UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
|
þ
|
ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE
SECURITIES EXCHANGE ACT OF 1934
|
|
For
the Fiscal Year Ended December 31, 2008
OR
|
p
|
TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d)
OF
THE SECURITIES EXCHANGE ACT OF 1934
|
|
Commission
File Number 0-9120
TXCO
Resources Inc.
(Exact
name of Registrant as specified in its charter)
|
Delaware
|
84-0793089
|
|
(State
or other jurisdiction of
|
(I.R.S.
Employer
|
|
incorporation
or organization)
|
Identification
No.)
|
|
|
|
777
E. Sonterra Blvd., Suite 350; San Antonio, Texas
|
78258
|
|
(Address
of principal executive offices)
|
(Zip
Code)
|
Registrant's
telephone number, including area code:
(210) 496-5300
Securities
registered pursuant to Section 12(b) of the
Act:
|
Title
of each class
|
Name
of each exchange on which registered
|
|
Common
Stock par value $0.01 per share
|
NASDAQ Global Select
Market
SM
|
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.
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act.
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
p
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.
p
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting company. See
definition of "large accelerated filer," "accelerated filer" and "smaller
reporting company" in Rule 12b-2 of the Exchange Act.
|
Large
accelerated filer
p
|
Accelerated filer
þ
|
|
Non-accelerated
filer
p
(Do not check if a smaller reporting company)
|
Smