
x |
|
|
15.0 |
x |
|
|
13.6 |
x |
|
|
7.6 |
x |
|
|
12.8 |
x |
-23-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
2005 |
|
2004 |
|
2003 |
|
2002 |
|
2001 |
|
|
|
|
|
(in thousands) |
Cash Flow Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
$ |
460,509 |
|
|
$ |
527,141 |
|
|
$ |
381,969 |
|
|
$ |
243,601 |
|
|
$ |
355,311 |
|
Net cash used in investing activities |
|
|
727,003 |
|
|
|
509,922 |
|
|
|
452,959 |
|
|
|
252,857 |
|
|
|
365,556 |
|
Net cash provided by (used in)financing
activities |
|
|
255,896 |
|
|
|
(1,211 |
) |
|
|
55,528 |
|
|
|
17,668 |
|
|
|
9,189 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, |
|
|
2005 |
|
2004 |
|
2003 |
|
2002 |
|
2001 |
|
|
|
|
|
(in thousands) |
Balance Sheet Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working capital (deficit) (5) |
|
$ |
(214,525 |
) |
|
$ |
(31,884 |
) |
|
$ |
(36 |
) |
|
$ |
10,550 |
|
|
$ |
34,314 |
|
Property, plant and equipment, net |
|
|
2,018,340 |
|
|
|
1,548,256 |
|
|
|
1,371,129 |
|
|
|
1,022,414 |
|
|
|
938,761 |
|
Total assets |
|
|
2,361,624 |
|
|
|
1,722,577 |
|
|
|
1,509,065 |
|
|
|
1,151,068 |
|
|
|
1,059,092 |
|
Long-term debt and notes |
|
|
597,000 |
|
|
|
355,000 |
|
|
|
302,000 |
|
|
|
252,000 |
|
|
|
244,000 |
|
Stockholders equity |
|
|
693,138 |
|
|
|
782,920 |
|
|
|
735,534 |
|
|
|
592,789 |
|
|
|
565,881 |
|
|
|
|
(1) |
|
Subsequent to the adoption of SFAS 143, Accounting for Asset Retirement
Obligations, we have recognized accretion expense as the estimated future obligations that we
have recorded accrete to fair value. |
|
(2) |
|
For 2005, 2004, 2003 and 2002, other income includes $2.7 million, $1.2
million, $21.6 million and $9.1 million, respectively, representing recoupments of prior
period severance tax expense that were recognized pursuant to the receipt of a high
cost/tight sand designation for a portion of our South Texas production in July 2002. See
Note 9 Commitments and Contingencies. In addition, for 2005, other income and expense
includes expense of $2.8 million incurred as a result of a payout settlement at East Cameron
82/83 during the first quarter of 2005, whereby our working interest in the A3 well was
subsequently reduced from 50% to 35%. For 2004, other income includes $0.2 million in debt
extinguishment expenses incurred during the second quarter of 2004 pursuant to the reduction
of our borrowing base from $375 million to $340 million as a result of the disposition of our
Appalachian Basin assets. For 2003, other income includes $5.9 million in expenses incurred
pursuant to the early redemption of our $100 million
85/8% notes in June 2003. For 2001, other
expense of $0.2 million, represents nonrecurring expenses incurred in connection with a
strategic review of alternatives for KeySpans investment in our company, including the
possible sale of all or a portion of Houston Exploration. |
|
(3) |
|
On January 1, 2003, we adopted SFAS 143, Accounting for Asset Retirement
Obligations, which addresses accounting and reporting for obligations associated with the
retirement of tangible long-lived assets and the associated asset retirement costs. Pursuant
to our adoption of SFAS 143, we recognized a charge to income during the first quarter of 2003
of $2.8 million, net of tax, for the cumulative effect of the change in accounting principle.
See Note 1 Summary of Organization and Significant Accounting Policies Asset Retirement
Obligations. |
|
(4) |
|
For purposes of determining the ratio of earnings to fixed charges,
earnings are defined as income (loss) before tax plus fixed charges, adjusted to exclude
capitalized interest. Fixed charges consist of interest expense, whether expensed or
capitalized, and an imputed or estimated interest component of rent expense. See Exhibit 12.1
for calculation. |
|
(5) |
|
The working capital deficit during at December 31, 2005, 2004 and 2003, was
caused by the fair value of our obligations under derivative contracts estimated to be payable
during next 12-month period, offset in part by the associated deferred tax asset. |
-24-
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 the results of
operations together with our present financial condition. This section should be read in
conjunction with our Consolidated Financial Statements and the accompanying notes included
elsewhere in this Annual Report on 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 Forward-Looking Statements
at the beginning of this Annual Report and Item 1A. Risk
Factors beginning on page 15 for
additional discussion of some of these factors and risks.
Overview of Our Business
We are an independent natural gas and oil producer concentrating on growing reserves and production
through the exploration, development, exploitation and acquisition of natural gas and oil reserves
in North America. We were founded in December 1985 as a Delaware corporation and began exploring
for natural gas and oil on behalf of KeySpan Corporation, our then parent company. KeySpan is a
diversified energy provider whose principal natural gas distribution and electric generation
operations are located in the Northeastern United States. In September 1996, we completed our
initial public offering and sold approximately 31% of our shares to the public. Through three
separate transactions, the first in February 2003 and last in November 2004, KeySpan completely
divested its investment in the common stock of our company. See Note 3 Stockholders Equity
for a complete description of these three transactions.
At December 31, 2005, we had operations in five producing regions within the United States: South
Texas; the Arkoma Basin of Arkansas and Oklahoma; East Texas; the Uinta and DJ Basins in the Rocky
Mountains; and the Gulf of Mexico.
Our total net proved reserves as of December 31, 2005 were 861 billion cubic feet equivalent or
Bcfe, with onshore reserves totaling 616 Bcfe. Our reserves are fully engineered on an annual
basis by independent petroleum engineers. Approximately 64% of our proved reserves at December 31,
2005, were classified as proved developed. Our daily production during 2005 averaged 313 million
cubic feet of natural gas equivalent or MMcfe and was significantly curtailed during the last four
months of 2005 and into the first quarter of 2006 primarily as a result of infrastructure damage to
third party pipelines and processing facilities caused by Hurricanes Katrina and Rita that hit the
Louisiana and Texas coasts in August and September 2005.
We derive our revenues from the sale of natural gas and oil that is produced from our natural gas
and oil properties. Revenues are a function of the volume produced and the prevailing market price
at the time of sale. The price of 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
have historically utilized derivative instruments to hedge future sales prices on a significant
portion of our natural gas production. During 2005, 2004 and 2003, 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.
We operate as one segment as all of our assets are based in North American and each of our
operating areas has similar economic characteristics and each meets the criteria for aggregation as
defined in the Financial Accounting Standards Board (FASB) Statement of Financial Accounting
Standards (SFAS) 131, Disclosures about Segments of an Enterprise and Related Information.
Shift
in Operating Focus and Pending Sale of the Texas Portion of Our Gulf of Mexico Assets
In November 2005, we announced our intent to explore the sale of our Gulf of Mexico assets and to
shift our operating focus onshore. At December 31, 2005, our offshore reserves totaled 245 Bcfe, or 28% of our total proved reserves.
Historically, production from our offshore properties has averaged 40% to 45% of total production.
Our offshore properties are located in the shallow waters of the Outer Continental Shelf. Key producing properties are located in the
western and central Gulf of Mexico and include the Mustang Island, Matagorda Island, Galveston
Island, High Island, East Cameron, West Cameron, Eugene Island and Main Pass areas. At December
31, 2005, we held interests in 136 blocks in federal and state waters, of which 78 were developed.
We had a total of 97 producing platforms and production caissons, of which we operated 61. During
2005, offshore production averaged 125 MMcfe/day, and immediately prior to shut-ins caused by
Hurricanes Katrina and Rita, averaged an estimated 155 MMcfe/day. For December 2005, offshore
production averaged 123 MMcfe per day with several fields still curtailed.
On February 28, 2006, we entered into an agreement to sell the
Texas portion of our Gulf of Mexico assets to certain partnerships affiliated with Merit Energy
Company for $220 million in cash, subject to adjustment and customary closing conditions. The transaction is
scheduled to close on or about March 31, 2006, with an effective date of January 1, 2006. We
expect to use the proceeds from the sale of the Texas portion of our Gulf of Mexico assets
primarily to acquire longer-lived natural gas assets onshore in North America and to repay
existing debt. There can be no assurances that we will be able to find suitable properties on
attractive terms. Our operating revenues and cash flows are expected to decrease following the
sale of these assets and are expected to remain at lower levels until we are able to replace the
lost production with production from new properties. Where possible, we plan to structure our
asset reinvestment to minimize taxes on any gain realized from the sale. The sale process with
respect to our remaining Gulf of Mexico assets is ongoing. If a sale is not consummated, we
expect to continue to operate and may consider other strategic
alternatives with respect to these remaining offshore assets. The Texas portion of our Gulf of Mexico assets accounted for approximately 18% of our 2005
production and represented 58.5 Bcfe, or 7% of our total proved reserves, at December 31, 2005. At
December 31, 2005, we held interests in 70 blocks in offshore Texas state and federal waters, of
which 33 were developed. Our assets included 38 producing platforms and production caissons.
-25-
The pending sale of the Texas portion of our Gulf of Mexico assets and any subsequent sale of
the remaining portion of our Gulf of Mexico assets will result in the reclassification of the fair
value of the derivative obligations allocated to offshore production from accumulated other
comprehensive income to earnings. At December 31, 2005, the fair value of derivative obligations
allocated to offshore production for years 2006, 2007 and 2008 was a liability of $182.7 million
($118.0 million net of tax) which approximates the amount deferred in accumulated other
comprehensive income at the end of the period. The ultimate amount of this reclassification and
possible charge against earnings will depend on the fair value of the obligations at the time that
receipt of offshore production allocated to these hedges no longer appears probable. This
reclassification and possible charge to earnings will not affect cash flow.
In connection with the possible divestiture of our Gulf of Mexico assets, and after taking into
account the impact of any such sale on our production levels and any acquisitions that appear
imminent at the time of any such sale, we may and may be required under our revolving bank credit
facility to liquidate a portion of our 2006 hedge position allocated to offshore production. If we
were to sell all of our Gulf of Mexico assets, we estimate that we would liquidate at least 70
MMBtu per day of hedged production. Depending on prices in effect at the time of liquidation, we
could be required to make a significant payment to unwind and settle the open contracts, which
payment we would expect to finance with proceeds from the sale of any Gulf of Mexico assets and/or
borrowings under our revolving bank credit facility.
Recent Acquisition
As part of the plan to shift our operational focus onshore, on November 30, 2005, we completed the
acquisition of certain interests in natural gas and oil producing properties and undeveloped
acreage in four fields located in South Texas from Kerr-McGee Oil & Gas Onshore LP and Westport Oil
and Gas Company, L.P. The net purchase price of $159.0 million was paid in cash and financed by
borrowings under our revolving bank credit facility. The properties cover approximately
26,000 net acres, include approximately 300 wells and are located in the Rincon Field in Starr
County, the Tijerina-Canales-Blucher Field in Jim Wells and Kleberg Counties, the Vaquillas Ranch
Field in Webb County, and the San Carlos Field in Hidalgo County. At December 31, 2005, the proved
reserves attributed to these properties were
approximately 62 Bcfe, of which approximately 75% were natural gas. Current production from the
four fields is estimated at approximately 10 MMcfe/day, net to the interests to be acquired. We
operate 100% percent of the proved reserves with an average working interest of 60%.
Industry Outlook
We currently operate in North America and we believe this region is maturing and production growth
is slowing or possibly declining. While new discoveries are still being made in North America, the
frequency and size of these discoveries is declining as finding and developing costs are
increasing. We believe domestic natural gas and oil production may be at or near its peak and can
be expected to decline in the future, with the exception of relatively unexplored onshore regions
such as the Rocky Mountains.
Our future success in growing our reserve base at an acceptable finding cost will depend in large
part on our ability to acquire new proved reserves and unevaluated acreage which we can explore and
exploit. We maintain an active acquisition program and expect to continue to devote significant
resources to identifying and pursuing both tactical acquisitions that are designed to expand our
operations within an existing core area as well as strategic acquisitions involving one or more new
onshore regions.
We anticipate that the continued decline of the North American gas basins will lead to higher cost
structures throughout our industry. We believe that the cost of finding, developing and producing
new natural gas and oil reserves through exploration and development operations will rise as the
industry makes fewer discoveries and such discoveries generally
-26-
will be of smaller average reserve size. In addition, the acquisition market for natural gas
properties has become extremely competitive as producers vie for additional production and expanded
drilling opportunities in North America. For full cost companies such as ours, increases in both
acquisition and finding and development costs are expected to yield higher depreciation, depletion
and amortization rates and ultimately could increase the likelihood of a writedown in the carrying
value of our natural gas and oil properties if commodity prices fall substantially below current
levels as we continue to add costs to our pool at higher rates with the addition of fewer new
reserves to the amortization base. In addition, we expect drilling costs and lease operating
expenses to continue to increase as producers are required to make operational enhancements to
maintain aging fields.
Natural gas is a commodity. As such, 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, as many industrial users have gradually switched to
a cleaner burning and historically cheaper fuel. Demand will be impacted by general economic
conditions, estimates of gas in storage, weather and other seasonal conditions, including
hurricanes and tropical storms.
Market conditions involving over or under supply of natural gas can result in substantial price
volatility. Continued concerns over the United States ability to meet its longer-term gas needs
from declining domestic supply have resulted in sustained prices above $5.00 throughout 2003, 2004
and 2005. As a direct result of the strong commodity prices during the last three-year period, we
were able to generate substantial cash flows to fund our exploration and development program.
However, historically, commodity prices have been very volatile, and we expect the volatility to
continue in the future. In fact, the NYMEX closing price for natural gas changed from $6.123 per
MMbtu for June 2005 to $13.832 per MMBtu for October and again to $7.112 per MMBtu for March 2006.
As a result, we cannot accurately predict future natural gas and oil prices, and, therefore, we
cannot determine what effect increases or decreases will have on our future revenues and cash
flows. A substantial or extended decline in natural gas and oil prices or poor drilling results
could have a material adverse effect on our financial position, results of operations, cash flows,
quantities of natural gas and oil reserves that may be economically produced and our ability to
access capital markets. Our continued growth and profitability depends on the strength of natural
gas prices and our ability to acquire, find and develop new reserves at economical costs.
Critical Accounting Estimates
The discussion and analysis of our financial condition and results of operations are based upon our
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 assumptions and prepare estimates that affect the reported amounts of assets
and liabilities, the disclosure of contingent assets and liabilities and revenues and expenses. We
base our estimates on historical experience and various other assumptions that we believe are
reasonable; however, actual results may differ. We evaluate our assumptions and estimates on a
regular basis and discuss the development and disclosure process with our Audit Committee. See
Note 1 Summary of Organization and Significant Accounting Policies of Item 8 contained in this
Form 10-K for a discussion of our significant accounting policies.
Proved Reserves. Our reserves are fully engineered on an annual basis by independent petroleum
engineers. Our estimates of proved reserves are based on the quantities of natural gas and 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. However,
there are numerous uncertainties inherent in estimating quantities of proved reserves and in
projecting future revenues, rates of production and timing of development expenditures, including
many factors beyond our control. The estimation process is very complex and relies on assumptions
and subjective interpretations of available geologic, geophysical, engineering and production data
and the accuracy of reserve estimates is a function of the quality and quantity of available data,
engineering and geological interpretation, and judgment. In addition, as a result of volatility
and changing market conditions, commodity prices and future development costs will change from
period to period, causing estimates of proved reserves to change, as well as causing estimates of
future net revenues to change. For the years ended December 31, 2005 and 2004, we revised our
proved reserves downward from prior years reports by approximately 60 Bcfe and 20 Bcfe,
respectively, due to proved undeveloped reserves that were determined to be depleted or otherwise
not recoverable, or from production performance indicating less gas in place or smaller reservoir
size than initially estimated. Estimates of proved reserves are key components of our most
significant financial estimates involving our rate for recording depreciation, depletion and
amortization and our full cost ceiling limitation.
Unevaluated Properties. The balance of unevaluated properties is comprised of capital costs
incurred for undeveloped acreage, wells and production facilities in progress, wells pending
determination and related capitalized interest. These costs are initially excluded from our
amortization base until the outcome of the project has been determined, or generally, until it is
known whether proved reserves will or will not be assigned to the property. We assess all items in
our
-27-
unevaluated property balance on a quarterly basis for possible impairment or reduction in value.
We believe that substantially all of the costs included in our unevaluated property balance will be
evaluated in the next four years.
Asset Retirement Obligations. Asset retirement obligations represent the estimated future
abandonment costs of tangible long-lived assets such as platforms, wells, service assets,
pipelines, and other facilities. We estimate the fair value of an assets retirement obligation in
the period in which the liability is incurred, if a reasonable estimate can be made. We employ a
present value technique to estimate the fair value of an asset retirement obligation, which
reflects certain assumptions, including an inflation rate, our credit-adjusted, risk-free interest
rate, the estimated settlement date of the liability and the estimated current cost to settle the
liability based on third party quotes and current actual costs. Changes in timing or to the
original estimate of cash flows will result in changes to the carrying amount of the liability.
Derivative Instruments. Historically, our derivative contracts have qualified for hedge accounting
under SFAS 133, Accounting for Derivative Instruments and Hedging Activities, as amended.
Accordingly, we reflect the fair market value of our derivative instruments on our balance sheet.
Fair value is accessed and measured and is estimated by obtaining independent market quotes from
counterparties, as well as utilizing the Black-1976 option valuation model that is based upon
underlying forward price curve data, a risk-free interest rate and estimated volatility factors.
In addition, forward price curves and estimates of future volatility factors are used to access and
measure the ineffectiveness of our open contracts at the end of each period. If open contracts
cease to qualify for hedge accounting, the mark-to-market change in the fair value is recognized in
the income statement. Loss of hedge accounting and cash flow designation will cause volatility in
earnings. The fair values we report in our financial statements change as estimates are revised to
reflect actual results, changes in market conditions or other factors, many of which are beyond our
control.
Taxes. We are subject to income taxes at the federal level and in the states where we operate.
Significant judgment is required in evaluating our tax positions and estimating our provision for
income taxes. During the ordinary course of business, there are many transactions and calculations
for which the ultimate tax determination is uncertain. The actual outcome of these future tax
consequences could differ significantly from these estimates, which could impact our financial
position, results of operations and cash flows.
Stock Compensation Expense. We account for stock-based compensation in accordance with the fair
value recognition provisions of SFAS 123, Accounting for Stock-Based Compensation. Under the
fair value recognition provisions of SFAS 123, stock-based compensation cost is measured at the
grant date based on the value of the award and is recognized as expense over the vesting period.
We utilize the Black-Scholes option pricing model to determine the fair value of stock-based awards
on the grant date which requires judgment in estimating the expected life of the option and the
expected volatility of our stock. Actual results could differ significantly from these estimates
and these differences could materially impact our financial position, results of operations and
cash flows. See New Accounting Pronouncements below.
In addition to the critical estimates discussed above, estimates are used in accounting and
computing depreciation, depletion and amortization, the full cost ceiling, accruals of operating
costs and production revenues.
New Accounting Pronouncements
On December 16, 2004, the FASB issued Statement 123 (revised 2004), Share-Based Payment (SFAS
123(R)), which requires the measurement and recognition of compensation expense for all
stock-based compensation payments and the current accounting under SFAS 123, Accounting for
Stock-Based Compensation, and supersedes Accounting Principles Board (APB) Opinion No. 25,
Accounting for Stock Issued to Employees. For us, SFAS 123(R) is effective for our first fiscal
year beginning after June 15, 2005, or January 1, 2006.
On January 1, 2003, we adopted the fair value expense recognition provisions of SFAS 123 as amended
by SFAS 148, Accounting for Stock-Based Compensation Transition and Disclosure using the
prospective method as defined by the SFAS 148. As a result, we have recognized compensation
expense for all stock options granted subsequent to January 1, 2003, with no expense recognized for
grants made prior to 2003. With the adoption of SFAS 123(R), we will recognize compensation expense
over the remaining service period for the unvested portion of all options granted during 2001 and
2002. All options granted prior to 2001 are fully vested. We adopted SFAS 123(R) on January 1,
2006, using the modified version of the prospective application. We plan to continue using the
Black-Scholes option pricing model to estimate the fair value of our options on the date of grant.
Based on current estimates, we expect to incur additional stock compensation expense for grants
made prior to our initial adoption of SFAS 123, and not vested as of January 1, 2006 of $2.0
million ($1.5 million net of amounts capitalized) during 2006 and $0.9 million ($0.7 net of amounts
capitalized) during 2007, with all prior awards being fully expensed by December 31, 2007. We do
not believe the adoption of SFAS 123(R) will have a material impact on our financial statements.
-28-
In March 2005, the SEC released Staff Accounting Bulletin (SAB) 107 providing additional guidance
in applying the provisions of SFAS 123(R), Share-Based Payment. SAB 107 should be applied when
adopting SFAS 123(R) and addresses a wide range of issues, focusing on valuation methodologies and
the selection of assumptions. In addition, SAB 107 addresses the interaction of SFAS 123(R) with
existing SEC guidance.
Overview of 2005 Results
Our results for 2005 were significantly impacted by the physical damage to the Gulf of Mexico
infrastructure and the resulting market uncertainties caused by Hurricane Katrina in August and
Hurricane Rita in September. Ritas path cut directly through our Gulf of Mexico operations. While
our physical facilities incurred relatively minor damage, our production during the last four
months of the year was significantly curtailed primarily as a result of damage to third party
pipelines and processing facilities. Key projects scheduled to add significant new production
during the third and fourth quarters of 2005 were further delayed. Curtailed supply throughout the Gulf of Mexico created unprecedented price movements in the natural gas markets. NYMEX prices for natural gas
reached record levels which resulted in record revenues that could not be realized in earnings
because a significant percentage (more than 85% during the fourth
quarter of 2005 as a result of offshore curtailments) of our
natural gas production was hedged well below these record prices. In addition, during the fourth
quarter of 2005, the basis differential between NYMEX and the Houston Ship Channel widened from an
average of $0.30 per MMBtu to an average of $2.40 per MMBtu. Because approximately 30% of our
production is allocated to the Houston Ship Channel index, we realized lower sales prices. As
commodity prices continued to increase from prior year levels, so did activity levels across the
industry, creating an increase in the demand for materials, equipment, rigs and services. As a
result, we experienced a significant increase in our finding and development costs as well as our
lease operating expenses during 2005. These factors, combined with an increase in debt were the
primary drivers behind results of operations, net income and cash flows during 2005. During 2005:
|
§ |
|
We incurred relatively minor structural damage from Hurricanes Katrina and Rita
and expect to spend a maximum of $35 million for hurricane related repairs. We anticipate
these losses in excess of our deductible will be covered by insurance. As we do not carry
business interruption insurance, the delay of revenues resulting from curtailed and delayed
production is not covered. We estimate the curtailment of production and drilling delays
resulting directly from the storms impacted operating revenues in 2005 by an estimated $132
million. Revenues are expected to be further impacted during the first quarter of 2006 as
we wait for repairs to third-party pipelines and processing facilities,
with restoration expected by the end of the first quarter of 2006; |
|
|
§ |
|
We announced our intent to explore the sale of our Gulf of Mexico assets and
to shift our operating focus onshore. We plan to reinvest the net cash proceeds
from the pending sale of the Texas portion of our Gulf of Mexico assets primarily into longer-lived natural gas
assets onshore in North America and to retire debt. The pending sale of our offshore Texas
assets is expected to close on or about March 31, 2006, with an effective date of January 1,
2006 (see Consolidated Financial Statements, Note 11 Subsequent Events Pending Sale of
Texas Gulf of Mexico Assets); |
|
|
§ |
|
We generated $105.2 million in net income, a decrease of 35% from $162.8 million
in 2004, primarily as a result of lower revenues caused by production curtailments and
$264.5 million in net hedge losses combined with higher depreciation, depletion and
amortization expense, general and administrative expense and interest expense; |
|
|
§ |
|
We produced 114 Bcfe and our average daily production rate was 313 MMcfe per day
compared to 339 Mcfe/day during 2004, a decrease of 8%. We estimate that approximately 10.6
Bcfe, or approximately 30 MMcfe per day on an annualized basis, was deferred by hurricane
related curtailments and delays; |
|
|
§ |
|
We increased total net proved reserves by 9% to 861 Bcfe. We added a net 184
Bcfe, which includes 144 Bcfe added through the drill bit and 100 Bcfe added through
acquisitions after 60 Bcfe of downward revisions, due primarily to reservoir performance.
With the total net additions of 184 Bcfe, we replaced 161% of the 114 Bcfe produced in 2005; |
|
|
§ |
|
We generated $460.5 million in net cash flows from operating activities compared
to $527.1 million during 2004, a decrease of 13%; |
|
|
§ |
|
We spent $743.3 million for investments in natural gas and oil properties, an
increase of 44% over 2004. Our 2005 expenditures included $197.7 million for producing
property acquisitions that compares to $149.6 million spent towards acquisitions in 2004, an
increase of 32%; |
|
|
§ |
|
We increased our outstanding borrowings under our revolving bank credit facility
by a net $242 million, in part to fund our acquisitions and in part to fund cash
requirements for the settlement of derivative contracts; |
|
|
§ |
|
We drilled 336 wells, of which 298, or 89%, were successful with 12 offshore, 16
in East Texas, 82 in South Texas, 60 in Arkoma and 128 in the Rockies; |
-29-
|
§ |
|
We successfully integrated the Gulf of Mexico producing properties acquired in
September and October 2004 from BP Exploration & Production Inc. and Orca Energy, L.P.,
respectively and successfully completed key development projects at Main Pass 264 and Eugene
Island 331; |
|
|
§ |
|
We drilled or participated in drilling of three offshore discoveries that were
considered deep shelf prospects. The successful wells were drilled at West Cameron 75,
West Cameron 77 and West Cameron 62. Additional exploratory successes included Galveston
210 and East Cameron 23; |
|
|
§ |
|
We expanded our onshore exploration efforts in the DJ Basin with one rig
drilling throughout the year and brought on-line our first group of wells during the third
quarter of 2005; |
|
|
§ |
|
We continued our exploration and exploitation efforts in the Uinta Basin with
one rig drilling throughout the year and partnered with two separate groups to spread our
risk and accelerate our efforts. At year-end, we had three rigs drilling on our acreage.
We had a discovery north of the Natural Buttes Field and the well is producing approximately
26 Bbls per day, net to our interests, as of the date of this Annual Report; |
|
|
§ |
|
We extended our development efforts in the North Roleta Field, located in South
Texas, southwest of our operations in the Charco Field, where we began to assemble acreage
and drilled a discovery well in 2004. We successfully drilled and completed eight of ten
wells and added approximately 17.5 MMcfe per day in production, net to our interests; |
|
|
§ |
|
We expanded our East Texas acreage through a series of three related
acquisitions totaling $38.7 million and added an estimated 38 Bcfe in proved reserves. We
successfully integrated these producing properties, added two drilling rigs, successfully
drilled 16 development wells which added 13 Bcfe in reserves and increased average daily
production in the area from 2 MMcfe per day in January 2005 to 8 MMcfe per day in December
2005 (see Note 10 Acquisitions and Dispositions); |
|
|
§ |
|
We acquired producing properties and acreage in four South Texas fields along
the Frio and Vicksburg Trends from Kerr-McGee Oil & Gas and Westport at the end of November
2005 for a net $159.0 million and added estimated proved reserves of 62 Bcfe and future
exploitation opportunities. We took over operations December 1, 2005 and began to integrate
the properties and optimize production rates. Daily production is averaging 10 to 12 MMcfe
per day as of the date of this Annual Report. We expect to spud our first well in the
Rincon Field in April 2006; (see Note 10 Acquisitions and Dispositions); |
|
|
§ |
|
Our depletion rate for natural gas and oil properties increased from $2.30 per
Mcfe during the fourth quarter of 2004 to $3.03 per MMcfe during the fourth quarter of 2005,
primarily as a result of an industry wide increase in costs. We spent more during 2005 on a
per Mcfe basis to find, develop or acquire new reserves and it is projected to cost more to
develop our proved reserves as our future development costs increased by $330 million or 60%
in 2005 from prior year end; |
|
|
§ |
|
We incurred $13.7 million in additional general and administrative expenses as a
result of special charges, including $5.0 million incurred pursuant to the February 2005
renegotiation of employment agreements with five of our key executive officers, including
our Chief Executive Officer, Chief Operating Officer and our then Chief Financial Officer;
$4.7 million in outside professional fees attributable to the review of a corporate
transaction in the second quarter and an acquisition in the third quarter, both of which
were not consummated; and $4.0 million in the fourth quarter related to severance and other
separation related payments made to certain former employees, including our former Chief
Financial Officer; |
|
|
§ |
|
As a result of higher market prices for natural gas at December 31, 2005, the
fair value of our open derivative contracts increased from a liability of $75.1 million
($48.5 million net of tax) at December 31, 2004, to a liability of $417.7 million ($269.8
million net of tax) at December 31, 2005. During 2005, we incurred a total net loss on our
hedging activities of $264.5 million which compares to a total net loss of $70.1 million
during 2004. Of our 2005 total net hedging loss, $116.5 million was incurred during the
fourth quarter; |
|
|
§ |
|
Our Board of Directors approved a plan for discretionary stock repurchases from
time to time up to $200 million of our common stock in conjunction with the possible
divesture of all of our Gulf of Mexico assets and subject to market conditions, applicable
legal requirements and contractual restrictions, available cash, competing reinvestment
opportunities in the acquisition market for oil and gas assets and other factors; and |
|
|
§ |
|
We renegotiated our revolving bank credit facility to increase our banks
lending commitments from $450 million to $750 million. Borrowings under the facility are
secured by our onshore natural gas and oil assets as well as certain other assets. Our
initial borrowing base has been set at $600 million, which is expected to decrease upon
completion of the pending sale of the Texas portion of our Gulf of Mexico assets and likely
would be reduced further upon any sale of the remaining portion of our Gulf of Mexico
assets. |
-30-
Operating and Financial Results for 2005 Compared to 2004 and Operating and Financial Results for
2004 Compared to 2003
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
Year Ended December 31, |
Summary Operating Information: |
|
2005 |
|
2004 |
|
Variance |
|
2004 |
|
2003 |
|
Variance |
|
|
(in thousands, except for price data) |
Natural gas revenues |
|
$ |
816,182 |
|
|
$ |
669,294 |
|
|
$ |
146,888 |
|
|
|
22 |
% |
|
$ |
669,294 |
|
|
$ |
522,597 |
|
|
$ |
146,697 |
|
|
|
28 |
% |
Oil revenues |
|
|
68,631 |
|
|
|
49,938 |
|
|
|
18,693 |
|
|
|
37 |
% |
|
|
49,938 |
|
|
|
37,201 |
|
|
|
12,737 |
|
|
|
34 |
% |
Gain (loss) on settled derivatives |
|
|
(265,236 |
) |
|
|
(68,195 |
) |
|
|
(197,041 |
) |
|
|
289 |
% |
|
|
(68,195 |
) |
|
|
(66,408 |
) |
|
|
(1,787 |
) |
|
|
3 |
% |
Unrealized gain (loss) derivatives |
|
|
694 |
|
|
|
(1,950 |
) |
|
|
2,644 |
|
|
|
-136 |
% |
|
|
(1,950 |
) |
|
|
(1,950 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
|
621,543 |
|
|
|
650,439 |
|
|
|
(28,896 |
) |
|
|
-4 |
% |
|
|
650,439 |
|
|
|
492,752 |
|
|
|
157,687 |
|
|
|
32 |
% |
Operating expenses |
|
|
436,807 |
|
|
|
382,626 |
|
|
|
54,181 |
|
|
|
14 |
% |
|
|
382,626 |
|
|
|
294,157 |
|
|
|
88,469 |
|
|
|
30 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations |
|
|
184,736 |
|
|
|
267,813 |
|
|
|
(83,077 |
) |
|
|
-31 |
% |
|
|
267,813 |
|
|
|
198,595 |
|
|
|
69,218 |
|
|
|
35 |
% |
Net income |
|
|
105,169 |
|
|
|
162,824 |
|
|
|
(57,655 |
) |
|
|
-35 |
% |
|
|
162,824 |
|
|
|
131,040 |
|
|
|
31,784 |
|
|
|
24 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf) |
|
|
105,809 |
|
|
|
115,855 |
|
|
|
(10,046 |
) |
|
|
-9 |
% |
|
|
115,855 |
|
|
|
99,965 |
|
|
|
15,890 |
|
|
|
16 |
% |
Oil (MBbls) |
|
|
1,417 |
|
|
|
1,355 |
|
|
|
62 |
|
|
|
5 |
% |
|
|
1,355 |
|
|
|
1,307 |
|
|
|
48 |
|
|
|
4 |
% |
Total (MMcfe) (1) |
|
|
114,311 |
|
|
|
123,985 |
|
|
|
(9,674 |
) |
|
|
-8 |
% |
|
|
123,985 |
|
|
|
107,807 |
|
|
|
16,178 |
|
|
|
15 |
% |
Average daily production (MMcfe/d) |
|
|
313 |
|
|
|
339 |
|
|
|
(26 |
) |
|
|
-8 |
% |
|
|
339 |
|
|
|
295 |
|
|
|
44 |
|
|
|
15 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (per Mcf) unhedged |
|
$ |
7.71 |
|
|
$ |
5.78 |
|
|
$ |
1.93 |
|
|
|
33 |
% |
|
$ |
5.78 |
|
|
$ |
5.23 |
|
|
$ |
0.55 |
|
|
|
11 |
% |
Natural Gas (per Mcf) realized (2) |
|
|
5.21 |
|
|
$ |
5.19 |
|
|
|
0.02 |
|
|
|
|
|
|
|
5.19 |
|
|
$ |
4.57 |
|
|
|
0.62 |
|
|
|
14 |
% |
Natural Gas (per Mcf) all-in (3) |
|
|
5.21 |
|
|
|
5.17 |
|
|
|
0.04 |
|
|
|
1 |
% |
|
|
5.17 |
|
|
|
4.55 |
|
|
|
0.62 |
|
|
|
14 |
% |
Oil (per Bbl) unhedged |
|
|
48.43 |
|
|
|
36.85 |
|
|
|
11.58 |
|
|
|
31 |
% |
|
|
36.85 |
|
|
|
28.46 |
|
|
|
8.39 |
|
|
|
29 |
% |
Oil (per Bbl) realized (2) |
|
|
48.43 |
|
|
|
36.85 |
|
|
|
11.58 |
|
|
|
31 |
% |
|
|
36.85 |
|
|
|
28.15 |
|
|
|
8.70 |
|
|
|
31 |
% |
|
|
|
(1) |
|
MMcfe is defined as one million cubic feet equivalent of natural gas,
determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or
natural gas liquids. |
|
(2) |
|
Includes gains and losses realized on hedge contracts settled for natural
gas produced during the period. |
|
(3) |
|
Includes both the effect of gains and losses realized on contracts settled
for natural gas produced during the period as well as unrealized gains and losses. |
Income from Operations
Income from Operations 2005
For 2005, income from operations decreased by $83.1 million, or 31%, as compared to 2004, as
operating revenues decreased by $28.9 million or 4% and operating expenses increased by $54.2
million or 14% for the year. Natural gas revenues of $816.2 million were significantly impacted by
a $265.2 million cash loss realized on derivative contracts settled during the period of which
$164.5 million was incurred during the fourth quarter. Although natural gas prices were
consistently strong throughout the first eight months of 2005, even exceeding levels seen in 2004,
the market volatility caused by Hurricanes Katrina and Rita during the last four months of the year
and the resulting record NYMEX prices for natural gas during this period compounded our hedge
losses for the year.
Income from Operations 2004
Production growth and higher realized natural gas prices were the primary factors contributing to
our 35% increase in operating income in 2004 over 2003. Increased revenues were offset in part by
a 30% increase in operating expenses.
Production Volume 2005 vs. 2004
Production volumes were 8% lower in 2005 compared to 2004, due primarily to curtailments of
offshore production and the natural production decline of our existing property base as we were
delayed in bringing on-line new production offshore and in the DJ Basin.
Onshore. Daily production rates for 2005 were slightly higher than the prior year, averaging 188
MMcfe per day compared to 186 MMcfe per day during 2004. Through development drilling we added
approximately 5 MMcfe per day in Arkoma
-31-
and 3 MMcfe per day in East Texas. We continued our exploration efforts in the Rockies, where we
experienced delays in bringing production from the DJ Basin wells on-line, but added approximately
4 MMcfe per day in the region for the year. Growth in these areas was offset by production
declines in South Texas, as we see our existing property base mature. Year-over-year, 2004 onshore
volumes include production from our South Louisiana properties sold in February 2004 and our
Appalachian Basin properties divested of in June 2004.
Offshore. Daily production rates decreased by 18%, or 28 MMcfe per day, from an average of 153
MMcfe per day during 2004 to an average of 125 MMcfe per day in 2005. For the first eight months
of 2005, offshore production rates were lower than prior year levels due in part to delays in our
development program caused by delays in rig availability during the first half of 2005 and in part
to (i) an unsuccessful side-track at High Island 115; (ii) lower production rates at High Island 47
subsequent to a side-track completed in the second quarter; and (iii) declining production rates at
High Island A283, Galveston 389 and East Cameron 81/84, all key producing fields during 2004. At
the end of August 2005, pre-storm production was estimated at 155 MMcfe per day, primarily as a
result of newly developed production at Galveston 210, Matagorda A-5, West Cameron 77, Main Pass
264 and Mustang Island 858. We estimate that approximately 10.6 Bcfe or 30 Mcfe per day on an
annualized basis was shut-in and deferred during the last four months of 2005 as a result of
Hurricanes Katrina and Rita.
Production Volume 2004 vs. 2003
The 15% increase in production for 2004 is primarily a result of both production added from Gulf of
Mexico properties acquired during the fourth quarter of 2003, as well as newly developed
production, both onshore and offshore, from our existing property base.
Onshore. Daily production rates increased 8% from an average of 173 MMcfe per day in 2003 to 186
MMcfe per day in 2004, despite our loss of approximately 8 MMcfe per day as a result of the
divesture of our South Louisiana and Appalachian Basin properties during the first half of 2004.
The Arkoma Basin was our onshore growth area during 2004. We experienced the full impact of the
accelerated drilling program initiated in 2003 that continued throughout 2004 as we added 15 MMcfe
per day in newly developed production. With three rigs drilling through the first 10 months of
2004, Arkoma production reached a record of 44 MMcfe per day during the fourth quarter compared to
25 MMcfe per day during the fourth quarter of 2003. For 2004, South Texas production increased to
an average of 142 MMcfe per day compared to 140 MMcfe per day 2003.
Average daily production rates for Arkoma and South Texas were negatively impacted during the
fourth quarter of 2004 by our operational curtailment. As a result of rising rig rates and service
costs during the quarter, we reduced our onshore rig activity to keep capital spending within
budgeted levels. In South Texas, we went from six rigs to four and in Arkoma we went from three
rigs to one. In addition, we deferred the completion of seven wells in South Texas capable of
producing an estimated 11 MMcfe per day, net, and five wells in Arkoma capable of producing an
estimated 2 MMcfe per day, net. By the end of January 2005, we had resumed our six-rig program in
South Texas and added a second rig in Arkoma.
In the Rockies, 2004 was an exploratory year and our activities were aimed at expanding our acreage
position and proving up reserves in several exploration projects on our Uinta Basin acreage
acquired in 2003. We drilled a total of 31 wells, 26 in the Uinta Basin, four in the DJ Basin and
one in Montana. Of the total drilled, 28 wells or 90% were successful. By December 2004, six of
our Uinta Basin wells were producing approximately 1.3 MMcfe per day, net to our interest. At
December 31, 2004, production from the remaining 19 of our 25 successful Uinta Basin wells remained
delayed, awaiting right-of-way approval for pipeline construction from the Bureau of Land
Management (BLM). Subsequent to December 31, 2004, we received approval from the BLM for
pipelines on 11 of the wells.
Offshore. We experienced record production growth as average daily rates increased 25% from 122
MMcfe per day during 2003 to an average of 153 MMcfe per day during 2004. We added approximately
41 MMcfe per day in newly developed production, of which an average of 22 MMcfe per day was
attributable to development drilling at High Island A283 and East Cameron 56/57 and 148. During
the year, we completed and brought on-line seven development wells at High Island A283, two at EC
56/57and one at East Cameron 148. All of these fields were acquired in mid-October 2003, as part
of our acquisition of Gulf of Mexico properties. Production from these properties accounted for
approximately 71 MMcfe per day of our offshore production during 2004. Partially offsetting the
production from our newly acquired properties were declines from existing and maturing fields
totaling approximately 40 MMcfe per day, resulting in a net 31 MMcfe per day production increase
year-over-year. Because the majority of our fields are located in the Western and Central Gulf of
Mexico, Hurricane Ivan in September 2004, had minimal impact on our results for the year. We
estimate that during the third quarter, approximately 210,000 Mcfe or 2 MMcfe per day was deferred.
All shut-in production was fully restored prior to the end of the third quarter of 2004.
-32-
During the fourth quarter of 2004, we experienced production declines at three key fields. In
November 2004, the High Island 47 No. 1 well depleted. A third party operates this field and, our
working interest is 33%. Prior to depletion, the well produced an average of 5 MMcfe per day to
our interest, during 2004. In December 2004, our deep well at High Island 115, the No. 1, was
shut-in due to a mechanical problem. A third party operates the well, and, we have a 50% working
interest. During 2004, this well contributed an average of 9 MMcfe per day to our total daily
production.
Commodity Prices and Effects of Hedging 2005 vs. 2004
For 2005, our average unhedged or sales price for natural gas increased by 33% from $5.78 per Mcf
during 2004 to $7.71 per Mcf during 2005. Because NYMEX prices traded above our average hedged
ceiling during all 12 months of 2005, our total loss from hedging activities increased by $194.4
million year-over-year, with approximately 60% of the increase occurring in last four months of
2005 as a result of the spike in NYMEX prices, trading in a range between $11.00 per MMBtu to
$14.00 per MMBtu, after Hurricanes Katrina and Rita. Subsequent to December 31, 2005, NYMEX prices
fell from the record levels set in the fourth quarter, to closing at $7.112 per MMBtu for March
2006. We expect prices to remain volatile throughout 2006.
Included in natural gas revenues for 2005 is a loss of $264.5 million from natural gas hedging
activities, which includes the following items:
|
§ |
|
Cash loss on contracts settled for natural gas produced during the period of $265.2
million ($171.3 million net of tax); |
|
|
§ |
|
As a result of the offshore production shortfall during the fourth quarter caused by the
hurricanes, we deferred a $20.6 million loss ($13.3 million net) of tax related to the above cash
settlements made during the fourth quarter of 2005 to accumulated other comprehensive income.
We expect to recapture the production shortfall during the first quarter of 2006, at which
time the $20.6 million will be recognized as a reduction to earnings; |
|
|
§ |
|
Unrealized loss of $46.0 million ($29.7 million net of tax) for the ineffective portion of
open contracts at the end of the period that were not eligible for
deferral under SFAS 133 due primarily to the basis differentials between the
contract price, which is NYMEX based, and the indexed price at the point of sale, 30% of which is allocated to the Houston Ship Channel index; and |
|
|
§ |
|
Unrealized gain of $26.1 million ($16.9 million net of tax) due to the loss of correlation
during the fourth quarter of 2005 of the Houston Ship Channel index and the NYMEX price. Our
hedged production allocated to the Houston Ship Channel index failed to qualify for hedge
accounting and as a result, our Houston Ship Channel contracts were marked-to-market with the
change in the fair value during the fourth quarter creating an unrealized gain. |
As a result of the cash loss from hedge contracts settled during 2005, we realized an average
natural gas price during the year of $5.21 per Mcf which was 68% of, or $2.50 per Mcf lower than,
our average sales price of $7.71 per Mcf of the year. During 2004, we incurred a hedge loss from
natural gas derivatives of $70.1 million, which included an unrealized loss of $1.9 million
recognized for ineffectiveness. As a result of the cash loss from hedge contracts settled during
2004, we realized an average price of $5.19 per Mcf, which was 90% of, or $0.59 per Mcf lower than,
our average sales price of $5.78 per Mcfe during the year.
Commodity Prices and Effects of Hedging 2004 vs. 2003
Our average unhedged or sales price for natural gas increased by 11% from $5.23 per Mcf during 2003
to $5.78 per Mcf during 2004. Included in natural gas revenues for 2004 is a loss of $70.1 million
from natural gas hedging activities, which includes an unrealized loss of $1.9 million representing
the ineffective portion of our derivative instruments that are not eligible for deferral under SFAS
133. As a result of the cash loss from hedging activities, we realized an average natural gas
price during 2004 of $5.19 per Mcf that was 90% of or $0.59 lower than our average sales price.
During 2003, we incurred a hedge loss from natural gas derivatives of $67.9 million, which is
included in natural gas revenues and includes an unrealized loss of $1.9 million recognized for
ineffectiveness. As a result of the cash loss from hedging activities, we realized an average
price of $4.57 per Mcf that was 87% of, or $0.66 per Mcf lower than our sales price.
-33-
Operating Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
Year Ended December 30, |
|
Operating Expenses per Mcfe |
|
2005 |
|
|
2004 |
|
|
Variance |
|
|
2004 |
|
|
2003 |
|
|
Variance |
|
Lease operating expense |
|
$ |
0.59 |
|
|
$ |
0.45 |
|
|
|
0.14 |
|
|
|
31 |
% |
|
$ |
0.45 |
|
|
$ |
0.44 |
|
|
$ |
0.01 |
|
|
|
2 |
% |
Severance tax |
|
|
0.16 |
|
|
|
0.10 |
|
|
|
0.06 |
|
|
|
60 |
% |
|
|
0.10 |
|
|
|
0.15 |
|
|
|
(0.05 |
) |
|
|
-33 |
% |
Transportation expense |
|
|
0.10 |
|
|
|
0.10 |
|
|
|
|
|
|
|
|
% |
|
|
0.10 |
|
|
|
0.10 |
|
|
|
|
|
|
|
|
% |
Asset retirement accretion expense |
|
|
0.05 |
|
|
|
0.04 |
|
|
|
0.01 |
|
|
|
25 |
% |
|
|
0.04 |
|
|
|
0.03 |
|
|
|
0.01 |
|
|
|
33 |
% |
Depreciation, depletion and
amortization |
|
|
2.58 |
|
|
|
2.14 |
|
|
|
0.44 |
|
|
|
21 |
% |
|
|
2.14 |
|
|
|
1.83 |
|
|
|
0.31 |
|
|
|
17 |
% |
General and administrative, net |
|
|
0.34 |
|
|
|
0.27 |
|
|
|
0.07 |
|
|
|
26 |
% |
|
|
0.27 |
|
|
|
0.18 |
|
|
|
0.09 |
|
|
|
50 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses per
unit of production |
|
$ |
3.82 |
|
|
$ |
3.10 |
|
|
|
0.72 |
|
|
|
23 |
% |
|
$ |
3.10 |
|
|
$ |
2.73 |
|
|
$ |
0.37 |
|
|
|
14 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
During 2005, total operating expenses increased on an absolute dollar basis by 14% over 2004,
primarily as a result of higher lease operating expenses, depreciation, depletion and amortization
expense and general and administrative expenses. On a unit of production basis, total operating
expenses increased $0.72 per Mcfe, or 23%, from 2004 to 2005. Per unit expenses were higher for
all categories of operating expense during 2005 due to curtailed production during the last four
months of the year combined with higher costs during 2005. Depreciation, depletion and
amortization accounted for $0.44 of the 2005 increase with lease operating expense adding $0.14 and
non-recurring general and administrative expenses contributing $0.12. During 2004, total operating
expenses increased 30% over 2003 primarily as a result of higher depreciation, depletion and
non-recurring general and administrative expenses. On a unit production basis, operating expenses
increased $0.37 per Mcfe produced, or 14%, from 2003 to 2004.
Lease Operating Expense.
On an absolute dollar basis, lease operating expense for 2005 increased by 21% from 2004 levels.
For 2004, lease operating expense increased by 19% from 2003 levels. The year-over-year increases
from 2003 to 2004 and from 2004 to 2005 relates primarily to higher service costs and the continued
expansion of our operating base from the escalation of our drilling program during each of the
respective years and the acquisition of new properties. We have seen our Gulf of Mexico lease
operating expenses increase significantly over the last two-year period as a direct result of the
acquisition of the Transworld properties in the fourth quarter of 2003 and the BP and Orca
properties in September and October of 2004. These properties were mature assets, acquired
primarily for exploitation opportunities, and operated under higher cost structures than our
existing offshore base. During the last two years, we have integrated these assets into our Gulf
of Mexico base and have worked to reduce overall operating expenses. While we remain committed to
minimizing our operating cost structure, we expect to see lease operating expenses continue to
increase during the next year as the demand for field services remains strong and as we continue
our acquisition activities.
Severance Tax.
Severance tax is a function of volume and revenues generated from onshore production. During 2005,
severance tax increased by 52% on an absolute dollar basis and $0.06 per Mcfe, primarily as a
result of the 33% increase in the market price for natural gas during 2005 as compared to 2004.
During 2004, severance tax on an absolute dollar basis, decreased by 25% from 2003. On an Mcfe
basis, severance tax decreased by $0.05 or 33% from 2003 to 2004. Despite higher wellhead prices
during 2004 as compared to 2003 severance tax expense was lower during 2004 primarily due to
severance tax rebates received on our South Texas properties as a result of their
high-cost/tight-sand designation.
Depreciation, Depletion and Amortization.
The increase in our depreciation, depletion and amortization expense during 2005 was primarily a
result of a higher depletion rate, offset in part by an 8% decrease in production. Our total
depreciation, depletion and amortization rate increased 21% from $2.14 per Mcfe during 2004 to
$2.58 per Mcfe during 2005. The higher depletion rate during 2005 is primarily a result of a
higher finding, development and acquisition costs incurred during 2005 combined with a 60% increase
in future development costs at December 31, 2005 compared to future development costs at the end of
2004. In addition, we incurred downward revisions of 60 Bcfe during
2005, due primarily to reservoir performance and included
approximately 14 Bcfe at High Island 115 from an unsuccessful side-track of the B-1 well and
approximately 12 Bcfe in the Uinta Basin primarily as a result of a reduction in our working
interest from 100% to 50% subsequent to our entering into a joint venture with another operator.
-34-
During 2004, the increase in our depreciation, depletion and amortization expense from 2003 was
primarily a result of a higher depletion rate combined with a 15% increase in production for the
year. Our depreciation, depletion and amortization rate of $2.14 per Mcfe during 2004 was 17%
higher than the $1.83 per Mcfe during 2003. Higher average finding costs per unit were the primary
factor in the increase in our depletion rate. In addition, our future development costs at
December 31, 2004 increased 48% from estimates at December 31, 2003, primarily as a result of the
future development costs relating to several offshore Gulf of Mexico properties acquired in October
2004. For 2004, producing property dispositions resulted in reserve reductions of 63.3 Bcfe.
Finally, for 2004, we incurred downward revisions of 19.9 Bcfe, either due to proved undeveloped
reserves that were depleted or otherwise not recoverable, or from production performance indicating
less gas in place or smaller reservoir size than initially estimated.
Asset Retirement Accretion Expense.
The increase in ARO accretion expense from 2004 to 2005 and from 2003 to 2004 reflects the increase
in our abandonment obligations as we drill and acquire new wells, offset in part by dispositions.
General and Administrative Expenses, Net of Overhead Reimbursements and Capitalized General and
Administrative Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Absolute Dollars |
|
|
Unit of Production
Mcfe |
|
|
|
Year Ended December 31, |
|
|
Year Ended December 31, |
|
General and Administrative Expense |
|
2005 |
|
|
2004 |
|
|
Variance |
|
|
2005 |
|
|
2004 |
|
|
Variance |
|
|
|
(in thousands) |
|
Gross general and administrative expense |
|
$ |
57,412 |
|
|
$ |
49,924 |
|
|
$ |
7,488 |
|
|
|
15 |
% |
|
$ |
0.50 |
|
|
$ |
0.40 |
|
|
$ |
0.10 |
|
|
|
25 |
% |
Operating overhead reimbursements |
|
|
(2,158 |
) |
|
|
(2,188 |
) |
|
|
30 |
|
|
|
-1 |
% |
|
|
(0.02 |
) |
|
|
(0.01 |
) |
|
|
(0.01 |
) |
|
|
100 |
% |
Capitalized general and administrative |
|
|
(16,876 |
) |
|
|
(14,837 |
) |
|
|
(2,039 |
) |
|
|
14 |
% |
|
|
(0.14 |
) |
|
|
(0.12 |
) |
|
|
(0.02 |
) |
|
|
17 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expense, net |
|
$ |
38,378 |
|
|
$ |
32,899 |
|
|
$ |
5,479 |
|
|
|
17 |
% |
|
$ |
0.34 |
|
|
$ |
0.27 |
|
|
$ |
0.07 |
|
|
|
26 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 vs 2004. For 2005, gross general and administrative expenses increased by 15%, or $7.5
million, as compared to 2004. Net general and administrative expenses increased by 17%, or $5.5
million, for the year. During 2005 we incurred additional expenses totaling $13.7 million ($0.12
per Mcfe) that include $5.0 million incurred during the first quarter pursuant to the February 2005
renegotiation of executive employment agreements (see Note 5 Related Party Transactions
Employment Agreements); $0.9 million in the second quarter together with another $3.8 million in
the third quarter for outside professional fees incurred pursuant to the review of two corporate
transactions that were not consummated; and $4.0 million in the fourth quarter related to severance
and other separation related payments made to certain former employees, including our former Chief
Financial Officer.
The year ended December 31, 2004 also includes additional charges to expense which total $9.5
million ($0.08 per Mcfe). We incurred $4.4 million during the second quarter of 2004 which
included special bonuses awarded by our Board to several key employees, including our Chief
Executive Officer who received $3.2 million, in connection with the KeySpan Exchange and Offering
completed in June 2004 (see Note 3 Stockholders Equity KeySpan Exchange and Offering). We
incurred $5.1 million during the fourth quarter of 2004 related to lump sum severance entitlements
for three senior executives whose rights to receive severance and accelerated vesting of options
and restricted stock were triggered under the terms of their employment agreements as a result of
an organizational realignment of management responsibilities during the fourth quarter of 2004.
One executive resigned effective December 14, 2004 and two executives resigned effective March 1,
2005. For 2005, the remaining $1.3 million increase in general and administrative expense was a
result of higher outside professional fees, specifically legal and accounting, combined with an
increase in stock compensation expense related to both options and restricted stock.
On a per unit of production basis, gross general and administrative expense increased by $0.10 per
Mcfe and net general and administrative expense increased by $0.07 per Mcfe from 2004 to 2005. The
increase in both aggregate and net general and administrative expense per Mcfe is a result of a 15%
increase in aggregate expense combined with the effect of an 8% decrease in production volume
during 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Absolute Dollars |
|
|
Unit of Production
Mcfe |
|
|
|
Year Ended December 31, |
|
|
Year Ended December 31, |
|
General and Administrative Expense |
|
2004 |
|
|
2003 |
|
|
Variance |
|
|
2004 |
|
|
2003 |
|
|
Variance |
|
|
|
(in thousands) |
|
Gross general and administrative expense |
|
$ |
49,924 |
|
|
$ |
33,980 |
|
|
$ |
15,944 |
|
|
|
47 |
% |
|
$ |
0.40 |
|
|
$ |
0.32 |
|
|
$ |
0.08 |
|
|
|
25 |
% |
Operating overhead reimbursements |
|
|
(2,188 |
) |
|
|
(1,559 |
) |
|
|
(629 |
) |
|
|
40 |
% |
|
|
(0.01 |
) |
|
|
(0.02 |
) |
|
|
0.01 |
|
|
|
-50 |
% |
Capitalized general and administrative |
|
|
(14,837 |
) |
|
|
(12,879 |
) |
|
|
(1,958 |
) |
|
|
40 |
% |
|
|
(0.12 |
) |
|
|
(0.12 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expense, net |
|
$ |
32,899 |
|
|
$ |
19,542 |
|
|
$ |
13,357 |
|
|
|
68 |
% |
|
$ |
0.27 |
|
|
$ |
0.18 |
|
|
$ |
0.09 |
|
|
|
50 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-35-
2004 vs. 2003. For 2004, net general and administrative expenses were up by 69% on an absolute
dollar basis from $19.5 million in 2003 to $32.9 million in 2004. Of the $13.4 million increase,
$9.5 million related to severance expenses and special incentive payments. A substantial portion
of the remaining increase related to changes in accounting for stock-based compensation, as well as
continuing professional expenses related to corporate governance compliance. For general and
administrative expense on a per-unit of production basis, the additional compensation expenses of
$9.5 million resulted in an $0.08 per Mcfe increase for 2004. Absent these additional compensation
expenses, gross general and administrative expense for 2004 would have been $0.32 per Mcfe,
unchanged from $0.32 per Mcfe in 2003 and net general and administrative expense would have been
$0.19 per Mcfe for 2004, an increase of $0.01 per Mcfe or 6%, from 2003. While general and
administrative expenses have increased as our company has grown, per unit expense is comparable
year-over-year as a result of the increase in our production volume during 2004.
Other Income and Expense, Interest and Taxes
Other Income and Expense.
For 2005, Other Income and Expense includes (i) income of $2.7 million related to refunds of prior
years severance tax expense and (ii) expense of $2.8 million incurred as a result of a payout
settlement at East Cameron 82/83 during the first quarter of 2005, whereby our working interest in
the A3 well was subsequently reduced from 50% to 35%. In July 2002, we applied for and received
from the Railroad Commission of Texas a high-cost/tight-gas formation designation for a portion
of our South Texas production. For qualifying wells, production is either exempt from tax or taxed
at a reduced rate until certain capital costs are recovered.
For 2004, Other Income and Expense includes two items: (i) income of $1.2 million related to
refunds of prior years severance tax expense; and (ii) a $0.2 million write-off of a portion of
our debt issuance costs due to the June 2, 2004 reduction in the borrowing base on our revolving
bank credit facility due to the disposition of our Appalachian Basin assets in June 2004. For
2004, the recognition of other income as a result of the recoupment of prior years expense is
considerably less than in 2003 as we were nearing the end of the recoupment process.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
Year Ended December 31, |
|
Interest and Average Borrowings |
|
2005 |
|
|
2004 |
|
|
Variance |
|
|
2004 |
|
|
2003 |
|
|
Variance |
|
|
|
(in thousands) |
|
Gross interest |
|
$ |
25,301 |
|
|
$ |
17,813 |
|
|
|
7,488 |
|
|
|
42 |
% |
|
$ |
17,813 |
|
|
$ |
15,642 |
|
|
$ |
2,171 |
|
|
|
14 |
% |
Capitalized interest |
|
|
(8,766 |
) |
|
|
(8,358 |
) |
|
|
(408 |
) |
|
|
5 |
% |
|
|
(8,358 |
) |
|
|
(7,300 |
) |
|
|
(1,058 |
) |
|
|
14 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net of capitalized
interest |
|
$ |
16,535 |
|
|
$ |
9,455 |
|
|
|
7,080 |
|
|
|
75 |
% |
|
$ |
9,455 |
|
|
$ |
8,342 |
|
|
$ |
1,113 |
|
|
|
13 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average total borrowings(1) |
|
$ |
388,000 |
|
|
$ |
289,000 |
|
|
$ |
99,000 |
|
|
|
34 |
% |
|
$ |
289,410 |
|
|
$ |
240,000 |
|
|
$ |
49,410 |
|
|
|
-21 |
% |
Average total interest rate(1) |
|
|
6.16 |
% |
|
|
5.68 |
% |
|
|
0.48 |
% |
|
|
8 |
% |
|
|
5.68 |
% |
|
|
6.08 |
% |
|
|
0.40 |
% |
|
|
-7 |
% |
Average bank borrowings |
|
$ |
211,000 |
|
|
$ |
112,000 |
|
|
$ |
99,000 |
|
|
|
88 |
% |
|
$ |
111,979 |
|
|
$ |
89,668 |
|
|
|
22,311 |
|
|
|
25 |
% |
Average bank interest rate |
|
|
5.54 |
% |
|
|
3.75 |
% |
|
|
1.80 |
% |
|
|
48 |
% |
|
|
3.75 |
% |
|
|
3.42 |
% |
|
|
0.33 |
% |
|
|
10 |
% |
|
|
|
(1) |
|
Average total borrowings and average total interest rate includes our
$175 million senior notes at 7% due June 2013 and borrowings under our revolving bank
credit facility. |
Interest Expense, Net of Capitalized Interest.
For 2005, the increase in gross interest expense period-over-period is due to an increase in
outstanding borrowings under our revolving bank credit facility combined with an increase in
average interest rates associated with our bank debt. Our average bank debt has continued to
increase from the second half of 2004 through the end of 2005 as we utilized our revolving facility
to fund a portion of the asset exchange transaction with KeySpan in June 2004, two producing
property acquisitions in September and October 2004 and two producing property acquisitions during
2005. Although the majority of our bank debt bears interest at LIBOR-based rates, the Federal
Reserve raised rates by one quarter of a percent eight times during 2005. We expect to continue to
see an increase in the interest rate we are paying on our bank debt if the Federal Reserve
continues to increase Federal interest rates. Capitalized interest is a function of unevaluated
properties and the 5% increase during 2005 is primarily a function of the increase in our average
borrowing rate as the balance of unevaluated properties declined during 2005.
-36-
For 2004, the increase in gross interest expense from 2003 is due to an increase in both fixed debt
and bank debt offset in part by a decrease in average interest rates. Our fixed debt increased in
June 2003 when we replaced our existing senior subordinated notes of $100 million at 85/8% with new
senior subordinated notes of $175 million at 7%. Bank debt increased during 2004 as we utilized
our revolving bank credit facility to fund not only a portion of the KeySpan Exchange in June 2004
but also our two producing property acquisitions in September and October 2004. Capitalized
interest is a function of unevaluated properties and the increase for 2004 corresponds to the
increase in our average unevaluated property balance throughout 2004.
Income Tax Provision.
Our provision for taxes includes both state and federal taxes. During 2005 and 2004, our state tax
obligations increased as our onshore revenues increased and as we expanded our operations into
several Rocky Mountain states.
The 35% decrease in income taxes for 2005 from 2004 corresponds to the 35% decrease in income
before taxes. During 2005, revenues were lower and expenses were higher than in 2004. Our current
provision for 2005 includes $1.4 million relating to nondeductible excess executive compensation
expense incurred as a result of the contract renegotiation payment made to our Chief Executive
Officer in February 2005 (see Note 6 Related Party Transactions Employment Agreements). In
addition, the provision for 2005 includes additional expense of $2.0 million, primarily related to
adjustments to estimates for federal and state liabilities incurred during the first quarter of
2005.
The 34% increase in income taxes for 2004 from 2003 corresponds to the 26% increase in income
before taxes from 2003 to 2004. Our current provision increased to $41.2 million during 2004 as we
utilized all of our net operating loss carryforwards during 2003 and moved to a tax paying status.
Prior to the third quarter of 2003, the majority of our federal income taxes were deferred. Our
current provision for 2004 includes $1.4 million relating to nondeductible excess executive
compensation expense of which $1.0 million was incurred in the second quarter as a result of the
special bonus paid to our Chief Executive Officer in connection with the KeySpan Exchange and $0.4
million incurred in the fourth quarter as a result of the retirement of our former Senior Vice
President and General Manager Offshore Division.
Liquidity
Capital Requirements
Our principal requirements for capital are to fund our exploration, development and acquisition
activities and to satisfy our contractual obligations, primarily the repayment of debt and any
amounts owing during the period relating to our hedging positions. Our uses of capital include the
following:
|
§ |
|
Drilling and completing new natural gas and oil wells; |
|
|
§ |
|
Constructing and installing new production infrastructure; |
|
|
§ |
|
Acquiring additional reserves and producing properties; |
|
|
§ |
|
Acquiring and maintaining our lease acreage position and our seismic resources; |
|
|
§ |
|
Maintaining, repairing, and enhancing existing natural gas and oil wells; |
|
|
§ |
|
Plugging and abandoning depleted or uneconomic wells; and |
|
|
§ |
|
Indirect costs related to our exploration activities, including payroll and
other expense attributable to our exploration professional staff. |
In light of the ongoing process to sell our Gulf of Mexico assets, we are currently reviewing our
capital program for 2006. To maintain flexibility of our capital program, we typically do not
enter into material long-term obligations with any of our drilling contractors or service providers
with respect to our operated properties; however, we may choose to do so if an opportunity is
economically beneficial. We do not include property acquisition costs in our initial capital
budget because the size and timing of capital requirements for acquisitions are inherently
unpredictable. As the year progresses, we will continue to evaluate our capital spending. Actual
levels may vary due to a variety of factors, including the timing of any sale of our Gulf of Mexico
assets, drilling results, natural gas prices, economic conditions and future acquisitions.
Future Commitments
The table below provides estimates of the timing of future payments that we were obligated to make
based on agreements in place at December 31, 2005. All amounts listed in the table below are
categorized as liabilities on our balance sheet with the exception of lease payments for operating
leases and outstanding letters of credit issued for performance obligations. At
-37-
December 31, 2005,
we did not have any capital leases or long-term contracts for drilling rigs
or equipment. The table includes references to our financial statements for information regarding
the listed obligation. Contractual obligations relating to our revolving bank credit facility and our
senior notes include only payments of principal.
In addition to the contractual obligations listed on the table below, our balance sheet at December
31, 2005, reflects accrued interest payable on our revolving bank credit facility of approximately
$0.3 million which is payable over the next 90-day period. We expect to make annual interest
payments of $12.3 million per year on our $175 million of 7% senior subordinated notes due June
2013. As a result of credits and amounts on deposit that were paid during 2005, we do not expect
to make any cash payments for federal income taxes during 2006 and estimate less than $1.0 million
for state income taxes. In connection with the pending sale of the Texas portion of our Gulf of
Mexico assets and any subsequent sale of the remaining portion of our Gulf of Mexico assets, we may
and may be required under our revolving bank credit facility to liquidate hedge positions allocated
to offshore production. Depending on prices in effect at the time of liquidation, we could be
required to make a significant payment to unwind and settle these contracts. We would expect to
fund the settlement of these contracts with proceeds from the sale of any Gulf of Mexico assets
and/or borrowings under our revolving bank credit facility.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2005 |
|
|
|
Payments Due by Period |
|
|
|
Reference |
|
|
Total |
|
|
1 year or less |
|
|
2 3 years |
|
|
4 5 years |
|
|
after 5 years |
|
|
|
(in thousands) |
|
Contractual Obligations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revolving bank credit facility, due November 2010 |
|
Note 2 |
|
$ |
422,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
422,000 |
|
|
$ |
|
|
7% senior subordinated notes, due June 2013 |
|
Note 2 |
|
|
175,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
175,000 |
|
Derivative instruments |
|
Note 7 |
|
|
417,657 |
|
|
|
352,456 |
|
|
|
65,201 |
|
|
|
|
|
|
|
|
|
Seismic data purchase |
|
Note 9 |
|
|
10,714 |
|
|
|
10,714 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating leases |
|
Note 9 |
|
|
6,599 |
|
|
|
1,796 |
|
|
|
3,718 |
|
|
|
1,085 |
|
|
|
|
|
Letters of credit |
|
Note 9 |
|
|
300 |
|
|
|
300 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,032,270 |
|
|
|
365,266 |
|
|
|
69,919 |
|
|
|
423,085 |
|
|
|
175,000 |
|
Other Long-Term Obligations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations |
|
Note 1 |
|
|
119,671 |
|
|
|
7,265 |
|
|
|
30,301 |
|
|
|
20,050 |
|
|
|
62,055 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual obligations and commitments |
|
|
|
|
|
$ |
1,151,941 |
|
|
$ |
372,531 |
|
|
$ |
99,220 |
|
|
$ |
443,135 |
|
|
$ |
237,055 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Resources
We intend to fund our capital expenditure program, contractual commitments, including settlement of
derivative contracts and future acquisitions with the proceeds from the pending sale of the Texas
portion of our Gulf of Mexico assets and/or from cash flows from our operations and borrowings
under our revolving bank credit facility. We expect to use the proceeds from any sale of the
remaining portion of our Gulf of Mexico assets for one or more of the following purposes:
acquiring additional onshore assets, repaying indebtedness or repurchasing shares of our common
stock.
At December 31, 2005, we had $177.7 million of excess borrowing capacity under our revolving bank
credit facility. We expect our borrowing base to decrease upon completion of the pending sale of
the Texas portion of our Gulf of Mexico assets, and to decrease further upon any sale of our
remaining Gulf of Mexico assets. If a significant acquisition opportunity arises, we may also
access public markets to issue additional debt and/or equity securities. Our primary sources of
cash during 2005 were from funds generated from operations and bank borrowings. Cash was used
primarily to fund acquisitions, exploration and development expenditures and settlements required
on derivative contracts. During 2005, we made aggregate cash payments of $23.9 million and $19.3
million, respectively, for interest and taxes. The table below summarizes the sources of cash
during 2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
variance |
|
|
% change |
|
|
|
(in thousands) |
|
Net cash provided by operating activities |
|
$ |
460,509 |
|
|
$ |
527,141 |
|
|
$ |
(66,632 |
) |
|
|
-13 |
% |
Net cash used in investing activities |
|
|
(727,003 |
) |
|
|
(509,922 |
) |
|
|
( 217,081 |
) |
|
|
43 |
% |
Net cash
provided by (used in) financing activities |
|
|
255,896 |
|
|
|
(1,211 |
) |
|
|
257,107 |
|
|
|
+100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (decrease) increase in cash |
|
$ |
(10,598 |
) |
|
$ |
16,008 |
|
|
$ |
(26,606 |
) |
|
|
-100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2005, we had a working capital deficit of $214.5 million and long-term debt of
$597.0 million. The working capital deficit at December 31, 2005 was due to a current liability of
$352.5 million representing the fair value of
-38-
our derivative instruments estimated to be payable over the next 12 months, offset in part by the
associated deferred tax asset of $157.1 million. As a result of the sustained high level of
natural gas prices, the fair value of our open derivative contracts payable within the next 12
months increased by $284.4 million from a liability of $68.1 million at December 31, 2004, to a
liability of $352.5 million at December 31, 2005. Corresponding to the increase in the liability,
the associated deferred tax asset increased by $130.5 million during this same twelve-month period
of 2005. The fair value of our derivative instruments will fluctuate with commodity prices, and as
commodity prices increase, our liquidity exposure tends to increase as a result of open derivative
instruments. Consequently, we are more likely to have the largest unfavorable mark-to-market
position in a high commodity price environment. Our working capital balance fluctuates as a result
of the timing and amount of cash receipts and disbursements for operating activities and borrowings
or repayments under our revolving bank credit facility. As a result, we often have a working
capital deficit or a relatively small amount of positive working capital, which we believe is
typical of companies of our size in the exploration and production industry. However, the sharp
rise in prices at the end of September triggered in part by Hurricanes Katrina and Rita, resulted
in a larger negative fair value than we consider normal. Prices have declined considerably and
closed at $7.112 per MMBtu for March 2006 down from the $11.00 to $14.00 per MMBtu range during the
fourth quarter of 2005. In addition, we may liquidate a portion of our offshore hedge position
in connection with the pending sale of the Texas portion of our Gulf
of Mexico assets and/or following any subsequent sale of the remaining portion of our Gulf of Mexico assets. At December 31, 2005, the
fair value of derivative obligations allocated to offshore production for years 2006, 2007 and 2008
was a liability of $182.7 million ($118.0 million net of tax) which approximates the amount
deferred in accumulated other comprehensive income at the end of the period.
Operating Activities. Net cash provided by operating activities decreased by $78.0 million or 14%
during 2005. The decrease was primarily a result of the 31% decrease in operating income during
2005. In addition to fluctuations in operating assets and liabilities that are caused by timing of
cash receipts and disbursements, commodity prices, production volume and operating expenses are the
key factors driving changes in operating cash flows. For 2005, we experienced lower production
volumes together with higher operating expenses.
Investing Activities. Total company capital expenditures during 2005 were $744.6 million which
included $10.6 million in drilling costs accrued and unpaid at December 31, 2005. During 2005, we
spent $226.1 million or 44% more than we spent during 2004. During 2005, we invested $743.3
million in natural gas and oil properties, which included $197.7 million for the acquisition of
producing properties and, we spent $1.3 million for non-oil and gas property and equipment.
Non-oil and gas property and equipment includes expenditures to upgrade to our information
technology systems and office equipment and compares to $1.5 million spent in 2004. For 2005, we
spent 32% offshore and 64% onshore with the balance of 4% on capitalized interest and general and
administrative costs. We completed the drilling of a record 336 gross wells (269.8 net) of which
87% or 298 (238.4 net) were successful and 38 (31.3 net) were unsuccessful with an additional 13
wells (8.9 net) in progress at the end to the year.
The table below provides a five-year historical analysis of our capital expenditures for natural
gas and oil properties and total net proved reserve additions, that is defined as the sum of
reserve extensions and discoveries, revisions and acquisitions. See Note 12 Supplemental
Information on Natural Gas and Oil Exploration, Development and Production Activities for a detail
calculation of the changes in our reserve quantities during the period.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
2002 |
|
|
2001 |
|
|
|
(in thousands) |
|
Natural gas and oil capital expenditures |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing property acquisitions |
|
$ |
197,680 |
|
|
$ |
149,599 |
|
|
$ |
175,420 |
|
|
$ |
73,351 |
|
|
$ |
69,010 |
|
Leasehold and lease acquisition costs (1) |
|
|
66,113 |
|
|
|
57,741 |
|
|
|
56,076 |
|
|
|
36,458 |
|
|
|
48,068 |
|
Development |
|
|
366,902 |
|
|
|
245,971 |
|
|
|
162,235 |
|
|
|
122,036 |
|
|
|
177,256 |
|
Exploration |
|
|
112,634 |
|
|
|
63,646 |
|
|
|
66,259 |
|
|
|
26,536 |
|
|
|
72,056 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total natural gas and oil capital expenditures |
|
|
743,329 |
|
|
|
516,957 |
|
|
|
459,990 |
|
|
|
258,381 |
|
|
|
366,390 |
|
Producing property dispositions |
|
|
(1,864 |
) |
|
|
(72,712 |
) |
|
|
|
|
|
|
(5,309 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net natural gas and oil capital expenditures |
|
$ |
741,465 |
|
|
$ |
444,245 |
|
|
$ |
459,990 |
|
|
$ |
253,072 |
|
|
$ |
366,390 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserve additions, net of revisions
(MMcfe) |
|
|
183,787 |
|
|
|
225,633 |
|
|
|
212,969 |
|
|
|
144,291 |
|
|
|
136,231 |
|
|
|
|
(1) |
|
For 2005, 2004, 2003, 2002 and 2001, leasehold costs include capitalized
interest and general and administrative expenses of $25.7 million $23.2 million, $20.2
million, $21.1 million, and $24.9 million, respectively. |
-39-
Financing Activities. During 2005, total long-term debt increased by a net $242 million, as we
borrowed under our revolving bank credit facility in part to fund acquisitions totaling $197.7
million and in part to fund cash requirements for the settlement of derivative contracts.
Access to Capital Markets. We have the capacity to offer up to $750 million of our common stock,
preferred stock, depositary shares and debt securities, or a combination of any of these
securities, under effective shelf registration statements filed with the SEC in March and October
2004.
We believe that operating cash flow and our credit facility will be adequate to meet our capital
and operating requirements during 2006. We continuously monitor our working capital and debt
position as well as coordinate our capital expenditure program with expected cash flows and
projected debt repayment schedules. In November 2005, we increased the lending commitment under
our revolving bank credit facility from $450 million to $750 million with an additional $100
million available upon request and with prior approval from our lenders. Amounts available for
borrowing under the credit facility are limited to a borrowing base, which as of December 31, 2005
was $600 million. The borrowing base of $600 million is expected to remain in effect until the
next scheduled redetermination on April 1, 2006. However, we expect our borrowing base to be
reduced upon consummation of the pending sale of the Texas portion of our Gulf of Mexico Assets and
likely would be further reduced upon any sale of the remaining portion of our Gulf of Mexico assets. In addition to operating cash flow and borrowings
under the revolving credit facility, we believe we could finance capital
expenditures with issuances of additional equity or debt securities or development with industry
partners.
We plan to reinvest the net cash proceeds from the pending sale of the Texas portion of our Gulf of
Mexico assets into longer-lived natural gas and oil assets onshore in North America. Our plans
include structuring the reinvestment, where possible, to optimize the tax effects under the tax
free exchange rules of Section 1031 of the Internal Revenue Code. However, numerous market
conditions and uncertainties may not allow for the reinvestment of all of the proceeds within the
prescribed time period for the most effective tax treatment. To the
extent we are not able to reinvest any such proceeds, we would then expect to repay debt.
Stock
Repurchase Program. In November 2005, our Board of Directors approved a plan for discretionary repurchases from time to
time of up to $200 million in company stock in conjunction with the possible divesture of all of
our Gulf of Mexico assets. These purchases may be in the open market or in privately negotiated
transactions, and will be subject to a number of considerations, including market conditions for
our shares, applicable legal requirements and contractual restrictions, available cash, competing
reinvestment opportunities in the acquisition market for oil and gas assets and other factors. No
repurchases have been made as of the date of this Annual Report.
Off-Balance Sheet Arrangements
We do not currently utilize any off-balance sheet arrangements to enhance liquidity and capital
resource positions, or for any other purpose.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Market Risk
Our major market risk exposure continues to be the prices applicable to our natural gas and oil
production. Our sales price is primarily driven by the prevailing market price. Historically,
prices received for our natural gas and oil production have been volatile and unpredictable.
Interest Rate Market Risk
At December 31, 2005, our total debt was $597.0 million, of which approximately 29% or $175 million
is fixed at an interest rate of 7%. The remaining 71% of our total debt balance at December 31,
2005, or $422 million, represents our bank debt that is tied to floating or market interest rates,
prime rate or LIBOR at our election. Fluctuations in floating interest rates will cause our annual
interest costs relating to our bank debt to fluctuate. During the fourth quarter of 2005, the
interest rate on our outstanding bank debt averaged 6.17%. If the balance of our bank debt at
December 31, 2005 were to remain constant, a 10% change in market interest rates would impact our
cash flow by an estimated $650,000 per quarter.
-40-
Commodity Risk
We utilize derivative commodity instruments to hedge future sales prices on a portion of our
natural gas and oil production to achieve more predictable cash flows, as well as to reduce our
exposure to adverse price fluctuations of natural gas. Our derivatives are not held for trading
purposes and our hedging policy prescribes that at the time we enter
into a contract that all hedge structures meet the requirements for
hedging accounting under SFAS 133 and that each transaction is specifically identified as a hedge
for Federal income tax purposes as defined in Section 1221(b)(2) of the Internal Revenue Code.
While the use of certain hedging arrangements limits the downside risk of adverse price movements,
it also limits increases in future revenues as a result of favorable price movements, as has been
the case in recent years, especially during the last four months of 2005. The use of hedging
transactions also involves the risk that the counterparties are unable to meet the financial terms
of such transactions. Hedging instruments that we typically use are swaps, collars and options,
which we generally place with major investment grade financial institutions that we believe are
minimal credit risks. We believe that our credit risk related to our natural gas hedging
instruments is no greater than the risk associated with the primary contracts and that the
elimination of price risk reduces volatility in our reported results of operations, financial
position and cash flows from period to period and lowers our overall business risk; however, as a
result of our hedging activities, we may be exposed to greater credit risk in the future.
Generally, our hedges qualify for hedge accounting under SFAS 133 and, accordingly, we carry the
fair market value of our derivative instruments on the balance sheet as either an asset or
liability and defer unrealized gains or losses, net of tax, in accumulated other comprehensive
income. Gains and losses are reclassified from accumulated other comprehensive income to the income
statement as a component of natural gas and oil revenues in the period the hedged production
occurs. If any ineffectiveness occurs, amounts are recorded directly to natural gas and oil
revenues and would be included as a component of the line item natural gas and oil revenues. For
us, ineffectiveness is primarily a result of changes at the end of each period in the price
differentials between the price of the derivative contract, which uses a NYMEX price, and the index
price for the point of sale for the cash flow that is being hedged, of which approximately 30% is
the Houston Ship Channel index. If our hedges cease to qualify for hedge accounting as a result of
ineffectiveness, as was the case during the fourth quarter of 2005 as a result of a loss of market
correlation between the NYMEX price and the Houston Ship Channel index, we include the
mark-to-market change in the fair value of open contracts in income.
Changes in Fair Value of Derivative Instruments
The following table summarizes the change in the fair value of our derivative instruments for each
of the twelve-month periods from January 1 to December 31, 2005 and 2004 and provides the fair
value at the end of each period:
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
Change in Fair Value of Derivatives Instruments: |
|
Before Tax |
|
|
|
(in thousands) |
|
Fair value of contracts at January 1 |
|
$ |
(75,149 |
) |
|
$ |
(36,862 |
) |
Realized loss on contracts settled |
|
|
265,236 |
|
|
|
68,195 |
|
Fair value of new contracts when entered into |
|
|
|
|
|
|
|
|
(Decrease) in fair value of all open contracts |
|
|
(607,745 |
) |
|
|
(106,482 |
) |
|
|
|
|
|
|
|
Net (decrease)
increase during period |
|
|
(342,509 |
) |
|
|
(38,287 |
) |
|
|
|
|
|
|
|
Fair value of contracts outstanding at December 31 |
|
$ |
(417,658 |
) |
|
$ |
(75,149 |
) |
|
|
|
|
|
|
|
-41-
Derivatives in Place as of the Date of Our Report
The following table summarizes, on an annual basis, our natural gas hedges in place for 2006, 2007
and 2008 as of December 31, 2005. There have been no changes since the balance sheet date.
In
connection with the pending sale of the Texas portion of our Gulf of
Mexico assets and/or any subsequent sale of the remaining portion of our Gulf of Mexico assets, we may liquidate a
portion of our 2006 hedge position associated with our offshore production, subject to the outcome
of our sale process, requirements under our revolving bank credit
facility, superseding operational developments and acquisition activities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Daily Volume |
|
|
NYMEX Price |
|
|
Floor Price |
|
|
Ceiling Price |
|
Year |
|
Transaction Type |
|
(MMBtu/day) |
|
|
($/MMBtu) |
|
|
($/MMBtu) |
|
|
($/MMBtu) |
|
|
2006 |
|
Swap |
|
|
20,000 |
|
|
$ |
5.87 |
|
|
|
|
|
|
|
|
|
2006 |
|
Swap |
|
|
10,000 |
|
|
|
5.94 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total swaps |
|
|
30,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
Costless collar |
|
|
10,000 |
|
|
|
|
|
|
$ |
5.50 |
|
|
$ |
7.20 |
|
2006 |
|
Costless collar |
|
|
10,000 |
|
|
|
|
|
|
|
5.50 |
|
|
|
7.25 |
|
2006 |
|
Costless collar |
|
|
40,000 |
|
|
|
|
|
|
|
5.50 |
|
|
|
7.26 |
|
2006 |
|
Costless collar |
|
|
20,000 |
|
|
|
|
|
|
|
5.75 |
|
|
|
7.20 |
|
2006 |
|
Costless collar |
|
|
30,000 |
|
|
|
|
|
|
|
5.80 |
|
|
|
7.00 |
|
2006 |
|
Costless collar |
|
|
50,000 |
|
|
|
|
|
|
|
5.82 |
|
|
|
7.00 |
|
2006 |
|
Costless collar |
|
|
30,000 |
|
|
|
|
|
|
|
6.00 |
|
|
|
7.00 |
|
2006 |
|
Costless collar |
|
|
20,000 |
|
|
|
|
|
|
|
6.00 |
|
|
|
7.02 |
|
2006 |
|
Costless collar |
|
|
10,000 |
|
|
|
|
|
|
|
6.00 |
|
|
|
7.05 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total collars |
|
|
220,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total daily volume 2006 |
|
|
250,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
Costless collar |
|
|
20,000 |
|
|
|
|
|
|
$ |
5.00 |
|
|
$ |
6.50 |
|
2007 |
|
Costless collar |
|
|
10,000 |
|
|
|
|
|
|
|
5.00 |
|
|
|
6.79 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total daily volume 2007 |
|
|
30,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
Costless collar |
|
|
20,000 |
|
|
|
|
|
|
$ |
5.00 |
|
|
$ |
5.72 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total daily volume 2008 |
|
|
20,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For natural gas, transactions are settled based upon the NYMEX price on the final trading day of
the month. In order to determine fair market value of our derivative instruments, we obtain
mark-to-market quotes from external counterparties.
With respect to any particular swap transaction, the counterparty is required to make a payment to
us if the settlement price for any settlement period is less than the swap price for the
transaction, and we are required to make payment to the counterparty if the settlement price for
any settlement period is greater than the swap price for the transaction. For any particular collar
transaction, the counterparty is required to make a payment to us if the settlement price for any
settlement period is below the floor price for the transaction, and we are required to make payment
to the counterparty if the settlement price for any settlement period is above the ceiling price
for the transaction. We are not required to make or receive any payment in connection with a collar
transaction if the settlement price is between the floor and the ceiling. For option contracts, we
have the option, but not the obligation, to buy contracts at the strike price up to the day before
the last trading day for that NYMEX contract.
Item 8. Financial Statements and Supplemental Data
For financial statements required by Item 8, see Item 15 in Part IV of this Annual Report.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
-42-
Item 9A. Controls and Procedures
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Under the supervision and with the participation of our management, including our Chief Executive
Officer and our Chief Financial Officer, we conducted an evaluation of our disclosure controls and
procedures, as this term is defined under Rule 13a-15(e) promulgated under the Securities Exchange
Act of 1934, as amended (the Exchange Act). Based on this evaluation, our Chief Executive Officer
and our Chief Financial Officer concluded that our disclosure controls and procedures were
effective as of the end of the period covered by this Annual Report.
Design and Evaluation of Internal Control Over Financial Reporting
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, 2005. Deloitte and Touche LLP,
our independent public accountants, also attested to, and reported on, managements assessment of
the effectiveness of internal control over financial reporting. Managements report and the
independent registered public accounting firms attestation report are included in our 2005
Financial Statements in Item 15 under the captions entitled Managements Report on Internal
Control Over Financial Reporting and Report of Independent Registered Public Accounting Firm and
are incorporated herein by reference.
Changes in Internal Control Over Financial Reporting
No change in our internal control over financial reporting (as defined in Rule 13a-15(f) under the
Securities Exchange Act of 1934) occurred during the fourth quarter of our fiscal year ended
December 31, 2005 that has materially affected, or is reasonably likely to materially affect, our
internal control over financial reporting.
Item 9B. Other Information.
None.
Part III.
Item 10. Directors and Executive Officers of Houston Exploration
The information required by Item 10 that relates to our directors and executive officers is
incorporated by reference from the information appearing under the captions Election of
Directors, Executive Officers, Committee Assignments Committee Functions Audit Committee,
Committee Functions Nominating and Governance Committee and Beneficial Ownership Reporting and
Compliance Section 16(a) in our definitive proxy statement that is to be filed with the SEC
pursuant to the Exchange Act within 120 days of the end of our fiscal year on December 31, 2005.
Item 11. Executive Compensation
The information required by Item 11 that relates to compensation of our principal executive
officers and our directors is incorporated by reference from the information appearing under the
captions Summary Compensation Table, Options Granted In 2005, Aggregated Options Exercised in
2005 and Director Compensation in our definitive proxy statement that is to be filed with the
SEC within 120 days of the end of our fiscal year on December 31, 2005. In addition and in
accordance with Item 402(a)(8) of Regulation S-K, the information contained in our definitive proxy
statement under the subheading Report of the Compensation and Management Development Committee of
the Board of Directors and Performance Graph shall not be deemed to be filed as part of, or
incorporated by reference into, this Annual Report. For information concerning our code of ethics,
see Item 1. and 2. Business and Properties Available Information.
Item 12. Security Ownership of Beneficial Owners and Management
The information required by Item 12 that relates to the ownership of securities by management and
others is incorporated by reference from the information appearing under the caption Equity
Compensation Plan Information and Security Ownership of Certain Beneficial Owners and Management
in our definitive proxy statement that is to be filed with the SEC within 120 days of the end of
our fiscal year on December 31, 2005.
Item 13. Certain Relationships and Related Transactions
The information required by Item 13 that relates to business relationships and transactions with
our management and other related parties is incorporated by reference from the information
appearing under the captions Related Party Transactions, Transactions Between the Company and
Managements and Compensation Committee Interlocks and Insider
-43-
Participation in our definitive proxy statement that is to be filed with the SEC within 120 days
of the end of our fiscal year on December 31, 2005.
Item 14. Principal Accounting Fees and Services
The information required by Item 14 that relates to services provided by our Independent Public
Accountants and the fees incurred for services provided during 2005 and 2004 is incorporated by
reference from the information appearing under the captions Fees Billed by Independent Public
Accountants in our definitive proxy statement that is to be filed with the SEC within 120 days of
the end of our fiscal year on December 31, 2005.
Part IV.
Item 15. Exhibits, Financial Statement Schedules
(a) Documents Filed as a Part of this Report
1. Financial Statements:
|
|
|
|
|
|
|
PAGE |
|
Index to Financial Statements |
|
|
F-1 |
|
Managements Report on Internal Controls Over Financial Reporting |
|
|
F-2 |
|
Report of Independent Registered Public Accounting Firm |
|
|
F-3 |
|
Consolidated Balance Sheets as of December 31, 2005 and 2004 |
|
|
F-4 |
|
Consolidated Statements of Operations for the Years Ended December 31, 2005, 2004 and 2003 |
|
|
F-5 |
|
Consolidated Statements of Stockholders Equity and Comprehensive Income (Loss) for the Period
January 1, 2003 to December 31, 2005 |
|
|
F-6 |
|
Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003 |
|
|
F-7 |
|
Notes to Consolidated Financial Statements |
|
|
F-8 |
|
Supplemental Information on Natural Gas and Oil Exploration, Development and
Production Activities (unaudited) |
|
|
F-30 |
|
Quarterly Financial Information (Unaudited) |
|
|
F-34 |
|
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.
2. Exhibits:
(a) See
Index of Exhibits on page F-36 for a description of the exhibits filed as a part of this report.
-44-
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.
|
|
|
|
|
|
|
THE HOUSTON EXPLORATION COMPANY |
|
|
|
|
|
|
|
By:
|
|
/s/ William G. Hargett |
|
|
|
|
|
|
|
|
|
William G. Hargett |
Date:
March 3, 2006
|
|
|
|
President and Chief Executive Officer |
-45-
POWER OF ATTORNEY
Each person whose signature appears below hereby constitutes and appoints Robert T. Ray and James
F. Westmoreland, and each of them, his true and lawful attorney-in-fact and agent, with full powers
of substitution, for him and in his name, place and stead, in any and all capacities, to sign any
and all amendments to this Annual Report of Form 10-K, and to file the same, with all exhibits
thereto, and other documents in connection therewith, with the Securities and Exchange Commission
granting to said attorneys-in-fact, and each of them, full power and authority to perform any other
act on behalf of the undersigned required to be done in connection therewith.
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 in the capacities and on the dates
indicated.
|
|
|
|
|
Signature |
|
Title |
|
Date |
|
|
|
|
|
/s/ William G. Hargett
William G. Hargett
|
|
Chairman of the Board of Directors,
President and Chief Executive Officer
(Principal Executive Officer)
|
|
March 3, 2006 |
|
|
|
|
|
/s/ Robert T. Ray
Robert T. Ray
|
|
Senior Vice President and Chief Financial
Officer
(Principal Financial Officer)
|
|
March 3, 2006 |
|
|
|
|
|
/s/ James F. Westmoreland
James F. Westmoreland
|
|
Vice President and Chief Accounting Officer
(Principal Accounting Officer)
|
|
March 3, 2006 |
|
|
|
|
|
/s/ Robert B. Catell
Robert B. Catell
|
|
Director
|
|
March 3, 2006 |
|
|
|
|
|
/s/ John U. Clarke
John U. Clarke
|
|
Director
|
|
March 3, 2006 |
|
|
|
|
|
/s/ David G. Elkins
David G. Elkins
|
|
Director
|
|
March 3, 2006 |
|
|
|
|
|
/s/ Harold R. Logan, Jr.
Harold R. Logan, Jr.
|
|
Director
|
|
March 3, 2006 |
|
|
|
|
|
/s/ Thomas A. McKeever
Thomas A. McKeever
|
|
Director
|
|
March 3, 2006 |
|
|
|
|
|
/s/ Stephen W. McKessy
Stephen W. McKessy
|
|
Director
|
|
March 3, 2006 |
|
|
|
|
|
/s/ Donald C. Vaughn
Donald C. Vaughn
|
|
Director
|
|
March 3, 2006 |
-46-
Glossary of Oil and Gas Terms
The definitions set forth below apply to the indicated terms as used in this Annual Report on Form
10-K. All volumes of natural gas referred to are stated at the legal pressure base of the state or
area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the
nearest major multiple.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to crude oil or
other liquid hydrocarbons.
Bbl/d. One barrel per day.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one
Bbl of crude oil, condensate or natural gas liquids.
Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass
of water from 58.5 to 59.5 degrees Fahrenheit.
Completion. The installation of permanent equipment for the production of oil or gas, or in the
case of a dry hole, the reporting of abandonment to the appropriate agency.
Deep Shelf. Structures located on the United States Outer Continental Shelf of the Gulf of Mexico
at depths generally greater than 15,000 feet in areas where there has been limited or no production
from deeper stratigraphic zones.
Developed acreage. The number of acres allocated or assignable to producing wells or wells capable
of production.
Developed well. A well drilled within the proved area of an oil or gas reservoir to the depth of a
stratigraphic horizon known to be productive.
Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities
such that proceeds from the sale of the production exceed production expenses and taxes.
Equivalents. When we refer to equivalents, we are doing so to compare quantities of oil with
quantities of natural gas or to express these different commodities in a common unit. In
calculating equivalents, we use a generally recognized standard in which one barrel of oil is equal
to six thousand cubic feet of natural gas.
Exploratory well. A well drilled to find and produce oil or gas reserves not classified as proved,
to find a new reservoir in a field previously found to be productive of oil or gas in another
reservoir or to extend a known reservoir.
Farm-in or farm-out. An agreement where the owner of a working interest in an natural gas and oil
lease assigns the working interest or a portion of the working interest to another party who
desires to drill on the leased acreage. Generally, the assignee is required to drill one or more
wells in order to earn its interest in the acreage. The assignor usually retains a royalty or
reversionary interest in the lease. The interest received by an assignee is a farm-in while the
interest transferred by the assignor is a farm-out.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to
the same individual geological structural feature or stratigraphic condition.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working
interest is owned.
Intangible Drilling and Development Costs. Expenditures made by an operator for wages, fuel,
repairs, hauling, supplies, surveying, geological works etc., incident to and necessary for the
preparing for and drilling of wells and the construction of production facilities and pipelines.
Lease Operating Expense. Recurring expenses incurred to operate wells and equipment on a producing
lease. Examples include: pumping and gauging, chemicals, compression, fuel and water, insurance
and property taxes.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
MBbls/d. One thousand barrels of crude oil or other liquid hydrocarbons per day.
Mcf. One thousand cubic feet.
G-1
Mcf/d. One thousand cubic feet per day.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to
one Bbl of crude oil, condensate or natural gas liquids.
Mcfe/d. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to
one Bbl of crude oil, condensate or natural gas liquids per day.
MMBbls. One million barrels of crude oil or other liquid hydrocarbons.
MMbtu. One million Btus.
MMMbtu. One billion Btus.
MMcf. One million cubic feet.
MMcf/d. One million cubic feet per day.
MMcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to
one Bbl of crude oil, condensate or natural gas liquids.
Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross
wells.
Net revenue interest. An interest in the production and revenues created from the working interest
which is generally calculated net or after deducting any royalty interests.
Oil. Crude oil and condensate.
Present value or PV10. When used with respect to natural gas and oil reserves, the estimated future
gross revenue to be generated from the production of proved reserves, net of estimated production
and future development costs, using prices and costs in effect as of the date indicated, without
giving effect to non-property related expenses such as general and administrative expenses, debt
service and future income tax expenses or to depreciation, depletion and amortization, discounted
using an annual discount rate of 10%.
Productive well. A well that is found to be capable of producing hydrocarbons in sufficient
quantities such that proceeds from the sale of the production exceed production expenses and taxes.
Proved developed nonproducing reserves. Proved developed reserves expected to be recovered from
zones behind casing in existing wells.
Proved developed producing reserves. Proved developed reserves that are expected to be recovered
from completion intervals currently open in existing wells and able to produce to market.
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 economic and operating conditions. In addition, please
refer to the definitions of proved oil and gas reserves as provided in Rule 4-10(a)(2)(3)(4) of
Regulation S-X of the federal securities laws. The rule is available at the SEC web site,
http://www.sec.gov/divisions/corpfin/forms/regsx.htm#gas.
Proved undeveloped location. A site on which a development well can be drilled consistent with
spacing rules for purposes of recovering proved undeveloped reserves.
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 from
recompletion.
Recompletion. The completion for production of an existing well bore in another formation from that
in which the well has been previously completed.
Reservoir. A porous and permeable underground formation containing a natural accumulation of
producible oil or gas that is confined by impermeable rock or water barriers and is individual and
separate from other reservoirs.
G-2
Royalty interest. An interest in a natural gas and oil property entitling the owner to a share of
natural gas or oil production free of costs of production.
Tangible Drilling and Development Costs. Cost of physical lease and well equipment and structures.
The costs of assets that themselves have a salvage value.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point
that would permit the production of commercial quantities of natural gas and oil regardless of
whether the acreage contains proved reserves.
Working interest. The operating interest which gives the owner the right to drill, produce and
conduct operating activities on the property and a share of production.
Workover. Operations on a producing well to restore or increase production.
G-3
Index to Financial Statements
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|
|
|
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|
|
Page |
|
|
|
F-2 |
|
|
|
|
F-3 |
|
|
|
|
F-4 |
|
|
|
|
F-5 |
|
|
|
|
F-6 |
|
|
|
|
F-7 |
|
|
|
|
F-8 |
|
Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities
(Unaudited) |
|
|
F-30 |
|
Quarterly Financial Information (Unaudited) |
|
|
F-34 |
|
F-1
MANAGEMENTS REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
To the Board of Directors and Stockholders of
The Houston Exploration Company
The Houston Exploration Companys management is responsible for establishing and maintaining
adequate internal control over financial reporting, as such term is defined in Exchange Act Rules
13a-15(f). Under the supervision and with the participation of management, including Houston
Explorations principal executive officer and principal financial officer, Houston Exploration
conducted an evaluation of the effectiveness of internal control over financial reporting based on
the framework in Internal Control Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission.
Based on Houston Explorations evaluation under the framework in Internal Control Integrated
Framework, our principal executive officer and principal financial officer concluded that internal
control over financial reporting was effective as of December 31, 2005. The conclusion of our
principal executive officer and principal financial officer is based on the recognition that there
are inherent limitations in all systems of internal control. 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 polices or procedures may deteriorate. Managements assessment of the effectiveness of
internal control over financial reporting as of December 31, 2005 has been audited by Deloitte &
Touche LLP, an independent registered public accounting firm, as stated in their report which is
included herein.
The Houston Exploration Company
Houston, Texas
March 3, 2006
|
|
|
/s/ William G. Hargett
|
|
/s/ Robert T. Ray |
|
|
|
William G. Hargett
|
|
Robert T. Ray |
Chairman, President and Chief Executive Officer
|
|
Senior Vice President and Chief Financial Officer |
F-2
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
The Houston Exploration Company
Houston, Texas
We have audited the accompanying consolidated balance sheets of The Houston Exploration Company (a
Delaware corporation) and subsidiaries (the Company) as of December 31, 2005 and 2004, and the
related consolidated statements of operations, stockholders equity and comprehensive income
(loss), and cash flows for each of the three years in the period ended December 31, 2005. We also
have audited managements assessment, included in the accompanying Managements Report on Internal
Control Over Financial Reporting, that the Company maintained effective internal control over
financial reporting as of December 31, 2005, based on criteria established in Internal
ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission. The Companys management is responsible for these financial statements, for
maintaining effective internal control over financial reporting, and for its assessment of the
effectiveness of internal control over financial reporting. Our responsibility is to express an
opinion on these financial statements, an opinion on managements assessment, and an opinion on the
effectiveness of the Companys internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement and
whether effective internal control over financial reporting was maintained in all material
respects. Our audit of financial statements included examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing the accounting
principles used and significant estimates made by management, and evaluating the overall financial
statement presentation. Our audit of internal control over financial reporting included obtaining
an understanding of internal control over financial reporting, evaluating managements assessment,
testing and evaluating the design and operating effectiveness of internal control, and performing
such other procedures as we considered necessary in the circumstances. We believe that our audits
provide a reasonable basis for our opinions.
A companys internal control over financial reporting is a process designed by, or under the
supervision of, the companys principal executive and principal financial officers, or persons
performing similar functions, and effected by the companys board of directors, management, and
other personnel 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 the inherent limitations of internal control over financial reporting, including the
possibility of collusion or improper management override of controls, material misstatements due to
error or fraud may not be prevented or detected on a timely basis. Also, projections of any
evaluation of the effectiveness of the internal control over financial reporting to future periods
are subject to the risk that the 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, the consolidated financial statements referred to above present fairly, in all
material respects, the financial position of the Company as of December 31, 2005 and 2004, and the
results of its operations and its cash flows for each of the three years in the period ended
December 31, 2005, in conformity with accounting principles generally accepted in the United States
of America. Also in our opinion, managements assessment that the Company maintained effective
internal control over financial reporting as of December 31, 2005, is fairly stated, in all
material respects, based on the criteria established in Internal ControlIntegrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission. Furthermore, in our
opinion, the Company maintained, in all material respects, effective internal control over
financial reporting as of December 31, 2005, based on the criteria established in Internal
ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission.
As discussed in Note 1 to the consolidated financial statements, the Company adopted Statement of
Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, and
SFAS No. 148, Accounting for Stock-Based Compensation Transition and Disclosure, on January 1,
2003.
DELOITTE & TOUCHE LLP
Houston,
Texas
March 3, 2006
F-3
THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2005 |
|
|
2004 |
|
Assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
7,979 |
|
|
$ |
18,577 |
|
Accounts receivable |
|
|
146,020 |
|
|
|
103,069 |
|
Inventories |
|
|
2,726 |
|
|
|
976 |
|
Deferred tax asset |
|
|
145,922 |
|
|
|
24,101 |
|
Prepayments and other |
|
|
19,709 |
|
|
|
9,107 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
322,356 |
|
|
|
155,830 |
|
|
|
|
|
|
|
|
|
|
Natural gas and oil properties, full cost method |
|
|
|
|
|
|
|
|
Unevaluated properties |
|
|
107,146 |
|
|
|
122,691 |
|
Properties subject to amortization |
|
|
3,556,755 |
|
|
|
2,777,097 |
|
Other property and equipment |
|
|
12,971 |
|
|
|
11,740 |
|
|
|
|
|
|
|
|
|
|
|
3,676,872 |
|
|
|
2,911,528 |
|
|
|
|
|
|
|
|
|
|
Less: Accumulated depreciation, depletion and amortization |
|
|
1,658,532 |
|
|
|
1,363,272 |
|
|
|
|
|
|
|
|
|
|
|
2,018,340 |
|
|
|
1,548,256 |
|
|
|
|
|
|
|
|
|
|
Other non-current assets |
|
|
20,928 |
|
|
|
18,491 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets |
|
$ |
2,361,624 |
|
|
$ |
1,722,577 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
Accounts payable and accrued expenses |
|
$ |
177,159 |
|
|
$ |
118,971 |
|
Derivative financial instruments |
|
|
352,457 |
|
|
|
68,081 |
|
Asset retirement obligation |
|
|
7,265 |
|
|
|
662 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
536,881 |
|
|
|
187,714 |
|
|
|
|
|
|
|
|
|
|
Long-term debt and notes |
|
|
597,000 |
|
|
|
355,000 |
|
Derivative financial instruments |
|
|
65,201 |
|
|
|
7,068 |
|
Deferred federal income taxes |
|
|
341,302 |
|
|
|
288,069 |
|
Asset retirement obligation |
|
|
112,406 |
|
|
|
91,084 |
|
Other non-current liabilities |
|
|
15,696 |
|
|
|
10,722 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities |
|
|
1,668,486 |
|
|
|
939,657 |
|
|
|
|
|
|
|
|
|
|
Commitments and Contingencies (see Note 9) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders Equity: |
|
|
|
|
|
|
|
|
Preferred Stock, $0.01 par value, 5,000,000 shares authorized and no shares issued |
|
|
|
|
|
|
|
|
Common Stock, $.01 par value, 100,000,000 shares authorized and 28,980,128 issued
and outstanding at December 31, 2005 and 50,000,000 shares authorized and
28,380,207 shares issued and outstanding at December 31, 2004 |
|
|
289 |
|
|
|
284 |
|
Additional paid-in capital |
|
|
305,077 |
|
|
|
273,002 |
|
Unearned compensation |
|
|
(7,859 |
) |
|
|
(2,537 |
) |
Retained earnings |
|
|
663,367 |
|
|
|
558,198 |
|
Accumulated other comprehensive income |
|
|
(267,736 |
) |
|
|
(46,027 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Stockholders Equity |
|
|
693,138 |
|
|
|
782,920 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Stockholders Equity |
|
$ |
2,361,624 |
|
|
$ |
1,722,577 |
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
F-4
THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas and oil revenues |
|
$ |
620,271 |
|
|
$ |
649,087 |
|
|
$ |
491,440 |
|
Other |
|
|
1,272 |
|
|
|
1,352 |
|
|
|
1,312 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
621,543 |
|
|
|
650,439 |
|
|
|
492,752 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating |
|
|
67,796 |
|
|
|
55,925 |
|
|
|
47,072 |
|
Severance tax |
|
|
18,121 |
|
|
|
11,933 |
|
|
|
15,958 |
|
Transportation expense |
|
|
11,883 |
|
|
|
11,819 |
|
|
|
10,387 |
|
Asset retirement accretion expense |
|
|
5,278 |
|
|
|
4,902 |
|
|
|
3,668 |
|
Depreciation, depletion and amortization |
|
|
295,351 |
|
|
|
265,148 |
|
|
|
197,530 |
|
General and administrative, net of amounts capitalized |
|
|
38,378 |
|
|
|
32,899 |
|
|
|
19,542 |
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses |
|
|
436,807 |
|
|
|
382,626 |
|
|
|
294,157 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations |
|
|
184,736 |
|
|
|
267,813 |
|
|
|
198,595 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other (income) expense |
|
|
142 |
|
|
|
(1,058 |
) |
|
|
(15,746 |
) |
Interest expense, net of amounts capitalized |
|
|
16,535 |
|
|
|
9,455 |
|
|
|
8,342 |
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
168,059 |
|
|
|
259,416 |
|
|
|
205,999 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision for taxes |
|
|
62,890 |
|
|
|
96,592 |
|
|
|
72,187 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting
principle |
|
$ |
105,169 |
|
|
$ |
162,824 |
|
|
$ |
133,812 |
|
Cumulative effect of change in accounting principle |
|
|
|
|
|
|
|
|
|
|
(2,772 |
) |
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
105,169 |
|
|
$ |
162,824 |
|
|
$ |
131,040 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
Net
income per share basic |
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in
accounting principle |
|
$ |
3.66 |
|
|
$ |
5.50 |
|
|
$ |
4.30 |
|
Cumulative effect of change in accounting principle |
|
|
|
|
|
|
|
|
|
|
(0.09 |
) |
|
|
|
|
|
|
|
|
|
|
Net income per share basic |
|
$ |
3.66 |
|
|
$ |
5.50 |
|
|
$ |
4.21 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share diluted |
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in
accounting principle |
|
$ |
3.62 |
|
|
$ |
5.44 |
|
|
$ |
4.29 |
|
Cumulative effect of change in accounting principle |
|
|
|
|
|
|
|
|
|
|
(0.09 |
) |
|
|
|
|
|
|
|
|
|
|
Net income per share diluted |
|
$ |
3.62 |
|
|
$ |
5.44 |
|
|
$ |
4.20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding basic |
|
|
28,707 |
|
|
|
29,616 |
|
|
|
31,097 |
|
Weighted average shares outstanding diluted |
|
|
29,037 |
|
|
|
29,932 |
|
|
|
31,213 |
|
The accompanying notes are an integral part of these consolidated financial statements.
F-5
THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
AND COMPREHENSIVE INCOME (LOSS)
(in thousands, except share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional |
|
|
|
|
|
|
|
|
|
|
Other |
|
|
Total |
|
|
|
Common Stock |
|
|
Paid-In |
|
|
Unearned |
|
|
Retained |
|
|
Comprehensive |
|
|
Shareholders |
|
|
|
Shares |
|
|
$ Value |
|
|
Capital |
|
|
Compensation |
|
|
Earnings |
|
|
Income (Loss) |
|
|
Equity |
|
Balance January 1, 2003 |
|
|
30,954,018 |
|
|
$ |
310 |
|
|
$ |
353,454 |
|
|
$ |
(107 |
) |
|
|
264,334 |
|
|
|
(25,202 |
) |
|
$ |
592,789 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
shares issued stock options |
|
|
461,563 |
|
|
|
5 |
|
|
|
10,218 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,223 |
|
Common
shares issued restricted
stock |
|
|
22,000 |
|
|
|
|
|
|
|
812 |
|
|
|
(812 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Common
shares issued public
offering |
|
|
3,000,000 |
|
|
|
30 |
|
|
|
79,170 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
79,200 |
|
Common shares repurchased from
KeySpan |
|
|
(3,000,000 |
) |
|
|
(30 |
) |
|
|
(79,170 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(79,200 |
) |
Amortization restricted stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
111 |
|
|
|
|
|
|
|
|
|
|
|
111 |
|
Stock
compensation expense stock
options |
|
|
|
|
|
|
|
|
|
|
903 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
903 |
|
Tax benefit exercise of
non-qualified stock options |
|
|
|
|
|
|
|
|
|
|
1,394 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,394 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
131,040 |
|
|
|
|
|
|
|
131,040 |
|
Other comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative settlements
reclassified to income, net of
tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
43,165 |
|
|
|
43,165 |
|
Unrealized loss change in fair
value of derivatives, net of
tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(44,091 |
) |
|
|
(44,091 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
130,114 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2003 |
|
|
31,437,581 |
|
|
$ |
315 |
|
|
$ |
366,781 |
|
|
$ |
(808 |
) |
|
$ |
395,374 |
|
|
$ |
(26,128 |
) |
|
$ |
735,534 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
shares issued stock options |
|
|
873,626 |
|
|
|
9 |
|
|
|
25,586 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25,595 |
|
Common
shares issued restricted
stock |
|
|
49,000 |
|
|
|
|
|
|
|
2,855 |
|
|
|
(2,855 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Common
shares issued public
offering |
|
|
6,820,000 |
|
|
|
68 |
|
|
|
310,659 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
310,727 |
|
Common shares repurchase from
KeySpan |
|
|
(10,800,000 |
) |
|
|
(108 |
) |
|
|
(441,471 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(441,579 |
) |
Amortization restricted stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,126 |
|
|
|
|
|
|
|
|
|
|
|
1,126 |
|
Stock
compensation expense stock
options |
|
|
|
|
|
|
|
|
|
|
3,670 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,670 |
|
Tax benefit exercise of
non-qualified stock options |
|
|
|
|
|
|
|
|
|
|
4,922 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,922 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
162,824 |
|
|
|
|
|
|
|
162,824 |
|
Other comprehensive income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative settlements
reclassified to income, net of
tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
44,054 |
|
|
|
44,054 |
|
Unrealized loss change in fair
value of derivatives, net of
tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(63,953 |
) |
|
|
(63,953 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
142,925 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2004 |
|
|
28,380,207 |
|
|
$ |
284 |
|
|
$ |
273,002 |
|
|
$ |
(2,537 |
) |
|
$ |
558,198 |
|
|
$ |
(46,027 |
) |
|
$ |
782,920 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
shares issued stock options |
|
|
510,316 |
|
|
|
5 |
|
|
|
16,285 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,290 |
|
Common
shares issued restricted
stock |
|
|
89,605 |
|
|
|
|
|
|
|
8,204 |
|
|
|
(8,204 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Amortization restricted stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,882 |
|
|
|
|
|
|
|
|
|
|
|
2,882 |
|
Stock
compensation expense stock
options |
|
|
|
|
|
|
|
|
|
|
4,229 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,229 |
|
Tax adjustment to 2004 benefit from
non-qualified stock options |
|
|
|
|
|
|
|
|
|
|
(180 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(180 |
) |
Tax benefit exercise of
non-qualified stock options |
|
|
|
|
|
|
|
|
|
|
3,537 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,537 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
105,169 |
|
|
|
|
|
|
|
105,169 |
|
Other comprehensive income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative settlements reclassified
to income, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
171,342 |
|
|
|
171,342 |
|
Unrealized loss change in fair
value of derivatives, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(393,051 |
) |
|
|
(393,051 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive (loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(116,540 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2005 |
|
|
28,980,128 |
|
|
$ |
289 |
|
|
$ |
305,077 |
|
|
$ |
(7,859 |
) |
|
$ |
663,367 |
|
|
$ |
(267,736 |
) |
|
$ |
693,138 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
F-6
THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
Operating Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
105,169 |
|
|
$ |
162,824 |
|
|
$ |
131,040 |
|
Adjustments to reconcile net income to net cash provided by
operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax expense |
|
|
57,555 |
|
|
|
50,500 |
|
|
|
58,274 |
|
Depreciation, depletion and amortization |
|
|
295,351 |
|
|
|
265,148 |
|
|
|
197,530 |
|
Asset retirement accretion expense |
|
|
5,278 |
|
|
|
4,902 |
|
|
|
3,668 |
|
Stock compensation expense |
|
|
7,111 |
|
|
|
4,796 |
|
|
|
1,014 |
|
Tax benefit (loss) non-qualified stock options |
|
|
(180 |
) |
|
|
4,922 |
|
|
|
1,394 |
|
Unrealized (gain) loss on derivative instruments |
|
|
(694 |
) |
|
|
1,950 |
|
|
|
1,950 |
|
Amortization of premiums paid on derivative contracts |
|
|
|
|
|
|
5,287 |
|
|
|
|
|
Debt extinguishment expense |
|
|
|
|
|
|
211 |
|
|
|
1,626 |
|
Cumulative effect of change in accounting principle |
|
|
|
|
|
|
|
|
|
|
2,772 |
|
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(42,951 |
) |
|
|
(8,387 |
) |
|
|
(4,863 |
) |
Inventories |
|
|
(1,750 |
) |
|
|
95 |
|
|
|
361 |
|
Prepayments and other |
|
|
(11,714 |
) |
|
|
(3,289 |
) |
|
|
(3,622 |
) |
Other assets |
|
|
(43 |
) |
|
|
(6,218 |
) |
|
|
(8,449 |
) |
Accounts payable and accrued expenses |
|
|
42,403 |
|
|
|
39,693 |
|
|
|
(3,055 |
) |
Other non-current liabilities |
|
|
4,974 |
|
|
|
7,276 |
|
|
|
2,329 |
|
ARO liability for assets abandoned |
|
|
|
|
|
|
(2,569 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
460,509 |
|
|
|
527,141 |
|
|
|
381,969 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Investment in property and equipment |
|
|
(728,882 |
) |
|
|
(523,205 |
) |
|
|
(452,959 |
) |
Dispositions and other |
|
|
1,879 |
|
|
|
13,283 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(727,003 |
) |
|
|
(509,922 |
) |
|
|
(452,959 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from long-term borrowings |
|
|
831,000 |
|
|
|
420,000 |
|
|
|
414,000 |
|
Repayments of long-term borrowings |
|
|
(589,000 |
) |
|
|
(367,000 |
) |
|
|
(364,000 |
) |
Debt issuance costs |
|
|
(2,394 |
) |
|
|
(1,555 |
) |
|
|
(4,695 |
) |
Proceeds from issuance of common stock from exercise of
stock options |
|
|
16,290 |
|
|
|
25,596 |
|
|
|
10,223 |
|
Proceeds from issuance of common stock |
|
|
|
|
|
|
310,727 |
|
|
|
79,200 |
|
Repurchase of common stock |
|
|
|
|
|
|
(388,979 |
) |
|
|
(79,200 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash (used in) provided by financing activities |
|
|
255,896 |
|
|
|
(1,211 |
) |
|
|
55,528 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in cash and cash equivalents |
|
|
(10,598 |
) |
|
|
16,008 |
|
|
|
(15,462 |
) |
Cash and cash equivalents, beginning of year |
|
|
18,577 |
|
|
|
2,569 |
|
|
|
18,031 |
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of year |
|
$ |
7,979 |
|
|
$ |
18,577 |
|
|
$ |
2,569 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Information: |
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash transactions: |
|
|
|
|
|
|
|
|
|
|
|
|
Investments in property and equipment accrued, not paid |
|
$ |
(15,785 |
) |
|
$ |
4,705 |
|
|
$ |
(8,863 |
) |
Divesture and exchange of Appalachian Basin assets |
|
|
|
|
|
|
60,000 |
|
|
|
|
|
Deferred tax benefit exchange of Appalachian Basin assets |
|
|
|
|
|
|
7,400 |
|
|
|
|
|
Cash paid during period for: |
|
|
|
|
|
|
|
|
|
|
|
|
Interest |
|
$ |
23,858 |
|
|
$ |
16,385 |
|
|
$ |
18,403 |
|
Federal and state income taxes |
|
|
19,297 |
|
|
|
41,854 |
|
|
|
14,800 |
|
The accompanying notes are an integral part of these consolidated financial statements.
F-7
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 Summary of Organization and Significant Accounting Policies (Reserve quantities, wells,
acreage and working interests included below are unaudited.)
Our Business
We are an independent natural gas and oil producer concentrating on growing reserves and production
through the exploration, development, exploitation and acquisition of natural gas and oil reserves
in North America. We were founded in December 1985 as a Delaware corporation and began exploring
for natural gas and oil on behalf of KeySpan Corporation, our then parent company. KeySpan is a
diversified energy provider whose principal natural gas distribution and electric generation
operations are located in the Northeastern United States. In September 1996, we completed our
initial public offering and sold approximately 31% of our shares to the public. Through three
separate transactions, the first in February 2003 and last in November 2004, KeySpan completely
divested its investment in the common stock of our company. See Note 3 Stockholders Equity -
KeySpan Exchange and Offering.
At December 31, 2005, we had operations in five producing regions within the United States: South
Texas; the Arkoma Basin of Arkansas and Oklahoma; East Texas; the Uinta and DJ Basins in the Rocky
Mountains; and the Gulf of Mexico. In November 2005, we announced our intent to explore the sale
of all our Gulf of Mexico assets and to shift our operating focus onshore. See Note 11
Subsequent Events Pending Sale of Texas Gulf of Mexico Assets.
Our total net proved reserves as of December 31, 2005 were 861 billion cubic feet equivalent or
Bcfe, with onshore reserves totaling 616 Bcfe. Our reserves are fully engineered on an annual
basis by independent petroleum engineers. Approximately 64% of our proved reserves at December 31,
2005, were classified as proved developed. Our daily production during 2005 averaged 313 million
cubic feet of natural gas equivalent or MMcfe.
Principles of Consolidation
Our consolidated financial statements for the periods ended December 31, 2005 and 2004 include the
accounts of Houston Exploration and the accounts of our wholly-owned subsidiaries. All significant
inter-company balances and transactions have been eliminated.
Our consolidated financial statements for the period ended December 31, 2003, include our accounts
and the accounts of our 100% owned subsidiary, Seneca-Upshur Petroleum, Inc. until June 2, 2004,
when we conveyed all of the shares of Seneca-Upshur to KeySpan in connection with an asset exchange
transaction. At that time, Seneca-Upshur was our only subsidiary. Seneca-Upshur is a natural gas
exploration and production company located in West Virginia. All significant inter-company
balances and transactions have been eliminated.
Use of Estimates
The preparation of the consolidated financial statements in conformity with accounting principals
generally accepted in the United States of America requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent
assets and liabilities at the dates of the financial statements and the reported amounts of
revenues and expenses during the reporting periods. Our most significant financial estimates are
based on remaining proved natural gas and oil reserves. Estimates of proved reserves are key
components of our depletion rate for natural gas and oil properties, our unevaluated properties and
our full cost ceiling test limitation. In addition, estimates are used in computing taxes,
preparing accruals of operating costs and production revenues, asset retirement obligations, fair
value and effectiveness of derivative instruments and fair value of stock options and the related
compensation expense. See Note 12 Supplemental Information on Natural Gas and Oil Exploration,
Development and Production Activities (Unaudited) for more information relating to estimates of
proved reserves. Because there are numerous uncertainties inherent in the estimation process,
actual results could differ materially from these estimates.
Reclassifications
Certain reclassifications have been made to prior year amounts to conform to the current year
presentation.
Business Segment Information
The Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards
(SFAS) 131, Disclosures about Segments of an Enterprise and Related Information establishes
standards for reporting information
F-8
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
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. Separate 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 for us as each of our operating areas has similar economic
characteristics and each meets the criteria for aggregation as defined in SFAS 131. All of our
operations involve the exploration, development and production of natural gas and oil and all of
our operations are located in the United States. We have a single, company-wide management team
that administers all properties as a whole rather than as discrete operating segments. We track
only basic operational data by area. We do not maintain 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 freely allocate capital resources on a project-by-project basis across our
entire asset base to maximize profitability without regard to individual areas or segments.
Revenue Recognition and Gas Imbalances
We use the entitlements method of accounting for the recognition of natural gas and oil revenues.
Under this method of accounting, income is recorded based on our net revenue interest in production
or nominated deliveries. We incur production gas volume imbalances in the ordinary course of
business. Net deliveries in excess of entitled amounts are recorded as liabilities, while net under
deliveries are reflected as assets. Imbalances are reduced either by subsequent recoupment of
over-and-under deliveries or by cash settlement, as required by applicable contracts. Production
imbalances are marked-to-market at the end of each month at the lowest of (i) the price in effect
at the time of production; (ii) the current market price; or (iii) the contract price, if a
contract is in hand.
At December 31, 2005, we had production imbalances representing assets of $4.9 million and
liabilities of $7.2 million. The primary sources of our production imbalances relate to Eugene
Island 331, acquired in October 2003 from Transworld Exploration and Production Inc., and to
various Arkoma wells. At December 31, 2004, we had production imbalances representing assets of
$3.3 million and liabilities of $4.0 million. At December 31, 2004, the primary sources of our
production imbalances related to Gulf of Mexico properties acquired in October 2004 from Orca
Energy, L.P. and in October 2003 from Transworld Exploration and Production Inc. See Note 10
Acquisitions and Dispositions. Production imbalances are included in the line items other
non-current assets and other non-current liabilities on the balance sheet.
F-9
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
Net Income Per Share
Basic net income per share is calculated by dividing net income by the weighted average number of
shares of common stock outstanding during the period. Diluted net income per share assumes the
conversion of all potentially dilutive securities and is calculated by dividing net income by the
sum of the weighted average number of shares of common stock outstanding plus all potentially
dilutive securities. Diluted net loss per share is computed using the weighted average number of
common shares and excludes potentially dilutive common shares outstanding, as their effect is
antidilutive. For us, potentially dilutive common shares consist primarily of employee stock
options and restricted common stock.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
|
(in thousand, except per share data) |
|
Numerator: |
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle |
|
$ |
105,169 |
|
|
$ |
162,824 |
|
|
$ |
133,812 |
|
Cumulative effect of change in accounting principle |
|
|
|
|
|
|
|
|
|
|
(2,772 |
) |
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
105,169 |
|
|
$ |
162,824 |
|
|
$ |
131,040 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator: |
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding |
|
|
28,707 |
|
|
|
29,616 |
|
|
|
31,097 |
|
Add dilutive securities: Stock options and restricted stock |
|
|
330 |
|
|
|
316 |
|
|
|
116 |
|
|
|
|
|
|
|
|
|
|
|
Total weighted average shares outstanding and dilutive securities |
|
|
29,037 |
|
|
|
29,932 |
|
|
|
31,213 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
per share basic: |
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle |
|
$ |
3.66 |
|
|
$ |
5.50 |
|
|
$ |
4.30 |
|
Cumulative effect of change in accounting principle |
|
|
|
|
|
|
|
|
|
|
(0.09 |
) |
|
|
|
|
|
|
|
|
|
|
Net income
per share basic |
|
$ |
3.66 |
|
|
$ |
5.50 |
|
|
$ |
4.21 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
per share diluted: |
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle |
|
$ |
3.62 |
|
|
$ |
5.44 |
|
|
$ |
4.29 |
|
Cumulative effect of change in accounting principle |
|
|
|
|
|
|
|
|
|
|
(0.09 |
) |
|
|
|
|
|
|
|
|
|
|
|
Net income
per share diluted |
|
$ |
3.62 |
|
|
$ |
5.44 |
|
|
$ |
4.20 |
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31, 2005, 2004 and 2003, the calculation of shares outstanding for
diluted net income per share does not include the effect of outstanding stock options to purchase
459,215, 755,922, and 1,865,313 shares respectively, because the exercise price of these shares was
greater than the average market price for the year, which would have an antidulitive effect on net
income per share.
Comprehensive Income
Comprehensive income includes net income and certain items recorded directly to stockholders
equity and classified as other comprehensive income. The table below summarizes comprehensive
income and provides the components of the change in accumulated other comprehensive income for the
twelve-month periods ended December 31, 2005, 2004 and 2003, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
|
(in thousands) |
|
Net income |
|
$ |
105,169 |
|
|
$ |
162,824 |
|
|
$ |
131,040 |
|
Other comprehensive income (loss) |
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments settled and reclassified, net of tax |
|
|
171,342 |
|
|
|
44,054 |
|
|
|
43,165 |
|
Change in unrealized (loss) fair value of open contracts, net of tax |
|
|
(393,051 |
) |
|
|
(63,953 |
) |
|
|
(44,091 |
) |
|
|
|
|
|
|
|
|
|
|
Total other comprehensive (loss) |
|
|
(221,709 |
) |
|
|
(19,899 |
) |
|
|
(926 |
) |
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss) |
|
$ |
(116,540 |
) |
|
$ |
142,925 |
|
|
$ |
130,114 |
|
|
|
|
|
|
|
|
|
|
|
F-10
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
Natural Gas and Oil Properties
Full Cost Accounting. We use the full cost method to account for our natural gas and oil
properties. Under full cost accounting, all costs incurred in the acquisition, exploration and
development of natural gas and oil reserves are capitalized into a full cost pool. Capitalized
costs include costs of all unproved properties, internal costs directly related to our natural gas
and oil activities and capitalized interest. We amortize these costs using a unit-of-production
method. We compute the provision for depreciation, depletion and amortization quarterly by
multiplying production for the quarter by a depletion rate. The depletion rate is determined by
dividing our total unamortized cost base by net equivalent proved reserves at the beginning of the
quarter. Our total unamortized cost base is the sum of our:
|
§ |
|
full cost pool (including assets associated with retirement obligations); plus, |
|
|
§ |
|
estimates for future development costs (excluding asset retirement obligations); less, |
|
|
§ |
|
unevaluated properties and their related costs; less, |
|
|
§ |
|
estimates for salvage. |
Costs associated with unevaluated properties are excluded from the amortization base until we have
made a determination as to the existence of proved reserves. We review our unevaluated properties
at the end of each quarter to determine whether the costs incurred should be reclassified to the
full cost pool and thereby subject to amortization. Sales of natural gas and oil properties are
accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the
adjustment would significantly alter the relationship between capitalized costs and proved
reserves.
Under full cost accounting rules, total capitalized costs are limited to a ceiling equal to the
present value of future net revenues, discounted at 10% per annum, plus the lower of cost or fair
value of unproved properties less income tax effects (the ceiling limitation). We perform a
quarterly ceiling test to evaluate whether the net book value of our full cost pool exceeds the
ceiling limitation. If capitalized costs (net of accumulated depreciation, depletion and
amortization) less related deferred taxes are greater than the discounted future net revenues or
ceiling limitation, a writedown or impairment of the full cost pool is required. A writedown of the
carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts
stockholders equity in the period of occurrence and typically results in lower depreciation,
depletion and amortization expense in future periods. Once incurred, a writedown is not reversible
at a later date.
The ceiling test is calculated using natural gas and oil prices in effect as of the balance sheet
date and adjusted for basis or location differential, held constant over the life of the
reserves. We use derivative financial instruments that qualify for cash flow hedge accounting under
SFAS 133,Accounting for Derivative Instruments and Hedging Activities, to hedge against the
volatility of natural gas prices, and in accordance with SEC guidelines, we include estimated
future cash flows from our hedging program in our ceiling test calculation. In addition,
subsequent to the adoption of SFAS 143, Accounting for Asset Retirement Obligations, the future
cash outflows associated with settling asset retirement obligations are excluded from the
computation of the discounted present value of future net revenues for the purposes of the ceiling
test calculation.
In calculating our ceiling test at December 31, 2005, 2004 and 2003, we estimated, using wellhead
prices of $8.21 per Mcfe, $5.75 per Mcfe and $5.74 per Mcfe, respectively, that we had a full cost
ceiling cushion at each of the respective balance sheet dates, whereby the carrying value of our
full cost pool was less that the ceiling limitation by $329.9 million (after tax) for 2005 and
$399.3 million (after tax) for 2004 and $440.7 million (after tax) for 2003. No writedown was
required.
Unevaluated Properties. The costs associated with unevaluated properties and properties under
development are not initially included in the amortization base and relate to unproved leasehold
acreage, wells and production facilities in progress and wells pending determination, together with
interest costs capitalized for these projects. Unevaluated leasehold costs are transferred to the
amortization base with the costs of drilling the related well once a determination has been made or
upon expiration of a lease. Costs of seismic data are allocated to various unproved leaseholds and
transferred to the amortization base with the associated leasehold costs on a specific project
basis. Costs associated with wells in progress and wells pending determination are transferred to
the amortization base once a determination is made whether or not proved reserves can be assigned
to the property. Costs of dry holes are transferred to the amortization base immediately upon
determination that the well is unsuccessful. All items classified as unevaluated property are
assessed on a quarterly basis for possible impairment or reduction in value. Of the $107.1 million
of unevaluated property costs at December 31, 2005 that have been excluded from the amortization
base, $37.9 million were incurred during 2005, $18.3
F-11
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
million were incurred in 2004, $30.5 million were incurred in 2003 and $20.4 million were incurred
prior to 2002. Of the $122.7 million of unevaluated property costs at December 31, 2004 that have
been excluded from the amortization base, $41.1 million were incurred during 2004, $48.2 million
were incurred in 2003, $16.5 million were incurred in 2002 and $16.9 million were incurred prior to
2001. We estimate these costs will be evaluated within a four-year period.
Asset Retirement Obligations
For us, asset retirement obligations (ARO) represent the future abandonment costs of tangible
assets such as platforms, wells, service assets, pipelines, and other facilities. SFAS 143,
Accounting for Asset Retirement Obligations, requires that the fair value of a liability for an
assets retirement obligation be recorded in the period in which it is incurred if a reasonable
estimate of fair value can be made, and that the corresponding cost is capitalized as part of the
carrying amount of the related long-lived asset. The liability is accreted to its then present
value each period, and the capitalized cost is depreciated over the useful life of the related
asset. If the liability is settled for an amount other than the recorded amount, an adjustment is
made to the full cost pool, with no gain or loss recognized, unless the adjustment would
significantly alter the relationship between capitalized costs and proved reserves. We carry ARO
assets on the balance sheet as part of our full cost pool, and include these ARO assets in our
amortization base for the purposes of calculating depreciation, depletion and amortization expense.
For the purposes of calculating the ceiling test, the future cash outflows associated with
settling the ARO liability are excluded from the computation of the discounted present value of
estimated future net revenues.
The following table describes changes in our asset retirement liability during each of the years
ended December 31, 2005 and 2004. The ARO liability in the table below includes amounts classified
as both current and long-term at December 31st.
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
|
(in thousands) |
|
ARO liability at January 1, |
|
$ |
91,746 |
|
|
$ |
92,357 |
|
Accretion expense |
|
|
5,278 |
|
|
|
4,902 |
|
Liabilities incurred from drilling |
|
|
7,520 |
|
|
|
4,487 |
|
Liabilities
incurred assets acquired |
|
|
5,783 |
|
|
|
19,638 |
|
Liabilities settled assets sold |
|
|
(32 |
) |
|
|
(12,714 |
) |
Liabilities settled assets abandoned |
|
|
(971 |
) |
|
|
(4,915 |
) |
Changes in estimates |
|
|
10,347 |
|
|
|
(12,009 |
) |
|
|
|
|
|
|
|
ARO liability at December 31, |
|
$ |
119,671 |
|
|
$ |
91,746 |
|
|
|
|
|
|
|
|
Other Property and Equipment
Other property and equipment includes the costs of various gathering facilities that are
depreciated using the unit-of-production basis utilizing estimated proved reserves attributable to
the facilities. Also included in other property and equipment are costs of office furniture,
fixtures and computer equipment and other office equipment which are recorded at cost and
depreciated using the straight-line method over estimated useful lives ranging between two to five
years.
Cash and Cash Equivalents
We consider all highly liquid short-term investments with original maturities of three months or
less to be cash and cash equivalents.
Income Taxes
We determine deferred taxes based on the estimated future tax effect of differences between the
financial statement and tax basis of assets and liabilities given the provisions of enacted tax
laws as of the balance sheet dates. These differences relate primarily to
|
§ |
|
intangible drilling and development costs associated with natural gas and oil
properties, which are capitalized and amortized for financial reporting purposes and
expensed as incurred for tax reporting purposes; and, |
|
|
§ |
|
provisions for depreciation and amortization for financial reporting purposes
that differ from those used for income tax reporting purposes. |
F-12
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
Inventories
Inventories consist primarily of tubular goods used in our operations and are stated at the lower
of the specific cost of each inventory item or market value.
General and Administrative Costs and Expenses
Under the full cost method of accounting, a portion of our general and administrative expenses that
are directly identified with our acquisition, exploration and development activities are
capitalized as part of our full cost pool. These capitalized costs include salaries, employee
benefits, costs of consulting services and other specifically identifiable costs and do not include
costs related to production operations, general corporate overhead or similar activities. We
capitalized general and administrative costs directly related to our acquisition, exploration and
development activities, during 2005, 2004 and 2003 of $16.9 million, $14.8 million and $12.9
million, respectively.
We receive reimbursement for administrative and overhead expenses incurred on behalf of other
working interest owners on properties we operate. These reimbursements totaling $2.1 million, $2.2
million and $1.6 million for the years ended December 31, 2005, 2004 and 2003, respectively, were
allocated as reductions to general and administrative expenses incurred. Generally, we do not
receive any excess of reimbursements or fees over the costs incurred; however, if we did, we would
credit the excess to the full cost pool to be recognized through lower cost amortization as
production occurs.
Capitalization of Interest
We capitalize interest related to our unevaluated natural gas and oil properties. For the years
ended December 31, 2005, 2004 and 2003, we capitalized interest costs of $8.8 million, $8.4 million
and $7.3 million, respectively.
Financial Instruments
The estimated fair value of financial instruments is the amount at which the instrument could be
exchanged currently between willing parties. On the balance sheet, we report cash and cash
equivalents, accounts receivable and accounts payable at cost or carrying value, which approximates
fair value due to the short maturity of these instruments. See Note 2 Long-term Debt and Notes
for fair value of our debt. Our derivative financial instruments are reported on the balance sheet
at fair market value. See Note 7 Derivative Instruments.
Concentration of Credit Risk
Substantially all of our accounts receivable result from natural gas and oil sales or joint
interest billings to third parties in the oil and gas industry. This concentration of customers and
joint interest owners may impact our overall credit risk in that these entities may be similarly
affected by changes in economic and other conditions. Historically, we have not experienced credit
losses on these receivables. Based on the current demand for natural gas and oil, we do not expect
that termination of sales to any of our current purchasers would have a material adverse effect on
our ability to find replacement purchasers and to sell our production at favorable market prices.
Further, our derivative instruments also expose us to credit risk in the event of nonperformance by
counterparties. Generally, these contracts are with major investment grade financial institutions
and other substantive counterparties. We believe that our credit risk related to the natural gas
futures and swap contracts is no greater than the risk associated with the primary contracts and
that the elimination of price risk through our hedging activities reduces volatility in our
reported results of operations, financial position and cash flows from period to period and lowers
our overall business risk; however, as a result of these same hedging activities, we may be exposed
to greater credit risk in the future.
Derivative Instruments and Hedging Activities
Our hedging policy does not permit us to hold derivative instruments for trading purposes. Our
hedging policy prescribes that upon entering into all derivative contracts, all hedge structures
meet the requirements for hedging accounting under SFAS 133 and all hedge transactions are
specifically identified as hedges for federal income tax purposes as defined in Section 1221(b)(2)
of the Internal Revenue Code. Historically, we have hedged between 70% and 80% of our estimated
future production. Our hedging policy allows us the flexibility to implement a wide variety of
hedging strategies,
F-13
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
including swaps, collars and options. We generally execute contracts with significant,
creditworthy financial institutions and, to a lesser extent, other counterparties. Although our
hedging program is intended to protect a portion of our cash flows from downward price movements,
certain hedging strategies, specifically the use of swaps and collars, may also limit our ability
to realize the full benefit of future price increases, as in recent years. In addition, because
our derivative instruments are typically indexed to New York Mercantile Exchange (NYMEX) prices,
as opposed to the index price where the gas is actually sold, our hedging strategy will not fully
protect our cash flows when, as in recent quarters, the price differential increases between the
NYMEX price and index price for the point of sale.
Generally, our derivative instruments qualify for hedge accounting. Consequently, we carry the
fair market value of our derivative instruments on the balance sheet as either an asset or
liability and defer unrealized gains or losses in accumulated other comprehensive income. Gains and
losses are reclassified from accumulated other comprehensive income to the income statement as a
component of natural gas and oil revenues in the period the hedged production occurs. If any
ineffectiveness occurs, amounts are recorded directly to the income statement and would be included
as a component of the line item natural gas and oil revenues. For us, ineffectiveness is
primarily a result of changes at the end of the current period in the price differentials between
the index price of the derivative contract, which uses a NYMEX price, and the index price for the
point of sale for the cash flow that is being hedged, the majority of which is the Houston Ship
Channel index. For the years ended December 31, 2005, 2004 and 2003, we recorded losses due to the
measured ineffectiveness of open contracts of $46.0 million ($29.7 million net of tax), $1.9
million ($1.3 million net of tax) and $1.9 million ($1.3 million net of tax), respectively.
If our hedge contracts cease to qualify for hedge accounting as a result of ineffectiveness, we
recognize the mark-to-market change in the fair value of the open contracts in income. During the
fourth quarter of 2004, our hedged production allocated to the Houston Ship Channel index failed to
qualify for hedging accounting due to a loss of correlation which the NYMEX price caused primarily
by the impact of Hurricanes Katrina and Rita. Accordingly, we recognized a gain of $26.1 million
($16.9 million net of tax). At December 31, 2005, our open derivative contracts extended through
each of the twelve months of 2006, 2007 and 2008. In addition, during the fourth quarter of 2005
as a result of a production shortfall caused by hurricane related curtailments, we deferred a loss
of $20.6 million in accumulation other comprehensive income, which we expect to realize when the
related gas is produced.
Based on market prices at December 31, 2005, we recorded an unrealized loss in accumulated other
comprehensive income of $267.7 million, net of tax, representing the fair value of our open
derivative contracts. Any loss will be realized in future earnings at the time of the related
sales of natural gas production applicable to specific hedges. If prices in effect at December 31,
2005 were to remain unchanged, over the next 12-month period, we would expect to reclassify from
accumulated other comprehensive income to earnings a loss of $198.9 million, net of tax, relating
to our open derivative contracts. However, these amounts could vary materially as a result of
changes in market conditions.
We enter into a substantial portion of our hedge contracts with counterparties who are participant
banks in our revolving bank credit facility. Under our arrangements with these banks, we generally
have no margin obligation so long as the counterparty remains in our bank group or is otherwise
secured at an equal rate with our bank group. As to other counterparties, with one exception, we
have no margin obligation so long as we satisfy certain credit rating thresholds with prescribed
rating agencies. In one instance we have a margin exposure threshold, above which we must provide
the counterparty margin to secure our hedge obligations. At December 31, 2005, we did not have any
letters of credit issued to secure performance for our open derivative contracts.
Accounting for Stock Options
On January 1, 2003, we adopted the fair value expense recognition provisions of SFAS 123,
Accounting for Stock-Based Compensation, as amended by SFAS 148, Accounting for StockBased
Compensation Transition and Disclosure using the prospective method as defined by the SFAS
148. As a result, we recorded as compensation expense the fair value of all stock options issued
subsequent to January 1, 2003. No expense for stock options has been recorded for grants made in
years prior to January 1, 2003. Prior to 2003, we accounted for stock-based compensation using the
intrinsic value method prescribed in Accounting Principles Board (APB) Opinion 25, Accounting
for Stock Issued to Employees, and related interpretations. Accordingly, compensation cost for
stock options was measured as the excess, if any, of the fair value of common stock at the date of
the grant over the amount the employee must pay to acquire the common stock. If
F-14
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
the exercise price of a stock option was equal to the fair market value at the time of grant, no
compensation expense was incurred.
If we had accounted for all stock options using the fair value method as recommended in SFAS 123,
stock compensation expense would have had the following pro forma effect on our net income and
earnings per share for the years ended December 31, 2005, 2004 and 2003:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
|
(in thousands, except per share data) |
|
Net income
as reported |
|
$ |
105,169 |
|
|
$ |
162,824 |
|
|
$ |
131,040 |
|
Add: Stock-based compensation expense included in
net income, net of tax |
|
|
3,292 |
|
|
|
2,581 |
|
|
|
551 |
|
Less: Stock-based compensation expense determined
using fair value method, net of tax |
|
|
4,679 |
|
|
|
4,694 |
|
|
|
4,427 |
|
|
|
|
|
|
|
|
|
|
|
Net income pro forma |
|
$ |
103,782 |
|
|
$ |
160,711 |
|
|
$ |
127,164 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
per share basic as reported |
|
$ |
3.66 |
|
|
$ |
5.50 |
|
|
$ |
4.21 |
|
Net income
per share diluted as reported |
|
|
3.62 |
|
|
|
5.44 |
|
|
|
4.20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
per share basic pro forma |
|
$ |
3.62 |
|
|
$ |
5.43 |
|
|
$ |
4.09 |
|
Net income
per share diluted pro forma |
|
|
3.57 |
|
|
|
5.37 |
|
|
|
4.07 |
|
The effects of applying SFAS 123 and the calculation of stock compensation expense in this pro
forma disclosure may not be representative of future amounts.
The fair value of each option grant is estimated on the date of grant using the Black-Scholes
option-pricing model with the following weighted average assumptions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
2005 |
|
2004 |
|
2003 |
Risk-free interest rate |
|
|
4.1 |
% |
|
|
3.7 |
% |
|
|
4.0 |
% |
Expected life in years |
|
|
5 |
|
|
|
5 |
|
|
|
5 |
|
Expected stock volatility |
|
|
42.7 |
% |
|
|
37.2 |
% |
|
|
42.7 |
% |
Expected dividends |
|
|
0.0 |
% |
|
|
0.0 |
% |
|
|
0.0 |
% |
The Black-Scholes option pricing model requires the input of certain subjective assumptions,
including the expected stock price volatility and expected life of the option. For the risk-free
interest rate, we utilize daily rates for either five-year or three-year United States treasury
bills with constant maturity that correspond to the options vesting period. The expected life is
based on historical exercise activity over the previous nine-year period. The expected volatility
is based on historical volatility and measured using the average closing price of our stock over a
60-month period. We believe historical volatility is the most accurate measure of future
volatility of our common stock. The weighted average fair value of options at their grant date
during 2005, 2004 and 2003 were $16.62, $21.36 and $14.61, respectively.
New Accounting Pronouncements
On December 16, 2004, the FASB issued Statement 123 (revised 2004), Share-Based Payment (SFAS
123(R)), which requires the measurement and recognition of compensation expense for all
stock-based compensation payments and the current accounting under SFAS 123, Accounting for
Stock-Based Compensation, and supersedes Accounting Principles Board (APB) Opinion No. 25,
Accounting for Stock Issued to Employees. For us, SFAS 123(R) is effective for our first fiscal
year beginning after June 15, 2005, or January 1, 2006.
On January 1, 2003, we adopted the fair value expense recognition provisions of SFAS 123 as amended
by SFAS 148, Accounting for Stock-Based Compensation Transition and Disclosure using the
prospective method as defined by the SFAS 148. As a result, we have recognized compensation
expense for all stock options granted subsequent to January 1, 2003, with no expense recognized for
grants made prior to 2003. With the adoption of SFAS 123(R), we will recognize compensation
expense over the remaining service period for the unvested portion of all options granted during
2001 and 2002. All options granted prior to 2001 are fully vested. We adopted SFAS 123(R) on
January 1, 2006, using the
F-15
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
modified version of the prospective application. We plan to continue using the Black-Scholes
option pricing model to estimate the fair value of our options on the date of grant. We do not
believe the adoption of SFAS 123(R) will have a material impact on our financial statements.
In March 2005, the SEC released Staff Accounting Bulletin (SAB) 107 providing additional guidance
in applying the provisions of SFAS 123(R), Share-Based Payment. SAB 107 should be applied when
adopting SFAS 123(R) and addresses a wide range of issues, focusing on valuation methodologies and
the selection of assumptions. In addition, SAB 107 addresses the interaction of SFAS 123(R) with
existing SEC guidance.
NOTE 2 Long-Term Debt and Notes
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
|
(in thousands) |
|
Senior Debt: |
|
|
|
|
|
|
|
|
Revolving bank credit facility, due November 30, 2010 |
|
$ |
422,000 |
|
|
$ |
180,000 |
|
Subordinated Debt: |
|
|
|
|
|
|
|
|
7% senior subordinated notes, due June 15, 2013 |
|
|
175,000 |
|
|
|
175,000 |
|
|
|
|
|
|
|
|
Total long-term debt and notes |
|
$ |
597,000 |
|
|
$ |
355,000 |
|
|
|
|
|
|
|
|
The carrying amount of borrowings outstanding under the revolving bank credit facility approximates
fair value as the interest rates are tied to current market rates. At December 31, 2005, the
quoted market value of our $175 million of 7% senior subordinated notes was 95.4% of the $175
million carrying value or $167 million. At December 31, 2004, the quoted market value of our $175
million of 7% senior subordinated notes was 101% of the $175 million carrying value or $177
million. At December 31, 2005, principal payments due over the next five-year period and
thereafter are as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
After |
|
|
|
2006 |
|
|
2007 |
|
|
2008 |
|
|
2009 |
|
|
2010 |
|
|
2011 |
|
|
|
(in thousands) |
|
Revolving bank credit facility |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
422,000 |
|
|
$ |
|
|
7% senior Subordinated Notes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
175,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total maturities |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
422,000 |
|
|
$ |
175,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revolving Bank Credit Facility
We maintain a revolving bank credit facility with a syndicate of lenders led by Wachovia Bank,
National Association, as issuing bank and administrative agent, The Bank of Nova Scotia and Bank of
America as co-syndication agents and BNP Paribas and Comerica Bank as co-documentation agents. The
credit facility was amended and restated on November 30, 2005, primarily to increase the size of
the facility. As amended, the facility provides us with a commitment of $750 million, which may be
increased at our request and with prior approval from Wachovia to a maximum of $850 million.
Amounts available for borrowing under the credit facility are limited to a borrowing base, which as
of December 31, 2005 was $600 million. The borrowing base of $600 million is expected to remain in
effect until the next scheduled redetermination on April 1, 2006. However, we expect our borrowing
base to be reduced upon consummation of the pending sale of the Texas portion of our Gulf of Mexico
assets and likely would be further reduced upon any subsequent sale
of the remaining portion of our Gulf of Mexico assets (see Note 11
Subsequent Events Pending Sale of Texas Gulf of Mexico
Assets). Up
to $60 million of the borrowing base is available for the issuance of letters of credit.
Outstanding borrowings under the revolving credit facility are secured by our onshore natural gas
and oil assets as well as certain other assets and rank senior in right of payment to our $175
million of 7% senior subordinated notes. The facility matures on November 30, 2010. At December
31, 2005, we had $422 million in outstanding borrowings under the credit facility and $0.3 million
in outstanding letter of credit obligations.
Interest is payable on borrowings under our revolving bank credit facility, as follows:
|
§ |
|
on base rate loans, at a fluctuating rate, or base rate, equal to the sum of (a)
the greater of the Federal funds rate plus 0.5% or Wachovias prime rate plus (b) a variable
margin between 0.00% and 0.50%, depending on the amount of borrowings outstanding under the
credit facility, or |
F-16
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
|
§ |
|
on fixed rate loans, a fixed rate equal to the sum of (a) a quoted LIBOR rate
divided by one minus the average maximum rate during the interest period set for certain
reserves of member banks of the Federal Reserve System in Dallas, Texas, plus (b) a variable
margin between 1.00% and 1.75%, depending on the amount of borrowings outstanding under the
credit facility. |
Interest is payable on base-rate loans on the last day of each calendar quarter. Interest on
fixed-rate loans is generally payable at maturity or at least every 90 days if the term of the loan
exceeds three months. In addition to interest, we must pay a quarterly commitment fee of between
0.30% and 0.50% per annum on the unused portion of the borrowing base.
Our revolving bank credit facility contains customary negative covenants that place restrictions
and limits on, among other things, the incurrence of debt, guarantees, liens, leases and certain
investments. The credit facility also restricts and limits our ability to pay cash dividends, to
purchase or redeem our stock and to sell or encumber our assets. Financial covenants require us
to, among other things:
|
§ |
|
maintain a ratio of earnings before interest, taxes, depreciation, depletion and
amortization (EBITDA) to cash interest payments of at least 3.00 to 1.00; |
|
|
§ |
|
maintain a ratio of total debt to EBITDA of not more than 3.50 to 1.00; and |
|
|
§ |
|
not hedge more than 85% of our production during any calendar year. |
At December 31, 2005, and December 31, 2004, we were in compliance with all covenants.
Senior Subordinated Notes
On June 10, 2003, we issued $175 million of 7% senior subordinated notes due June 15, 2013. The
notes bear interest at a rate of 7% per annum with interest payable semi-annually on June 15 and
December 15, beginning December 15, 2003. We may redeem the notes at our option, in whole or in
part, at any time on or after June 15, 2008, at a price equal to 100% of the principal amount plus
accrued and unpaid interest, if any, plus a specified premium that decreases yearly from 3.5% in
2008 to 0% in 2011 and thereafter. In addition, at any time prior to June 15, 2006, we may redeem
up to a maximum of 35% of the aggregate principal amount with the net proceeds of one or more
equity offerings at a price equal to 107% of the principal amount, plus accrued and unpaid interest
and liquidated damages, if any. The notes are general unsecured obligations and rank subordinate
in right of payment to all existing and future senior debt, including the revolving bank credit
facility, and will rank senior or equal in right of payment to all existing and future subordinated
indebtedness.
The indenture governing the notes contains covenants that, among other things, restrict or limit:
|
§ |
|
incurrence of additional indebtedness and issuance of preferred stock; |
|
|
§ |
|
repayment of certain other indebtedness; |
|
|
§ |
|
payment of dividends or certain other distributions; |
|
|
§ |
|
investments and repurchases of equity; |
|
|
§ |
|
use of the proceeds of assets sales; |
|
|
§ |
|
transactions with affiliates; |
|
|
§ |
|
creation, incurrence or assumption of liens; |
|
|
§ |
|
merger or consolidation and sales or other dispositions of all or substantially all of our assets; |
|
|
§ |
|
entering into agreements that restrict the ability of our subsidiary to make certain distributions or payments; or |
|
|
§ |
|
guarantees by our subsidiary of certain indebtedness. |
In addition, upon the occurrence of a change of control (as defined in the indenture), we will be
required to offer to purchase the notes at a purchase price equal to 101% of the aggregate
principal amount, plus accrued and unpaid interest and liquidated damages, if any.
F-17
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
NOTE 3 Stockholders Equity
Stock Repurchase Program
In November 2005, our Board of Directors approved a plan for discretionary repurchases from time to
time of up to $200 million in company stock in conjunction with the possible divesture of all of
our Gulf of Mexico assets. These purchases may be in the open market or in privately negotiated
transactions, and will be subject to a number of considerations, including market conditions for
our shares, applicable legal requirements, contractual limitations, available cash, competing
reinvestment opportunities in the acquisition market for oil and gas assets and other factors. No
repurchases were made during 2005.
Stockholder Rights Plan
In August 2004, we adopted a stockholder rights plan designed to assure that our stockholders
receive fair and equal treatment in the event of an unsolicited attempt to takeover our company and
to protect against abusive or coercive takeover tactics that are not in the best interest of our
company or its stockholders. On May 2, 2005, the Board of Directors approved an amendment to the
rights agreement to increase the acquisition threshold of an acquiring party from 10% to 15%. The
rights under the plan expire on August 12, 2014, unless redeemed earlier by our Board of Directors.
The Board of Directors can redeem the rights at a price of $.01 per right at any time before the
rights become exercisable, and thereafter only in limited circumstances.
Increase in Number of Shares Outstanding
In April 2005, our Board of Directors received shareholder approval to increase the number of
shares we are authorized to issue to up to 105,000,000 shares of stock, including up to 100,000,000
shares of common stock and up to 5,000,000 shares of preferred stock.
KeySpans Divesture of Our Common Stock
Through a series of three separate transactions, the first in February 2003 and the last in
November 2004, KeySpan completely divested of its investment in the common stock of our company.
The three transactions are described as follows:
Issuance of 3,000,000 Shares to the Public and Concurrent Repurchase of 3,000,000 Shares from
KeySpan. In connection with our initial public offering in September 1996, we entered into a
registration rights agreement with KeySpan pursuant to which we were obligated, at KeySpans
election, to facilitate KeySpans sale of its shares of our stock by registering the shares under
the Securities Act of 1933 and assisting in KeySpans selling efforts. During February of 2003,
KeySpan notified us of its desire to sell 3,000,000 shares of their Houston Exploration stock. To
accomplish the transaction, we sold 3,000,000 newly issued shares of our stock in a public offering
under our shelf registration statement for net proceeds of $26.40 per share, or an aggregate $79.2
million, and simultaneously bought a like number of KeySpans shares of our stock for the same
price per share. We cancelled the 3,000,000 shares acquired from KeySpan immediately following the
repurchase. KeySpan reimbursed us for all costs and expenses, and the transaction had no impact on
our capitalization. The transaction was evidenced in a stock purchase agreement, dated February
26, 2003. As a result of the transactions, KeySpans interest in our outstanding shares decreased
from 66% to 55%.
KeySpan Exchange and Offering. On June 2, 2004, we completed an asset exchange transaction with
KeySpan pursuant to which we redeemed and cancelled 10,800,000 shares of our common stock owned by
KeySpan in exchange for all the stock of Seneca-Upshur Petroleum, Inc., our wholly-owned
subsidiary, to which we contributed all of our Appalachian Basin assets, valued at $60 million, and
$389 million in cash, for a total exchange value of $449 million. This transaction is referred to
as the KeySpan Exchange. The KeySpan Exchange was intended to qualify as a tax-free exchange
under Section 355(a) of the Internal Revenue Code.
To fund the cash portion of the exchange, on June 2, 2004, we sold 6,200,000 shares of our common
stock in a registered public offering at $48.00 per share, (the Offering), and contributed to
Seneca-Upshur substantially all of the net proceeds from the Offering (approximately $282 million),
together with an additional $107 million of proceeds from bank borrowings. We then conveyed to
KeySpan all of the shares of Seneca-Upshur in exchange for 10,800,000 shares of our common stock
owned by KeySpan.
F-18
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
On June 23, 2004, the underwriters of our Offering exercised a portion of their over-allotment
option and we sold an additional 620,000 shares of common stock at $48.00 per share for net
proceeds of $28.6 million. The proceeds from the over-allotment were used to reduce bank
borrowings.
Our redemption and cancellation of the 10,800,000 shares received from KeySpan and our issuance of
6,820,000 new shares resulted in a net 3,980,000 decrease in the outstanding shares of our common
stock, and thereby reduced KeySpans ownership from approximately 54% to 24%. As a result of the
KeySpan Exchange and Offering, our bank borrowings increased by a net $79 million and we incurred
approximately $5.1 million in compensation and other expenses related to special bonuses awarded to
executives and key employees who assisted in structuring and consummating the transactions. As a
result of the reduction in ownership, KeySpan agreed to reduce its representation on our Board of
Directors from five to two directors. Our Chief Executive Officer, William G. Hargett, was elected
Chairman of the Board replacing Robert B. Catell, Chairman and Chief Executive Officer of KeySpan,
who remains on the Board.
KeySpan Secondary Offering. On November 24, 2004, KeySpan completed a secondary public offering of
its remaining 6,580,392 shares of our common stock at $56.25 per share. All shares were offered by
KeySpan under our shelf registration statement filed with the Securities and Exchange Commission on
March 16, 2004. We did not receive any proceeds from the sale of these shares in the offering.
Subsequent to the offering, KeySpan no longer held any common stock of our company.
NOTE 4 Employee Benefit and Stock and Option Plans
401(k) Plan
We maintain a tax-qualified defined contribution plan under Section 401(k) of the Internal Revenue
Code for our employees. All employees are eligible to participate in the plan upon reaching 21
years of age and completing one month of service. Participants may elect to have us contribute on
their behalf up to 12.5% of their total compensation (subject to limitations imposed under the
Internal Revenue Code) on a before tax basis. We make a matching contribution of $1.00 for each
$1.00 of employee deferral, subject to limitations imposed by the 401(k) plan and the Internal
Revenue Code. The amounts contributed under the 401(k) plan are held in a trust and invested at
the direction of each participant among various investment funds. An employees salary deferral
contributions to the 401(k) plan are 100% vested. Our matching contributions vest at the rate of
20% per year of service. Participants are entitled to distribution of their vested account balances
upon termination of employment. We made contributions to the 401(k) plan of $1.4 million, $1.2
million and $1.3 million, respectively, for the years ended December 31, 2005, 2004 and 2003.
Deferred Compensation Plan
We maintain a deferred compensation plan for the benefit of our employees. The plan is a
non-qualified plan and is intended to supplement our 401(k) plan by allowing highly compensated
employees to save on a tax deferred basis a portion of their eligible compensation subject to
limitations imposed by the plan. Under the terms of the plan, employees who have made the maximum
allowable contribution to their 401(k) accounts for any year may elect to defer an additional
portion of their compensation into the deferred compensation plan. We match 100% of each
employees deferral up to an aggregate contribution of 12.5% under both the 401(k) plan and the
deferred compensation plan. During 2005, 2004 and 2003, we made matching contributions totaling
$1.2 million, $0.7 million and $0.7 million, respectively, to the deferred compensation plan.
Employer contributions vest 20% per year and become fully vested after a five-year period. We make
contributions to a grantor trust to fund plan benefits, but the assets of the trust are subject to
the claims of our general creditors. Assets of the grantor trust are invested, at the direction of
the employee, in various investment funds. Income on trust assets is treated as our income.
Participants are entitled to a benefit attributable to their deferrals and the vested portion of
our matching contributions at predetermined future dates or upon termination of their employment.
At December 31, 2005 and 2004, the fair market value of the assets held in the trust was $8.5
million and $6.7 million, respectively. These balances are carried on our balance sheet as a
non-current asset together with a corresponding non-current liability for the same amount and are
located in the line items Other Non-Current Assets and Other Deferred Liabilities. On January
31, 2006, the plan was amended in order to comply with provisions added to the Internal Revenue
Code by the American Jobs Creation Act of 2004.
F-19
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
Supplemental Executive Retirement Plans
Effective January 1, 2006, we adopted a new Supplemental Executive Retirement Plan (SERP) to
provide retirement benefits to certain management level or other highly compensated employees. The
SERP is an unfunded, non-tax qualified defined benefit pension plan. Initial participation in the
SERP is currently limited to all our executive officers. Participants in the SERP will be entitled
to a monthly retirement benefit payable for life. The amount of this monthly retirement benefit is
equal to 2.5% times final average compensation times years of service with the company (not to
exceed 20 years), reduced by an annuity (offset) based on a hypothetical account that is credited
with 6% of the participants annual base salary and bonus paid each year and investment returns as
defined in the Plan. Participants are fully vested in their benefits after five years of plan
participation or age 65, whichever is earlier. If a vested participant retires prior to age 65,
then the monthly retirement benefit as described above (before reduction for the offset) will be
reduced by 5% for each year that retirement precedes age 65. In the event a participant is
terminated for cause before becoming vested in his or her benefits, all benefits under the SERP will
be forfeited. In general, benefits will be paid when the participant retires from the company or
beginning at age 65. However, in the event of a change of control (as defined in the plan), the
benefit will be paid as a lump-sum if a participants employment is terminated by us without cause
or the participant resigns for good reason within two years following a change of control. All
benefits become fully vested upon a change of control whether or not a participants employment is
terminated.
Employee Annual Incentive Compensation Plan
We maintain an Annual Incentive Compensation Plan that provides an annual incentive bonus to all
full-time employees if certain performance goals are met during the year. The plan is administered
by our Chief Executive Officer on behalf of our Board of Directors and the Compensation Committee.
Annual objectives and incentive opportunity levels are established and approved by the Compensation
Committee. Incentive awards are earned based on our actual performance in relation to
pre-established objectives and on an assessment of individual contribution during the year. We
incurred incentive compensation costs under this plan of approximately $5.0 million, $6.2 million
and $4.8 million in 2005, 2004 and 2003.
Retention Bonus Plan
In July 2005, we adopted a retention bonus plan designed to retain key non-executive employees,
primarily involved in the operations of our business. Under the terms of the plan, participants
will receive a bonus equal to one years base salary, with 50% payable in cash and 50% payable in
restricted stock of the company. Participants will earn their bonus over a 36 month period, with
the first payment of cash and stock to be made 18 months after the first anniversary of the plan or
January 26, 2007. The final payment will be made on July 26, 2008. The number of shares of
restricted stock to be issued was determined by dividing 50% of the employees base salary by the
closing price of our shares on July 26, 2005 which was equal to $58.88. At December 31, 2005, we
had 52,501 restricted units outstanding under the plan. For the year ended December 31, 2005, we
incurred costs of $1.3 million in compensation expense under the plan. Benefits under the plan are
forfeited if a participants employment with our company is terminated before the payment date.
Deferred Compensation Plan for Non-Employee Directors
We maintain a deferred compensation plan for non-employee, non-affiliated directors. The plan in a
non-tax qualified plan designed to allow members of our Board of Directors who are not employees to
defer retainer and/or meetings fees on a pre-tax basis, to be credited with interest or deemed
invested in phantom stock rights that are tied to the market price of our common stock on the date
services are performed. The term phantom stock rights refers to units of value that track the
performance of our companys common stock. These units are not convertible to stock and do not
possess any voting rights. Phantom stock rights are exchanged for a cash distribution upon
retirement from our Board of Directors. The plan was amended in 2005 to comply with the American
Jobs Creation Act of 2004. Deferred fees under the plan totaled $0.9 million for each of the years
ended December 31, 2005 and 2004.
Stock and Option Plans
We have four stock option plans (together, our Stock Plans): (i) the 1996 Stock Option Plan
which was adopted at the completion of our initial public offering in September 1996, amended and
approved by the stockholders in 1997; (ii) the 1999 Non-Qualified Stock Option Plan adopted by our
Board of Directors in October 1999; (iii) the 2002 Long-Term Incentive Plan adopted in January
2002, approved by the stockholders in May 2002 and amended by our Board in October
F-20
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
2003; and (iv) the 2004 Long-Term Incentive Plan, approved by the stockholders in June 2004 and
amended and restated in January 2006. All our employees, directors, consultants and advisors are
eligible to participate in our Stock Plans, with the exception of executive officers who are not
eligible to participate in the 1999 plan. Options granted under our Stock Plans expire 10 years
from the grant date and vest in equal annual increments over either a five year or three year
vesting period, with the exception of options granted to directors whose options vest immediately
upon grant. In general, stock options become fully vested upon the occurrence of a change of
control, unless an award agreement provides otherwise. All grants are made at the closing price of
our common stock as reported on the NYSE on the date of grant. The 1996, 2002 and 2004 plans allow
for the grant of both incentive stock options and non-qualified stock options. After the amendment
and restatement of the 2004 plan in January 2006, non-employee directors are no longer eligible to
receive grants of non-qualified stock options.
Common stock issued through the exercise of non-qualified stock options will result in a tax
deduction for us which is equal to the taxable gain recognized by the optionee. Generally, we will
not receive an income tax deduction for incentive stock options. For financial reporting purposes,
the tax effect of this deduction is accounted for as a credit to additional paid-in-capital rather
than as a reduction of income tax expense. The exercise of non-qualified stock options during
2005, 2004 and 2003 resulted in a tax benefit to us of approximately $ 3.5 million, $4.9 million
and $1.4 million, respectively. For 2005, the tax benefit of $3.5 million was not able to be
utilized for the current tax period due to a tax net operating loss for the year ended December 31,
2005.
In addition to stock options, the 2002 plan and 2004 plan allow for the grant of restricted stock.
Restricted stock carries voting and dividend rights; however, the sale or transfer of the shares is
restricted. During 2005, 2004 and 2003, restricted stock was granted and issued to certain
executive officers, non-employee directors and affiliated directors as a component of each
recipients annual compensation. Generally, restricted shares vest and become freely transferable
at the end of the vesting period, which is either five years or three years from the date of grant.
In general, accelerated vesting will occur upon the occurrence of certain events, a change of
control (as defined by the plan), unless an award agreement provides otherwise, and in the case of
non-employee directors, termination as a director by reason of death, disability or retirement.
On January 1, 2003, we adopted the fair value expense recognition provisions of SFAS 123, as
amended by SFAS 148, Accounting for StockBased Compensation Transition and Disclosure using
the Prospective Method as defined by the SFAS 148. As a result, we record as compensation
expense the fair value of all stock options issued subsequent to January 1, 2003. For the years
ended December 31, 2005, 2004 and 2003, we did not incur compensation expense for stock options
granted prior to January 1, 2003.
The table below provides a detail of stock compensation expenses incurred during the years ended
December 31, 2005, 2004 and 2003. For 2005 and 2004, we incurred additional expense of $0.6
million and $1.6 million, respectively related to the accelerated vesting of stock options and $1.0
million and $0.8 million, respectively for the accelerated vesting of restricted stock for
executive officers and members of our Board of Directors that either retired or resigned.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
|
(in thousands) |
|
Options |
|
$ |
4,229 |
|
|
$ |
3,670 |
|
|
$ |
903 |
|
Restricted stock and units(1) |
|
|
2,882 |
|
|
|
1,126 |
|
|
|
111 |
|
|
|
|
|
|
|
|
|
|
|
Stock compensation expense, gross |
|
|
7,111 |
|
|
|
4,796 |
|
|
|
1,014 |
|
Amounts capitalized |
|
|
(2,015 |
) |
|
|
(800 |
) |
|
|
(166 |
) |
|
|
|
|
|
|
|
|
|
|
Stock compensation expense, net of amounts capitalized |
|
$ |
5,096 |
|
|
$ |
3,996 |
|
|
$ |
848 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes $21,000 and $85,000, respectively, during 2004 and 2003 for the
amortization of 10,000 shares of restricted stock granted to our Chief Executive Officer
upon his employment with our company in April 2001. These shares fully vested in April
2004 and were not made pursuant to one of our Plans. |
The following table summarizes all of our Stock Plans as of December 31, 2005. Pursuant to
shareholder approval of the 2004 Plan, all remaining options available for grant under the 2002,
1999 and 1996 Plans were cancelled and 1,500,000 shares were made available for grant under the
2004 Plan.
F-21
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 Plan |
|
2002 Plan |
|
1999 Plan |
|
1996 Plan |
|
Total Plans |
Options and restricted stock authorized |
|
|
1,500,000 |
|
|
|
1,500,000 |
|
|
|
800,000 |
|
|
|
3,033,912 |
|
|
|
6,833,912 |
|
Options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incentive stock grants |
|
|
|
|
|
|
47,675 |
|
|
|
|
|
|
|
909,454 |
|
|
|
957,129 |
|
Non-qualified stock grants |
|
|
646,680 |
|
|
|
1,194,000 |
|
|
|
806,606 |
|
|
|
2,132,758 |
|
|
|
4,780,044 |
|
Forfeitures |
|
|
(33,772 |
) |
|
|
(85,720 |
) |
|
|
(43,665 |
) |
|
|
(26,600 |
) |
|
|
(189,757 |
) |
Cancellations |
|
|
|
|
|
|
322,045 |
|
|
|
37,059 |
|
|
|
18,300 |
|
|
|
377,404 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total options |
|
|
612,908 |
|
|
|
1,478,000 |
|
|
|
800,000 |
|
|
|
3,033,912 |
|
|
|
5,924,820 |
|
Restricted stock and units:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Grants |
|
|
195,423 |
|
|
|
22,000 |
|
|
|
|
|
|
|
|
|
|
|
217,423 |
|
Forfeitures |
|
|
(4,317 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,317 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total restricted stock and units (2) |
|
|
191,106 |
|
|
|
22,000 |
|
|
|
|
|
|
|
|
|
|
|
213,106 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options and restricted stock available for grant |
|
|
695,986 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
695,986 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total exercised and issued |
|
|
163,558 |
|
|
|
540,370 |
|
|
|
547,329 |
|
|
|
2,755,632 |
|
|
|
4,006,889 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Average grant price for restricted stock was $57.47, $58.28 and $36.94,
respectively, during years ended December 31, 2005, 2004 and 2003. |
|
(2) |
|
Includes 52,501 units granted in 2005 pursuant to the July 2005 Retention Bonus
Plan at an average of $58.76 per share. |
The table below summarizes the activity for stock options during the respective years for all
of our stock plans.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
2005 |
|
2004 |
|
2003 |
|
|
Shares |
|
Price(1) |
|
Shares |
|
Price (1) |
|
Shares |
|
Price (1) |
Options outstanding January 1 |
|
|
1,957,598 |
|
|
$ |
35.05 |
|
|
|
2,535,159 |
|
|
$ |
30.23 |
|
|
|
2,421,166 |
|
|
$ |
27.50 |
|
Granted |
|
|
345,230 |
|
|
|
55.37 |
|
|
|
342,950 |
|
|
|
55.98 |
|
|
|
606,725 |
|
|
|
34.86 |
|
Exercised |
|
|
(510,316 |
) |
|
|
31.92 |
|
|
|
(873,626 |
) |
|
|
29.30 |
|
|
|
(461,563 |
) |
|
|
22.15 |
|
Forfeited |
|
|
(95,902 |
) |
|
|
40.14 |
|
|
|
(46,885 |
) |
|
|
34.49 |
|
|
|
(31,169 |
) |
|
|
27.73 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options outstanding December 31 |
|
|
1,696,610 |
|
|
$ |
39.85 |
|
|
|
1,957,598 |
|
|
$ |
35.05 |
|
|
|
2,535,159 |
|
|
$ |
30.23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options exercisable December 31 |
|
|
615,523 |
|
|
$ |
32.83 |
|
|
|
555,546 |
|
|
$ |
29.80 |
|
|
|
838,568 |
|
|
$ |
28.28 |
|
|
Options available for grant
December 31 |
|
|
695,986 |
|
|
|
|
|
|
|
1,152,975 |
|
|
|
|
|
|
|
309,889 |
|
|
|
|
|
|
|
|
(1) |
|
Weighted average price. For all grants, the grant price equal to closing
market price on the NYSE on date of grant. |
The table below sets forth a summary of options granted and outstanding, their remaining
contractual lives, a weighted average exercise price and the number vested and exercisable as of
December 31, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding |
|
|
Options Exercisable |
|
|
Unvested |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares |
|
|
|
|
|
|
Remaining |
|
|
Average |
|
|
Shares |
|
|
Average |
|
|
Shares |
|
Range of |
|
|
Underlying |
|
|
Year |
|
|
Contractual |
|
|
Exercise |
|
|
Underlying |
|
|
Exercise |
|
|
Underlying |
|
Exercise Prices |
|
|
Options |
|
|
Granted |
|
|
Life |
|
|
Price |
|
|
Options |
|
|
Price |
|
|
Options |
|
|
|
$ |
15.50 |
|
|
|
|
|
|
$ |
17.25 |
|
|
|
14,400 |
|
|
|
1996 |
|
|
1 years |
|
$ |
15.60 |
|
|
|
14,400 |
|
|
$ |
15.50 |
|
|
|
|
|
|
|
$ |
13.13 |
|
|
|
|
|
|
$ |
25.00 |
|
|
|
15,900 |
|
|
|
1997 |
|
|
2 years |
|
|
20.73 |
|
|
|
15,900 |
|
|
|
20.73 |
|
|
|
|
|
|
|
$ |
15.75 |
|
|
|
|
|
|
$ |
23.38 |
|
|
|
6,920 |
|
|
|
1998 |
|
|
3 years |
|
|
18.86 |
|
|
|
6,920 |
|
|
|
18.86 |
|
|
|
|
|
|
|
$ |
16.94 |
|
|
|
|
|
|
$ |
21.00 |
|
|
|
27,430 |
|
|
|
1999 |
|
|
4 years |
|
|
19.62 |
|
|
|
27,430 |
|
|
|
19.62 |
|
|
|
|
|
|
|
$ |
18.00 |
|
|
|
|
|
|
$ |
26.19 |
|
|
|
29,500 |
|
|
|
2000 |
|
|
5 years |
|
|
23.72 |
|
|
|
29,500 |
|
|
|
23.72 |
|
|
|
|
|
|
|
$ |
22.50 |
|
|
|
|
|
|
$ |
37.38 |
|
|
|
315,482 |
|
|
|
2001 |
|
|
6 years |
|
|
29.38 |
|
|
|
205,247 |
|
|
|
29.56 |
|
|
|
110,235 |
|
|
|
$ |
27.49 |
|
|
|
|
|
|
$ |
33.75 |
|
|
|
318,760 |
|
|
|
2002 |
|
|
7 years |
|
|
30.15 |
|
|
|
120,800 |
|
|
|
30.14 |
|
|
|
197,960 |
|
|
|
$ |
26.18 |
|
|
|
|
|
|
$ |
37.42 |
|
|
|
339,785 |
|
|
|
2003 |
|
|
8 years |
|
|
34.75 |
|
|
|
96,320 |
|
|
|
35.07 |
|
|
|
243,465 |
|
|
|
$ |
36.56 |
|
|
|
|
|
|
$ |
60.45 |
|
|
|
294,678 |
|
|
|
2004 |
|
|
9 years |
|
|
56.08 |
|
|
|
74,006 |
|
|
|
57.93 |
|
|
|
220,672 |
|
|
|
$ |
46.25 |
|
|
|
|
|
|
$ |
67.08 |
|
|
|
333,755 |
|
|
|
2005 |
|
|
10 years |
|
|
55.37 |
|
|
|
25,000 |
|
|
|
36.55 |
|
|
|
308,755 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,696,610 |
|
|
|
|
|
|
|
|
|
|
$ |
39.85 |
|
|
|
615,523 |
|
|
$ |
32.83 |
|
|
|
1,081,087 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-22
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 5 Income Taxes
The components of the federal income tax provision are:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
|
(in thousands) |
|
Current |
|
$ |
5,335 |
|
|
$ |
46,092 |
|
|
$ |
13,913 |
|
Deferred |
|
|
57,555 |
|
|
|
50,500 |
|
|
|
58,274 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
62,890 |
|
|
$ |
96,592 |
|
|
$ |
72,187 |
|
|
|
|
|
|
|
|
|
|
|
For the year ended December 31, 2005, we had an estimated net operating tax loss of $31.4 million,
including tax deductions of $10 million for certain non-qualified stock options. We plan to carry
back this net operating loss to years 2004 and 2003 for tax refunds. In addition, for 2005, we
generated alternative minimum tax credits of $8.7 million. These tax credits can be carried
forward indefinitely to offset regular income tax. At December 31, 2004 and 2003, we had no net
operating loss carryforwards remaining for federal income tax purposes. Net operating loss
carryforwards may be used in future years to offset taxable income.
The following is a reconciliation of statutory federal income tax expense to our income tax
provision:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
|
(in thousands) |
|
Income before income taxes |
|
$ |
168,059 |
|
|
$ |
259,416 |
|
|
$ |
205,999 |
|
Statutory rate |
|
|
35 |
% |
|
|
35 |
% |
|
|
35 |
% |
Income tax expense computed at statutory rate |
|
|
58,821 |
|
|
|
90,796 |
|
|
|
72,100 |
|
Reconciling items: |
|
|
|
|
|
|
|
|
|
|
|
|
State income taxes and other, net of federal
tax benefit |
|
|
672 |
|
|
|
4,358 |
|
|
|
|
|
Permanent differences |
|
|
40 |
|
|
|
45 |
|
|
|
29 |
|
Other adjustments (1) |
|
|
1,852 |
|
|
|
|
|
|
|
58 |
|
Non-deductible compensation expense |
|
|
1,505 |
|
|
|
1,393 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax provision |
|
$ |
62,890 |
|
|
$ |
96,592 |
|
|
$ |
72,187 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
For 2005, includes an adjustment relating to 2004 estimates for federal and
state taxes. For 2003, comprised of excess deductions for Section 29 tax credits taken
in 2002. |
Deferred Income Taxes
Deferred income taxes primarily represent the net tax effect of temporary differences between the
carrying amounts of assets and liabilities for financial reporting purposes and the amounts used
for income tax purposes. The components of our deferred taxes are detailed in the table below.
For 2005, the change in the balance of our deferred tax liability was comprised of deferred tax
expense of $57.6 million, a tax benefit of $121.5 million due to the change in the fair value of
our open derivative contracts that have been deferred in accumulated other comprehensive income, an
increase in deferred tax assets for stock option deductions of $3.5 million and other adjustments
of $1.1 million.
For 2004, the change in the balance of our deferred tax liability was comprised of deferred tax
expense of $50.5 million, a tax benefit of $11.1 million due to the change in the fair value of our
open derivative contracts that has been deferred in accumulated other comprehensive income and a
reduction of $7.4 million to our deferred tax liabilities related to oil and gas property and
equipment associated with the Appalachian Basin assets divested as part of the KeySpan Exchange in
June 2004.
F-23
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
|
(in thousands) |
|
Deferred tax assets: |
|
|
|
|
|
|
|
|
Derivative instruments |
|
$ |
146,716 |
|
|
$ |
25,222 |
|
Ineffectiveness derivative instruments |
|
|
1,135 |
|
|
|
1,381 |
|
Net operating loss |
|
|
11,101 |
|
|
|
|
|
Alternative minimum tax credit carryforwards |
|
|
8,728 |
|
|
|
|
|
Deferred compensation |
|
|
5,728 |
|
|
|
4,327 |
|
|
|
|
|
|
|
|
Total deferred tax assets |
|
|
173,408 |
|
|
|
30,930 |
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities: |
|
|
|
|
|
|
|
|
Oil and gas property and equipment |
|
|
368,788 |
|
|
|
294,898 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax liability |
|
$ |
195,380 |
|
|
$ |
263,968 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reflected in the accompanying Balance Sheet as: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current deferred income tax asset |
|
$ |
(145,922 |
) |
|
$ |
(24,101 |
) |
Non-current deferred income tax liability |
|
|
341,302 |
|
|
|
288,069 |
|
|
|
|
|
|
|
|
|
|
$ |
195,380 |
|
|
$ |
263,968 |
|
|
|
|
|
|
|
|
NOTE 6 Related Party Transactions
Transactions With Our Executive Officers and Directors
Employment Agreements
We have entered into employment agreements with all of our executive officers. Employment
agreements have an initial term of three years, which is automatically extended each year for an
additional year on the anniversary effective date, unless either party gives notice to the contrary
within 90 days prior to the anniversary of the employment agreement. Executive officers receive
annual salary and bonus payments pursuant to their employment agreements and are eligible to
participate in our stock compensation, deferred compensation and supplemental executive pension
plans.
If we terminate an executive without cause (as defined in the agreement), or if the executive
terminates his employment with us for good reason (as defined in the agreement, which includes
the occurrence of certain events following a change in control), we are obligated to pay the
executive a lump-sum severance payment equal to 2.99 times his then current annual rate of total
compensation, and to continue certain medical and insurance benefits for a specified time period.
The agreements further provide that if any payments made to the executive, whether or not under the
agreement, would result in an excise tax being imposed on the executive under Section 4999 of the
Internal Revenue Code, we will make each of the executives whole on a net after-tax basis.
We may terminate any employment agreement for cause without financial obligation (other than
payment of any accrued obligations). Each executive may terminate his agreement at any time for
any reason upon at least 30 days prior written notice. In the event the executives employment is
terminated by us without cause or upon death or disability, or if the executive terminates his
employment with us for good reason, any unvested shares of restricted stock, unvested options or
similar deferred compensation automatically will vest and any other conditions to such awards shall
be deemed satisfied.
Employment Agreement with Robert T. Ray, Chief Financial Officer
On January 18, 2006, we entered into an employment agreement with Robert T. Ray in connection with
Mr. Rays appointment as Senior Vice President and Chief Financial Officer of our company. The
terms of Mr. Rays employment agreement are consistent with the general terms described above.
Further, under Mr. Rays agreement, he will initially receive a base salary of $315,000 (subject to
review each year by our Compensation Committee) and will be entitled to an annual incentive bonus
equal to 55% of his base salary. Payment of the bonus is based on achievement of certain
performance goals established each year by our Compensation Committee. In addition, Mr. Ray
received a signing bonus in the amount of $85,000, along with 20,000 stock options and 7,500
restricted shares our common stock. Mr. Ray is
F-24
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
eligible to participate in our stock compensation and deferred compensation plans, as well as our
Supplemental Executive Retirement Plan. The agreement provides for an automobile allowance of $700
per month and reimbursement of certain business expenses and requires us to provide certain
disability and life insurance. If we terminate Mr. Ray without
cause, or if he terminates his
employment with us for good reason, we are obligated to pay him a lump sum severance payment,
based on his initial compensation, equal to approximately $1.5 million.
Amendments to Employment Agreements
In February 2005, we entered into amended and restated employment agreements with William G.
Hargett, our President and Chief Executive Officer, Steven L. Mueller, our Executive Vice President
and Chief Operating Officer, John H. Karnes, our then Senior Vice President and Chief Financial
Officer, James F. Westmoreland, our Vice President and Chief Accounting Officer, and Roger B. Rice,
our Senior Vice President-Administration.
By entering into the amended and restated employment agreements and terminating their prior
employment agreements with us, Messrs. Hargett, Mueller, Karnes, Westmoreland and Rice gave up
certain rights, including the right to receive severance for a termination of employment following
a change of control of our company absent the existence of good reason and the right to
guaranteed annual stock option grants and incentive compensation bonuses, which will now be subject
to the discretion of our Compensation and Management Development Committee. In addition to these
rights, Mr. Hargett also gave up the right to receive a transaction bonus upon the occurrence of
certain corporate transactions involving our company, and all of the executives are agreeing to
somewhat broader non-competition provisions under the amended and restated agreements. In
consideration of their entering into the amended and restated agreements and foregoing such rights,
we paid to each of these executives cash and/or restricted stock as follows: for Mr. Hargett, $4.2
million; for Mr. Mueller, $0.4 million in cash and 6,553 shares of restricted stock; for Mr.
Karnes, 12,892 shares of restricted stock; for Mr. Westmoreland, $0.3 million in cash and 5,394
shares of restricted stock; and for Mr. Rice, $0.3 million in cash and 5,266 shares of restricted
stock. The restricted stock vests over a period of five years in accordance with the terms of our
Amended and Restated 2004 Long-Term Incentive Compensation Plan.
Lump-Sum Payments to Executives Under Employment Contracts
On December 8, 2005, we terminated our employment agreement with John H. Karnes, who resigned as
Senior Vice President and Chief Financial Officer and entered into a separation agreement and
general release with Mr. Karnes. The separation agreement provided for full settlement of any
compensation and benefits to which Mr. Karnes would otherwise be entitled under his employment
agreement. Mr. Karnes received a cash lump-sum severance payment of $1.5 million and will continue
certain welfare benefits. In addition, we incurred $1.7 million in stock compensation expense
pursuant to the accelerated vesting of Mr. Karnes restricted stock and stock options.
Pursuant to a management organizational change made within our company in November 2004 that
changed the reporting responsibilities of three executive officers, Charles W. Adcock, Senior Vice
President and General Manager Offshore Division resigned, effective December 14, 2004, and
Timothy R. Lindsey, Senior Vice President of Exploration, and Tracy Price, Senior Vice President
Land, resigned, effective March 1, 2005. Pursuant to their resignations and the termination of
their employment agreements with our company, during the fourth quarter of 2004, we incurred
approximately $5.1 million in general and administrative expense of which $1.3 million, $1.1
million and $1.0 million, respectively, related to lump-sum severance entitlements for Messrs.
Adcock, Lindsey and Price and, $1.7 million related to expense incurred as a result of the
accelerated vesting of all their outstanding stock options and restricted stock.
Transactions Involving Companies with Common Directors
John U. Clarke, a member of our Board of Directors and Chairman of the Audit Committee serves as a
Chairman and Chief Executive Officer of NATCO Group, a publicly traded oil field services and
equipment company. During 2005, 2004, and 2003 we purchased services and supplies from NATCO of
$1.3 million, $0.9 million and $1.1 million, respectively. Mr. Clarke meets all requirements of
the New York Stock Exchange to be considered an independent director of our company.
F-25
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Transactions with KeySpan
To
facilitate the KeySpan Exchange (see Note 3 KeySpan Exchange and Offering), we entered into a
Distribution Agreement with KeySpan that defines each companys rights and obligations with respect
to the exchange transaction. The Distribution Agreement contains, among other provisions,
customary representations and warranties concerning our Appalachian Basin properties, including
title, regulatory compliance and environmental matters, along with limited indemnification
obligations. Pursuant to the Distribution Agreement, the two companies also entered into a Tax
Matters Agreement, which generally provides that each party would be responsible for its own tax
consequences if the KeySpan Exchange fails to qualify as a tax-free transaction. In addition, we
entered into a Transition Services Agreement pursuant to which we provided KeySpan with
transitional services with respect to the Appalachian Basin assets for a fee of $27,000 per month
until March 31, 2005.
NOTE 7 Derivative Instruments
As of December 31, 2005, we had entered into commodity price hedging contracts with respect to
approximately 75% of our forecasted natural gas production for 2006 and less than 10% for 2007 and
2008 as listed in the tables below. The total estimated fair value of our natural gas and oil
derivative instruments at December 31, 2005 was a liability of $417.7 million, of which we have
deferred a net $267.7 million in accumulated other comprehensive income and recognized $46.0
million in earnings as a reduction to natural gas and oil revenues as a result of the estimated
ineffectiveness of our open contracts as of the end of the period. In addition, during the fourth
quarter of 2005, we recognized in income a gain of $26.1 million for hedged production allocated to
the Houston Ship Channel index due to loss of correlation between the NYMEX price and the Houston
Ship Channel index. Further, we deferred a loss in accumulated other comprehensive income of $20.6
million as a result of a production shortfall during the fourth quarter of 2005 due to offshore
production curtailments caused by Hurricanes Katrina and Rita.
From time to time, if the fair value of an open contract or contracts exceeds our available credit
limit with a particular counterparty, we could be required to post a letter of credit to further
guarantee our performance. As of December 31, 2005, we did not have any outstanding letters of
credit issued relating to derivative contracts.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
Fixed Price Swaps |
|
Collars |
|
|
|
|
Daily |
|
NYMEX |
|
Daily |
|
NYMEX |
|
|
|
|
Volume |
|
Contract |
|
Volume |
|
Contract Price |
|
|
Period |
|
(MMBtu) |
|
Price |
|
(MMBtu) |
|
Floor |
|
Ceiling |
|
Fair Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(thousands) |
January December 2006
|
|
|
30,000 |
|
|
$ |
5.893 |
|
|
|
220,000 |
|
|
$ |
5.774 |
|
|
$ |
7.090 |
|
|
$ |
(352,456 |
) |
January December 2007
|
|
|
|
|
|
|
|
|
|
|
30,000 |
|
|
|
5.000 |
|
|
|
6.597 |
|
|
|
(40,255 |
) |
January December 2008
|
|
|
|
|
|
|
|
|
|
|
20,000 |
|
|
|
5.000 |
|
|
|
5.720 |
|
|
|
(24,947 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(417,658 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2004, we had entered into commodity price hedging contracts with respect to our
natural gas production for 2005 through 2008 as listed in the tables below. The total estimated
fair value of our natural gas and oil derivative instruments at December 31, 2004 was a liability
of $75.1 million, of which we have deferred a net $46.0 million in accumulated other comprehensive
income and recognized $1.9 million in earnings as a reduction to natural gas and oil revenues as a
result of the estimated ineffectiveness of our open contracts as of the end of the period.
As of December 31, 2004, we did not have any outstanding letters of credit issued relating to
derivative contracts.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
Fixed Price Swaps |
|
Collars |
|
|
|
|
Daily |
|
NYMEX |
|
Daily |
|
NYMEX |
|
|
|
|
Volume |
|
Contract |
|
Volume |
|
Contract Price |
|
|
Period |
|
(MMBtu) |
|
Price |
|
(MMBtu) |
|
Floor |
|
Ceiling |
|
Fair Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(thousands) |
January December 2005
|
|
|
80,000 |
|
|
$ |
5.304 |
|
|
|
180,000 |
|
|
$ |
4.833 |
|
|
$ |
6.434 |
|
|
$ |
(68,081 |
) |
January December 2006
|
|
|
30,000 |
|
|
|
5.893 |
|
|
|
60,000 |
|
|
|
5.500 |
|
|
|
7.248 |
|
|
|
(3,889 |
) |
January December 2007
|
|
|
|
|
|
|
|
|
|
|
30,000 |
|
|
|
5.000 |
|
|
|
6.597 |
|
|
|
(1,662 |
) |
January December 2008
|
|
|
|
|
|
|
|
|
|
|
20,000 |
|
|
|
5.000 |
|
|
|
5.720 |
|
|
|
(1,517 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(75,149 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-26
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Fair market value is calculated for the respective months using prices derived from NYMEX futures
contract prices existing at December 31st and from market quotes received from
counterparties.
For natural gas, transactions are settled based upon the NYMEX price on the final trading day of
the month (the settlement price). With respect to any particular swap transaction, the
counterparty is required to make a payment to us in the event that the settlement price for any
settlement period is less than the swap price for the transaction, and we are required to make
payment to the counterparty in the event that the settlement price for any settlement period is
greater than the swap price for the transaction. For any particular collar transaction, the
counterparty is required to make a payment to us if the settlement price for any settlement period
is below the floor price for the transaction, and we are required to make payment to the
counterparty if the settlement price for any settlement period is above the ceiling price for the
transaction. We are not required to make or receive any payment in connection with a collar
transaction if the settlement price is between the floor and the ceiling.
NOTE 8 Sales to Major Customers
We sold natural gas and oil production representing 10% or more of our natural gas and oil revenues
for the years ended December 31, 2005, 2004 and 2003 as listed below. In the exploration,
development and production business, production is normally sold to relatively few customers.
However, based on the current demand for natural gas and oil, we believe that the loss of any of
our major purchasers would not have a material adverse effect on our operations. Amounts presented
in the below table that are less than 10% have been included for information and comparison
purposed only.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, |
|
Major Purchaser |
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
|
|
|
ConocoPhillips |
|
|
11.9 |
% |
|
|
11.9 |
% |
|
|
18.4 |
% |
Anadarko Petroleum Corporation |
|
|
10.1 |
% |
|
|
9.08 |
% |
|
|
11.7 |
% |
KinderMorgan |
|
|
2.7 |
% |
|
|
10.1 |
% |
|
|
11.4 |
% |
NOTE 9 Commitments and Contingencies
Legal Proceedings
We are involved from time to time in various claims and lawsuits incidental to our business. In the
opinion of management, the ultimate liability, if any, of these claims and lawsuits will not have a
material adverse effect on our financial position or results of operations.
Severance Tax Refund
During July 2002, we applied for and received from the Railroad Commission of Texas a
high-cost/tight-gas formation designation for a portion of our South Texas production. For
qualifying wells, production is either exempt from tax or taxed at a reduced rate until certain
capital costs are recovered. For the years ended December 31, 2005, 2004 and 2003, we recognized
as other income refunds of prior period severance tax payments of $2.7 million, $1.2 million and
$21.6 million, respectively. At December 31, 2005, and 2004, our current receivables include $0.7
million and $1.3 million, respectively, in gross refunds of which we estimate, approximately 70%,
or $0.5 million and $9.0 million, respectively, relate to our net revenue interest. Beginning
September 1, 2003, all refunds issued by the State of Texas are to be made in the form of a
reduction to or credit against our current severance tax liability rather than in the form of a
cash reimbursement.
Leases
We have entered into non-cancelable operating lease agreements in the ordinary course of our
business activities. These leases include those for our office space at 1100 Louisiana in Houston,
Texas and at 700 17th Street in Denver, Colorado together with various types of office
equipment (primarily copiers and fax machines). The terms of these agreements have various
expiration dates from 2006 through 2010. Rental expense related to these leases was $1.9 million,
$1.6 million and $1.3 million, respectively, for the years ended December 31, 2005, 2004 and 2003.
At December 31, 2005, our total commitment under these non-cancelable operating leases was $6.6
million. Minimum rental commitments under the terms of our operating leases are as follows (in
thousands):
F-27
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
Minimum |
|
Years Ended December 31, |
|
Payments |
|
2006 |
|
$ |
1,796 |
|
2007 |
|
|
1,855 |
|
2008 |
|
|
1,863 |
|
2009 |
|
|
1,083 |
|
2010 |
|
|
2 |
|
Thereafter |
|
|
|
|
|
|
|
|
Total |
|
$ |
6,599 |
|
|
|
|
|
Purchase Obligations
We have committed to acquire additional offshore seismic data under two license agreements for a
total of $10.7 million, of which $7.7 million is payable in January 2006 and $3.0 million is
payable by March 31, 2006.
Letters of Credit
We had $0.3 million and $0.4 million, respectively, in letters of credit outstanding at December
31, 2005 and 2004.
NOTE 10 Acquisitions and Dispositions (Reserve quantities, wells, acreage and working interests
included below are unaudited.)
Acquisition of South Texas Properties
On November 30, 2005, we completed the acquisition of certain interests in natural gas and oil
producing properties and undeveloped acreage in four fields located in South Texas from Kerr-McGee
Oil & Gas Onshore LP and Westport Oil and Gas Company, L.P. The net purchase price of $159.0
million was paid in cash and financed by borrowings under our revolving bank credit facility. The
$163.0 million purchase price was reduced by $4.0 million for various customary closing items,
including revenues received by and expenditures made by the seller related to the properties
acquired for the period between the effective date of the transaction, October 1, 2005, and the
closing date, November 30, 2005.
The properties cover approximately 26,000 net acres, include approximately 300 wells and are
located in the Rincon Field in Starr County, the Tijerina-Canales-Blucher Field in Jim Wells and
Kleberg Counties, the Vaquillas Ranch Field in Webb County, and the San Carlos Field in Hidalgo
County. At December 31, 2005, proved reserves were approximately 62 Bcfe, of which approximately
75% were natural gas. Current production from the four fields is estimated at approximately 10
MMcfe/day, net to the interests acquired. We operate 100% percent of the proved reserves with an
average working interest of 60%.
East Texas Acquisitions
On March 15, 2005, we completed the purchase of certain natural gas and oil producing properties
and associated gathering pipelines and equipment, together with developed and undeveloped acreage,
located in the Rusk County, Texas, from Dale Gas Partners, L.P. The $22.0 million purchase price
was paid in cash and financed by borrowings under our revolving bank credit facility. The
properties purchased cover approximately 5,776 gross acres located in South Oak Hill Field, which
is in close proximity to our existing operations in the Willow Springs Field, and represents
interests in three producing wells and one well in the completion stage. We operate all of the
wells acquired and our working interest is 100%. Based on internal estimates, total proved
reserves associated with the interests acquired were 9.1 Bcfe as of March 15, 2005, the effective
date of the transaction.
On April 5, 2005, we completed the acquisition of a 50% working interest in seven producing wells
together with undeveloped acreage located in the North Blocker Field located in Harrison County,
Texas from Dale Resources East Texas L.L.C. The $9.2 million purchase price was paid in cash and
financed by borrowings under our revolving bank credit facility. The properties purchased cover
approximately 4,679 gross acres and, we operate all seven wells. Based on internal estimates,
total proved reserves associated with the interests acquired were estimated at 7.7 Bcfe, as of
April 1, 2005, the effective date of the transaction. On December 31, 2005, we purchased the
remaining working interests held by Dale in the seven wells and undeveloped acreage acquired in
April 2005 for $7.3 million.
F-28
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Orca Acquisition
On October 29, 2004, we completed the acquisition of certain producing properties from Orca Energy,
L.P. The $113.6 purchase price was paid in cash and financed by borrowings under our revolving bank
credit facility. The transaction was effective August 1, 2004. The Orca properties consist of 10
offshore blocks and two onshore fields. The onshore fields are non-operated and located in central
Mississippi: the Wausau Field, located in Wayne County and the Oakvale Dome Field, located in
Jefferson Davis County. The 10 offshore blocks are a mix of state and federal leases, located in
less than 50 feet of water, and include seven blocks in federal waters and three blocks in state
waters. Total acreage acquired covers 23,777 gross (17,973 net) acres. The properties include 15
platforms, five production caissons and 28 producing wells. Based on internal estimates, total
proved reserves acquired were approximately 60.7 Bcfe as of the closing date, October 29, 2004, of
which 81% were natural gas. Our average working interest in the properties acquired is 68% and we
operate approximately 85% of the proved reserves acquired.
BP Acquisition
On September 30, 2004, we completed the purchase of two producing offshore fields from BP
Exploration & Production Inc. The net purchase price of $30.0 million was paid in cash and financed
by borrowings under our revolving bank credit facility. The $31.5 million purchase price was
reduced by $1.5 million for various customary closing items, including revenues received by and
expenditures made by the seller related to the properties acquired for the period between the
effective date of the transaction, August 1, 2004, and the closing date, September 30, 2004. The
properties acquired are located at Eugene Island 240 and Main Pass 264 and each block has one
producing platform. Based on internal estimates, total proved reserves associated with the
interests acquired were approximately 16.2 Bcfe as of September 30, 2004, of which 85% were natural
gas. Our average working interest is 85% and we operate both blocks.
Disposition and Exchange of Appalachian Basin Assets
In connection with the KeySpan Exchange on June 2, 2004, (see Note 3 KeySpan Exchange and
Offering) we divested all of our Appalachian Basin assets with an agreed upon value of $60 million.
Pursuant to an Asset Contribution Agreement, we contributed to Seneca-Upshur all of the assets
relating solely to our Appalachian Basin assets that were not already owned by Seneca-Upshur, and
Seneca-Upshur assumed all of the liabilities relating to the Appalachian Basin assets for which it
was not already liable. In the KeySpan Exchange, all of the stock of Seneca-Upshur was then
conveyed to KeySpan and effective June 1, 2004, Seneca-Upshur became an indirect wholly-owned
subsidiary of KeySpan.
Our Appalachian property base was located primarily in central West Virginia and included the
Belington, Clarksburg and Seneca Upshur Fields located in Barbour, Randolph, Upshur and Mingo
Counties of West Virginia. Included in the assets exchanged were the assets acquired on December
31, 2003, from EnerVest East Limited Partnership located adjacent to our existing base in the
Crawford and Pennsboro Fields in Lewis, Harrison, Tyler and Ritchie Counties of West Virginia and
the Waynesburg and Yatesboro Fields in Greene and Armstrong Counties of southwestern Pennsylvania.
Based on internal estimates at June 1, 2004, our Appalachian Basin properties had 51.2 Bcfe of
estimated proved reserves, and our average daily production was approximately 8 MMcfe/day, which
represented approximately 3% of our total daily production. We had approximately 207,000 gross
(129,000 net) acres under lease and owned working interests in approximately 1,414 gross (1,035
net) wells, of which we operated approximately 92%. Our average working interest was 73%.
Sale of Onshore South Louisiana Properties
On February 4, 2004, we completed the sale of our onshore South Louisiana producing properties.
The sale was effective November 1, 2003, and the properties represented 12.3 Bcfe proved reserves
as of December 31, 2003, and included interests in 33 gross (9.5 net) producing wells and covered
approximately 6,300 gross (2,300 net) acres. The sale price of $15 million was reduced by $1.9
million for various customary closing items, including revenues received by and expenditures made
by us related to the properties sold for the period between the effective date of the transaction
and the closing date. The net proceeds of $13.1 million from the sale were used to repay
borrowings under our revolving bank credit facility.
EnerVest Acquisition
On December 31, 2003, we completed the purchase of certain producing natural gas and oil properties
and associated gathering pipelines and equipment located in the Appalachian Basin of West Virginia
and Pennsylvania from EnerVest East Limited Partnership. The properties acquired were adjacent to
our existing producing properties in West Virginia. The $28 million purchase price was reduced by
$0.2 million for various customary closing items, including revenues
F-29
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
received by and expenditures made by the seller related to the properties acquired for the period
between the effective date of the transaction, December 1, 2003, and the closing date, December 31,
2003. The net purchase price of $27.9 million was paid in cash and financed by borrowings under
our revolving bank credit facility. The properties purchased cover approximately 146,000 gross
(83,950 net) acres. The properties acquired include working interests in approximately 774
producing wells Our average working interest is 74% and we will we operate approximately 85% of the
wells acquired. In addition, the interests acquired include approximately 300 wells in which we
will have an overriding royalty interest. Total proved reserves associated with the interests
acquired were 23.4 Bcfe, as of the December 31, 2003.
Transworld Exploration and Production Inc. Acquisition
On October 15, 2003, we completed the acquisition of Transworld Exploration and Production Inc.s
shallow-water Gulf of Mexico natural gas and oil producing properties and undeveloped acreage. At
closing, the $155 million purchase price was reduced by $7.5 million for various customary closing
items, including revenues received by and expenditures made by the seller related to the properties
acquired for the period between the effective date of the transaction, July 1, 2003, and the
closing date, October 15, 2003. The net purchase price of $147.5 million was paid in cash and
financed in part by cash on hand and in part by borrowings under our revolving bank credit
facility. The properties are located primarily in the central Gulf of Mexico in less than 320 feet
of water and include 21 blocks covering 86,237 gross (64,394 net) acres. As of the October 15,
2003 closing date, proved reserves were an estimated 88.5 Bcfe, of which 75% is natural gas. We
operate properties representing 97% of the proved reserves with an average working interest of 65%.
NOTE 11 Subsequent Events
Pending
Sale of Texas Gulf of Mexico Assets
On February 28, 2006,
we entered into a definitive purchase and sale agreement with certain
partnerships affiliated with Merit Energy Company whereby these
entities will acquire the Texas portion of
our Gulf of Mexico assets for a purchase price of $220 million
in cash, subject to adjustment and customary
closing requirements. The sale of these assets will be effective January 1, 2006, and the
transaction is expected to close on March 31, 2006. The Texas portion of our Gulf of Mexico assets
accounted for approximately 18% of our 2005 production and represented 58.5 Bcfe, or 7% of our
total proved reserves, at December 31, 2005.
F-30
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 12 Supplemental Information on Natural Gas and Oil Exploration, Development and Production
Activities (Unaudited)
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. Our natural gas and oil producing activities are conducted onshore within the
continental United States and offshore in federal and state waters of the Gulf of Mexico.
Capitalized Costs of Natural Gas and Oil Properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
|
(in thousands) |
|
Unevaluated properties, not subject to amortization |
|
$ |
107,146 |
|
|
$ |
122,691 |
|
|
$ |
134,491 |
|
Properties subject to amortization |
|
|
3,462,907 |
|
|
|
2,705,897 |
|
|
|
2,252,852 |
|
Asset retirement obligations (1) |
|
|
93,848 |
|
|
|
71,200 |
|
|
|
71,159 |
|
|
|
|
|
|
|
|
|
|
|
Capitalized costs |
|
|
3,663,901 |
|
|
|
2,899,788 |
|
|
|
2,458,502 |
|
Accumulated depreciation, depletion and amortization |
|
|
(1,649,674 |
) |
|
|
(1,355,857 |
) |
|
|
(1,092,073 |
) |
|
|
|
|
|
|
|
|
|
|
Net capitalized costs |
|
$ |
2,014,277 |
|
|
$ |
1,543,931 |
|
|
$ |
1,366,429 |
|
|
|
|
|
|
|
|
|
|
|
Additions to Unevaluated Properties
The following table provides a summary of unevaluated costs not being amortized as of December 31,
2005, by the year in which the costs were incurred. There are no individually significant
properties or significant development projects included in our unevaluated property balance. We
estimate that costs will be evaluated within four years.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs incurred by Year as of December 31, 2005 |
|
|
|
Total |
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
2002 and Prior |
|
|
|
(in thousands) |
|
Property acquisition costs |
|
$ |
82,457 |
|
|
$ |
28,120 |
|
|
$ |
13,104 |
|
|
$ |
28,723 |
|
|
$ |
12,510 |
|
Exploration and development |
|
|
13,599 |
|
|
|
4,429 |
|
|
|
1,168 |
|
|
|
119 |
|
|
|
7,883 |
|
Capitalized interest |
|
|
11,090 |
|
|
|
5,366 |
|
|
|
4,052 |
|
|
|
1,672 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
107,146 |
|
|
$ |
37,915 |
|
|
$ |
18,324 |
|
|
$ |
30,514 |
|
|
$ |
20,393 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalized Costs Incurred
Costs incurred for natural gas and oil exploration, development and acquisition are summarized
below. Costs incurred during the years ended December 31, 2005, 2004 and 2003 include interest
expense and general and administrative costs related to acquisition, exploration and development of
natural gas and oil properties of $25.6 million, $23.2 million and $20.2 million, respectively.
During the years ended December 2005, 2004 and 2003, we spent $128.9 million, $56.7 million and
$46.0 million, respectively, to develop our proved undeveloped reserves.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
|
(in thousands) |
|
Property acquisition and leasehold costs |
|
|
|
|
|
|
|
|
|
|
|
|
Unevaluated |
|
$ |
31,009 |
|
|
$ |
28,059 |
|
|
$ |
61,224 |
|
Proved |
|
|
232,784 |
|
|
|
179,281 |
|
|
|
170,272 |
|
Exploration costs |
|
|
112,634 |
|
|
|
63,646 |
|
|
|
66,259 |
|
Development costs |
|
|
366,902 |
|
|
|
245,971 |
|
|
|
162,235 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
743,329 |
|
|
|
516,957 |
|
|
|
459,990 |
|
Asset
retirement obligations costs assumed (1) |
|
|
23,651 |
|
|
|
12,116 |
|
|
|
31,652 |
|
Asset
retirement obligations costs properties sold (1) |
|
|
(32 |
) |
|
|
(12,714 |
) |
|
|
|
|
Asset retirement expenditures |
|
|
(971 |
) |
|
|
(2,362 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred |
|
$ |
765,977 |
|
|
$ |
513,997 |
|
|
$ |
491,642 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Asset retirement obligation costs reflect abandonment obligations assumed
during the year and revisions to prior estimates. As a result of the disposition of our
South Louisiana and Appalachian Basin assets during 2004, asset retirement obligations were
reduced by $12.7 million. Actual retirement expenditures reflect plugging and abandonment
costs during the year. For 2003, our presentation of asset retirement obligation costs
incurred does not include the cumulative effect of adopting SFAS 143 Asset Retirement
Obligations on January 1, 2003 of $42.5 million.. |
F-31
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Natural Gas and
Oil Reserves
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 the Statement of Financial Accounting Standards 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
independent petroleum consultants. 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.
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 periods during which
they are expected to be produced based on year-end economic conditions. |
|
|
2. |
|
The estimated future cash flows are compiled by applying year-end prices of natural gas
and oil relating to our proved reserves to the year-end quantities of those reserves. |
|
|
3. |
|
The future cash flows are reduced by estimated production costs, costs to develop and
produce the proved reserves and abandonment costs, all based on year-end economic
conditions. |
|
|
4. |
|
Future income tax expenses are based on 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. |
|
|
5. |
|
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 does not include cash flows associated with hedges outstanding at each
of the respective reporting dates.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
|
(in thousands) |
|
Future cash inflows |
|
$ |
7,065,492 |
|
|
$ |
4,558,560 |
|
|
$ |
4,335,669 |
|
Future production costs |
|
|
(1,403,934 |
) |
|
|
(812,800 |
) |
|
|
(764,373 |
) |
Future development costs |
|
|
(874,327 |
) |
|
|
(545,192 |
) |
|
|
(369,121 |
) |
Future income taxes |
|
|
(1,520,815 |
) |
|
|
(976,611 |
) |
|
|
(850,264 |
) |
|
|
|
|
|
|
|
|
|
|
Future net cash flows |
|
|
3,266,416 |
|
|
|
2,223,957 |
|
|
|
2,351,911 |
|
10% annual discount for estimated timing of cash flows |
|
|
(1,299,392 |
) |
|
|
(783,902 |
) |
|
|
(847,505 |
) |
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows |
|
$ |
1,967,024 |
|
|
$ |
1,440,055 |
|
|
$ |
1,504,406 |
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2005, our standardized measure of discounted future net cash flows includes
estimated future development costs for our proved undeveloped reserves for the next three years of
$299.5 million, $205.2 million and $70.3 million, respectively, for 2006, 2007 and 2008.
Present Value of Future Net Cash Flows Relating to Proved Natural Gas and Oil Reserves
The present value of future net cash flows before income tax expense attributable to estimated net
proved reserves, discounted at 10% per annum, (PV10) is a computation of the standardized measure
of discounted future net cash flows on a pre-tax basis. The table below provides a reconciliation
of PV10 to the standardized measure of discounted future net
F-32
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
cash flows. PV10 may be considered a non-GAAP financial measure as defined by the SECs Regulation
G. We consider PV10 to be an important measure for evaluating the relative significance of our
natural gas and oil properties. PV10 is computed on the same basis as the standardized measure of
discounted future net cash flows but without deducting income taxes. We believe investors and
creditors may utilize our PV10 as a basis for comparison of the relative size and value of our
reserves to other companies. However, PV10 is not a substitute for the standardized measure. Our
PV10 measure and the standardized measure of discounted future net cash flows do not purport to
present the fair value of our natural gas and oil reserves. Year-end prices per Mcf
of natural gas used in making the present value and standardized measure determinations as of December 31, 2005,
2004 and 2003 were $8.15, $5.68 and $5.79, respectively. Year-end prices per Bbl of oil
used for the same calculations were $53.27, $41.67 and $30.27,
respectively for 2005, 2004 and 2003.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
|
(in thousands) |
|
Net present value of future cash flows, before income taxes |
|
$ |
2,877,420 |
|
|
$ |
2,071,976 |
|
|
$ |
2,056,414 |
|
Future income taxes, discounted at 10% |
|
|
(910,396 |
) |
|
|
(631,921 |
) |
|
|
(552,008 |
) |
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows |
|
$ |
1,967,024 |
|
|
$ |
1,440,055 |
|
|
$ |
1,504,406 |
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes changes in the standardized measure of discounted future net cash
flows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
|
(in thousands) |
|
Beginning of the year |
|
$ |
1,440,055 |
|
|
$ |
1,504,406 |
|
|
$ |
1,058,064 |
|
Revisions in quantities |
|
|
(251,007 |
) |
|
|
(59,549 |
) |
|
|
(123,954 |
) |
Changes in prices |
|
|
943,487 |
|
|
|
(34,170 |
) |
|
|
459,373 |
|
Changes in future development costs |
|
|
(198,013 |
) |
|
|
(35,056 |
) |
|
|
(13,029 |
) |
Development costs incurred during the period |
|
|
209,322 |
|
|
|
85,439 |
|
|
|
72,717 |
|
Extensions and discoveries, net of related costs |
|
|
620,243 |
|
|
|
445,908 |
|
|
|
434,311 |
|
Sales of natural gas and oil, net of production costs |
|
|
(787,013 |
) |
|
|
(639,555 |
) |
|
|
(486,382 |
) |
Accretion of discount |
|
|
207,197 |
|
|
|
205,641 |
|
|
|
136,492 |
|
Net change in income taxes |
|
|
(278,475 |
) |
|
|
(79,913 |
) |
|
|
(245,151 |
) |
Purchase of reserves in place |
|
|
250,520 |
|
|
|
247,671 |
|
|
|
254,030 |
|
Sale of reserves in place |
|
|
(4,904 |
) |
|
|
(110,877 |
) |
|
|
|
|
Production timing and other |
|
|
(184,388 |
) |
|
|
(89,890 |
) |
|
|
(42,065 |
) |
|
|
|
|
|
|
|
|
|
|
End of year |
|
$ |
1,967,024 |
|
|
$ |
1,440,055 |
|
|
$ |
1,504,406 |
|
|
|
|
|
|
|
|
|
|
|
F-33
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Estimated Net Quantities of Natural Gas and Oil Reserves
The following table sets forth our proved reserves, including changes, and proved developed
reserves (all within the United States) at the end of each of the three years in the period ended
December 31, 2005, 2004 and 2003.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (MMcf) |
|
|
Crude Oil, Liquids and Condensate (MBbls) |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
Beginning of the year reserves |
|
|
749,114 |
|
|
|
709,883 |
|
|
|
610,409 |
|
|
|
7,335 |
|
|
|
7,481 |
|
|
|
6,533 |
|
Revisions of previous estimates |
|
|
(66,205 |
) |
|
|
(13,232 |
) |
|
|
(30,573 |
) |
|
|
1,097 |
|
|
|
(1,110 |
) |
|
|
(1,615 |
) |
Extensions and discoveries |
|
|
135,336 |
|
|
|
162,719 |
|
|
|
140,632 |
|
|
|
1,395 |
|
|
|
255 |
|
|
|
117 |
|
Production |
|
|
(105,809 |
) |
|
|
(115,855 |
) |
|
|
(99,965 |
) |
|
|
(1,417 |
) |
|
|
(1,355 |
) |
|
|
(1,307 |
) |
Purchase of reserves in place |
|
|
81,704 |
|
|
|
67,806 |
|
|
|
89,380 |
|
|
|
3,000 |
|
|
|
2,245 |
|
|
|
3,753 |
|
Sales of reserves in place |
|
|
(1,066 |
) |
|
|
(62,207 |
) |
|
|
|
|
|
|
(119 |
) |
|
|
(181 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year reserves |
|
|
793,074 |
|
|
|
749,114 |
|
|
|
709,883 |
|
|
|
11,291 |
|
|
|
7,335 |
|
|
|
7,481 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year |
|
|
475,080 |
|
|
|
487,867 |
|
|
|
435,629 |
|
|
|
3,535 |
|
|
|
4,073 |
|
|
|
2,413 |
|
End of year |
|
|
506,212 |
|
|
|
475,080 |
|
|
|
487,867 |
|
|
|
6,933 |
|
|
|
3,535 |
|
|
|
4,073 |
|
|
|
|
Natural Gas Equivalents (MMcfe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year reserves |
|
|
793,124 |
|
|
|
754,769 |
|
|
|
649,607 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates |
|
|
(59,623 |
) |
|
|
(19,892 |
) |
|
|
(40,263 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Extensions and discoveries |
|
|
143,706 |
|
|
|
164,249 |
|
|
|
141,334 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
(114,311 |
) |
|
|
(123,985 |
) |
|
|
(107,807 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of reserves in place |
|
|
99,704 |
|
|
|
81,276 |
|
|
|
111,898 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of reserves in place |
|
|
(1,780 |
) |
|
|
(63,293 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year reserves |
|
|
860,820 |
|
|
|
793,124 |
|
|
|
754,769 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year |
|
|
496,290 |
|
|
|
512,305 |
|
|
|
450,107 |
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year |
|
|
547,810 |
|
|
|
496,290 |
|
|
|
512,305 |
|
|
|
|
|
|
|
|
|
|
|
|
|
F-34
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE
13 Quarterly Financial Information (Unaudited)
The following represents our unaudited quarterly results for years ended December 31, 2005 and
2004. There quarterly results were prepared in accordance with GAAP and reflect all adjustments
that are, in the opinion of management, necessary for a fair statement of the results. These
adjustments are of a normal recurring nature.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1st Quarter |
|
|
2nd Quarter |
|
|
3rd Quarter |
|
|
4th Quarter |
|
2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues(1) |
|
$ |
165,720 |
|
|
$ |
175,817 |
|
|
$ |
125,413 |
|
|
$ |
154,593 |
|
Total operating expenses (2) |
|
|
104,119 |
|
|
|
106,117 |
|
|
|
109,180 |
|
|
|
117,391 |
|
Income from operations |
|
|
61,601 |
|
|
|
69,700 |
|
|
|
16,233 |
|
|
|
37,202 |
|
Net income |
|
|
33,438 |
|
|
|
43,830 |
|
|
|
8,081 |
|
|
|
19,820 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
per share basic (4) |
|
$ |
1.17 |
|
|
$ |
1.53 |
|
|
$ |
0.28 |
|
|
$ |
0.69 |
|
Net income
per share diluted (4) |
|
$ |
1.16 |
|
|
$ |
1.51 |
|
|
$ |
0.28 |
|
|
$ |
0.69 |
|
2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
$ |
151,882 |
|
|
$ |
172,776 |
|
|
$ |
162,760 |
|
|
$ |
163,021 |
|
Total operating expenses (3) |
|
|
86,839 |
|
|
|
97,702 |
|
|
|
94,366 |
|
|
|
103,719 |
|
Income from operations |
|
|
65,043 |
|
|
|
75,074 |
|
|
|
68,394 |
|
|
|
59,302 |
|
Net income |
|
|
39,690 |
|
|
|
45,350 |
|
|
|
42,998 |
|
|
|
34,786 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
per share basic (4) |
|
$ |
1.26 |
|
|
$ |
1.49 |
|
|
$ |
1.53 |
|
|
$ |
1.23 |
|
Net income
per share diluted (4) |
|
$ |
1.25 |
|
|
$ |
1.47 |
|
|
$ |
1.51 |
|
|
$ |
1.21 |
|
|
|
|
(1) |
|
For the fourth quarter of 2005, total revenues includes a net loss of $116.5 million
from hedging activities which includes the following items: a $164.5 million loss realized on
contracts settled during fourth quarter; a $20.6 million unrealized gain for the deferral of
losses on settled contracts that were deferred to accumulated other comprehensive income due
to an offshore production shortfall; a $27.6 million unrealized gain for ineffective contracts
which includes $26.4 million due to loss of correlation between the NYMEX price and the
Houston Ship Channel index during the fourth quarter of 2005. |
|
(2) |
|
For the fourth quarter of 2005, total operating expenses includes $4.0 million in
additional general and administrative expenses related to severance and other separation
related payments made to certain former employees, including our former Chief Financial
Officer. |
|
(3) |
|
During the fourth quarter of 2004, as a result of management organizational changes
made within our company in November 2004, we recognized additional general and administrative
expense of $5.1 million. The additional compensation expenses were a result of lump-sum
severance payments and entitlements under executive employment agreements, including expenses
related to the accelerated vesting of stock options and restricted stock. See Note 6
Subsequent Events Lump Sum Payments to Executives Under Employment Contracts. |
|
(4) |
|
Quarterly earnings per share is based on the weighted average number of shares
outstanding during the quarter. Because of changes in the number of shares outstanding during
the quarters due to the exercise of stock options and/or the issuance or repurchase of common
stock, the sum of quarterly earnings per share may not equal earnings per share for the year. |
F-35
INDEX TO EXHIBITS
|
|
|
|
|
EXHIBITS |
|
|
|
DESCRIPTION |
|
3.1
|
|
|
|
Restated Certificate of Incorporation, as amended, including the Certificate of Amendment thereto
dated April 26, 2005 (filed as exhibit 3.1 to our Quarterly Report on Form 10-Q for the period
ended March 31, 2005 (file No. 001-11899) and incorporated by reference herein). |
|
|
|
|
|
3.2(1)
|
|
|
|
Restated Bylaws of The Houston Exploration Company. |
|
|
|
|
|
4.1
|
|
|
|
Indenture, dated as of June 10, 2003, between The Houston Exploration Company and the Bank of New
York, as Trustee, with respect to the 7% Senior Subordinated Notes due 2013 (filed as Exhibit 4.2
to our Registration Statement on Form S-4 (Registration No. 333-106836) and incorporated by
reference). |
|
|
|
|
|
4.2
|
|
|
|
Rights Agreement, dated as of August 12, 2004, between The Houston Exploration Company and The Bank
of New York, as Rights Agent (filed as Exhibit 4.1 to our Current Report on Form 8-K dated August
13, 2004 (File No. 001-11899) and incorporated by reference). |
|
|
|
|
|
4.3
|
|
|
|
First Amendment dated as of May 2, 2005, to the Rights Agreement dated as of August 12, 2004
between The Houston Exploration Company and The Bank of New York, as Rights Agent (filed as exhibit
4.1 to our Quarterly Report on Form 10-Q for the period ended March 31, 2005 on April 26, 2005
(file No. 001-11899) and incorporated by reference herein). |
|
|
|
|
|
4.4
|
|
|
|
Form of Certificate of Designation of Series A Junior Participation Preferred Stock of The Houston
Exploration Company (filed as Exhibit 4.2 to our Current Report on Form 8-K dated August 13, 2004
(File No. 001-11899) and incorporated by reference). |
|
|
|
|
|
10.1
|
|
|
|
Amended and Restated Credit Agreement dated November 30, 2005 among The Houston Exploration Company
and Wachovia Bank, National Association, as Issuing Bank and Administrative Agent; The Bank of Nova
Scotia and Bank of America as Co-Syndication Agents; and BNP Paribas and Comerica Bank as
Co-Documentation Agents (filed as exhibit 99.1 to our Current Report on Form 8-K dated November 30,
2005 (File No. 001-11899) and incorporated by reference). |
|
|
|
|
|
10.2(2)
|
|
|
|
Deferred Compensation Plan for Non-Employee Directors (filed as Exhibit 10.24 to our Annual Report
on Form 10-K for the year ended December 31, 1997 (File No. 001-11899) and incorporated by
reference). |
|
|
|
|
|
10.3(2)
|
|
|
|
Compensation Table for Non-Employee Directors, effective January 1, 2006 (filed as exhibit 99.2 to
our Current Report on Form 8-K dated January 6, 2006. |
|
|
|
|
|
10.4(2)
|
|
|
|
Amended and Restated 1996 Stock Option Plan (filed as Exhibit 10.1 to our Quarterly Report on Form
10-Q for the quarter ended June 30, 1998 (File No. 001-11899) and incorporated by reference). |
|
|
|
|
|
10.5(2)
|
|
|
|
1999 Non-Qualified Stock Option Plan dated October 26, 1999 (filed as Exhibit 10.24 to our Annual
Report on Form 10-K for the year ended December 31, 1999 (File No. 001-11899) and incorporated by
reference). |
|
|
|
|
|
10.6(2)
|
|
|
|
Executive Deferred Compensation Plan dated January 1, 2002 (filed as Exhibit 10.28 to our Annual
Report on Form 10-K for the year ended December 31, 2002 (File No. 001-11899) and incorporated by
reference). |
|
|
|
|
|
10.7(2)
|
|
|
|
Amendment to The Houston Exploration Company Executive Deferred Compensation
Plan (filed as exhibit 99.2 to our Current Report on Form 8-K file dated January 31, 2006
(File No. 001-11899) and incorporated by reference). |
|
|
|
|
|
10.8(2)
|
|
|
|
Amended and Restated 2002 Long-Term Incentive Plan effective May 17, 2002, adopted October 26,
2003 (filed as Exhibit 10.31 to our Annual Report on Form 10-K for the year ended December 31,
2003 (file No. 001-11899) and incorporated by reference). |
|
|
|
|
|
10.9(2)
|
|
|
|
Amended and Restated 2004 Long Term Incentive Plan (filed as exhibit 99.1 to our Current Report on
Form 8-K file dated January 31, 2006 (File No. 001-11899) and incorporated by reference). |
F-36
|
|
|
|
|
EXHIBITS |
|
|
|
DESCRIPTION |
10.10(2)
|
|
|
|
Supplemental Executive Retirement Plan dated January 1, 2006 (filed as exhibit 99.1 to our Current
Report on Form 8-K dated January 6, 2006 (File No. 001-11899) and incorporated by reference). |
|
|
|
|
|
10.11(2)
|
|
|
|
Employment Agreement dated July 16, 2001 between The Houston Exploration Company and Tracy Price
(filed as Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30,
2001 (File No. 001-11899) and incorporated by reference). |
|
|
|
|
|
10.12(2)
|
|
|
|
Employment Agreement dated September 29, 2003 between The Houston Exploration Company and Timothy
R. Lindsey (filed as Exhibit 10.3 to our Quarterly Report on Form 10-Q for the quarter ended
September 30, 2003 (File No. 001-11899) and incorporated by reference). |
|
|
|
|
|
10.13(2)
|
|
|
|
Amended and Restated Employment Agreement dated February 8, 2005 between The Houston Exploration
Company and William G. Hargett (filed as Exhibit 10.1 to our Current Report on Form 8-K dated
February 8, 2005 (File No. 001-11899) and incorporated by reference). |
|
|
|
|
|
10.14(2)
|
|
|
|
Amended and Restated Employment Agreement between The Houston Exploration Company and Steven L.
Mueller dated February 8, 2005 (filed as Exhibit 10.19 to
our Annual Report on Form 10-K for the year ended
December 31, 2004 (File No. 001-11899) and incorporated by
reference). |
|
|
|
|
|
10.15(2)
|
|
|
|
Amended and Restated Employment Agreement between The Houston Exploration Company and John H.
Karnes February 8, 2005 (filed as Exhibit 10.20 to
our Annual Report on Form 10-K for the year ended
December 31, 2004 (File No. 001-11899) and incorporated by
reference). |
|
|
|
|
|
10.16(2)
|
|
|
|
Separation Agreement and General Release dated December 8, 2005 between the Company and John H.
Karnes (filed as exhibit 99.1 to our Current Report on Form 8-K dated December 12, 2005 (File No.
001-11899) and incorporated by reference) . |
|
|
|
|
|
10.17(2)
|
|
|
|
Amended and Restated Employment Agreement between The Houston Exploration Company and James F.
Westmoreland dated February 8, 2005 (filed as Exhibit 10.21 to
our Annual Report on Form 10-K for the year ended
December 31, 2004 (File No. 001-11899) and incorporated by
reference). |
|
|
|
|
|
10.18(2)
|
|
|
|
Amended and Restated Employment Agreement between The Houston Exploration Company and Roger B.
Rice dated February 8, 2005 (filed as Exhibit 10.22 to
our Annual Report on Form 10-K for the year ended
December 31, 2004 (File No. 001-11899) and incorporated by
reference). |
|
|
|
|
|
10.19(2)
|
|
|
|
Employment Agreement dated February 10, 2005 between The Houston Exploration Company and Joanne C.
Hresko (filed as Exhibit 10.3 to our Current Report on Form 8-K dated February 8, 2005 (File No.
001-11899) and incorporated by reference). |
|
|
|
|
|
10.20(2)
|
|
|
|
Employment Agreement effective March 10, 2005, between John E. Bergeron, Jr. and The Houston
Exploration Company (filed as exhibit 99.2 to our Current Report on Form 8-K dated March 10, 2005
(File No. 001-11899) and incorporated by reference). |
|
|
|
|
|
10.21(2)
|
|
|
|
Employment Agreement effective April 13, 2005, between Jeffrey B. Sherrick and The Houston
Exploration Company (filed as exhibit 99.2 to our Current Report on Form 8-K dated April 13, 2005
(File No. 001-11899) and incorporated by reference). |
|
|
|
|
|
10.22(2)
|
|
|
|
Employment Agreement dated January 18, 2006 between Robert T. Ray and The Houston Exploration
Company (filed as exhibit 99.1 to our Current Report on Form 8-K dated January 18, 2006 (File No.
001-11899) and incorporated by reference). |
|
|
|
|
|
10.23(2)
|
|
|
|
Compensation Table for Executive Officers (filed as Exhibit 10.2 to our Quarterly Report on Form
10-Q for the period ended September 30, 2005 (File No. 001-11899) and incorporated by reference). |
|
|
|
|
|
10.24(2)
|
|
|
|
Change of Control Plan dated October 26, 1999 (filed as Exhibit 10.25 to our Annual Report on Form
10-K for the year ended December 31, 1999 (File No. 001-11899) and incorporated by reference). |
|
|
|
|
|
10.25
|
|
|
|
Purchase and Sale Agreement, dated September 3, 2003, by and among Transworld Exploration and
Production, Inc., as Seller, and The Houston Exploration Company, as Buyer (Exhibit 2.1 to Current
Report on Form 8-K dated October 15, 2003 (file No. 001-11899) and incorporated by reference). |
F-37
|
|
|
|
|
EXHIBITS |
|
|
|
DESCRIPTION |
10.26
|
|
|
|
Purchase and Sale Agreement, dated September 17, 2004, between The Houston Exploration Company and
Orca Energy, L.P. (filed as Exhibit 2.1 to our Current Report on Form 8-K dated November 1, 2004
(File No. 001-11899) and incorporated by reference). |
|
|
|
|
|
10.27
|
|
|
|
Purchase and sale agreement dated October 21, 2005 by and between Kerr-McGee Oil & Gas Onshore LP
D/B/A KMOG Onshore LP and Westport Oil and Gas Company, L.P., as sellers, and The Houston
Exploration Company, as buyer, (filed as exhibit 99.2 to our Current Report on Form 8-K dated
November 30, 2005 (File No. 001-11899) and incorporated by reference). |
|
|
|
|
|
10.28
|
|
|
|
Distribution Agreement dated as of June 2, 2004 by and among The Houston Exploration Company,
Seneca-Upshur Petroleum, Inc., THEC Holdings Corp. and KeySpan Corporation (filed as Exhibit 99.2
to our Current Report on Form 8-K dated June 30, 2004 (File No. 001-11899) and incorporated by
reference). |
|
|
|
|
|
10.29
|
|
|
|
Asset Contribution Agreement dated June 2, 2004 between The Houston Exploration Company and
Seneca-Upshur Petroleum, Inc. (filed as Exhibit 99.3 to our Current Report on Form 8-K dated June
30, 2004 (File No. 001-11899) and incorporated by reference). |
|
|
|
|
|
10.30
|
|
|
|
Tax Matters Agreement dated as of June 2, 2004 by and among The Houston Exploration Company,
Seneca-Upshur Petroleum, Inc., THEC Holdings Corp., and KeySpan Corporation (filed as Exhibit 99.4
to our Current Report on Form 8-K dated June 30, 2004 (File No. 001-11899) and incorporated by
reference). |
|
|
|
|
|
12.1(1)
|
|
|
|
Computation of ratio of earnings to fixed charges. |
|
|
|
|
|
21.1(1)
|
|
|
|
Subsidiaries of The Houston Exploration Company. |
|
|
|
|
|
23.1(1)
|
|
|
|
Consent of Deloitte & Touche LLP. |
|
|
|
|
|
23.2(1)
|
|
|
|
Consent of Netherland, Sewell & Associates. |
|
|
|
|
|
23.3(1)
|
|
|
|
Consent of Miller and Lents. |
|
|
|
|
|
31.1(1)
|
|
|
|
Certification of William G. Hargett, Chief Executive Officer, as required pursuant to Section 302
of the Sarbanes-Oxley Act of 2002. |
|
|
|
|
|
31.2(1)
|
|
|
|
Certification of Robert T. Ray, Chief Financial Officer, as required pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002. |
|
|
|
|
|
32.1(1)
|
|
|
|
Certification of William G. Hargett, Chief Executive Officer, as required pursuant to Section 906
of the Sarbanes-Oxley Act of 2002. |
|
|
|
|
|
32.2(1)
|
|
|
|
Certification of Robert T. Ray, Chief Financial Officer, as required pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002. |
|
|
|
(1) |
|
Filed herewith. |
|
(2) |
|
Management contract or compensation plan. |
F-38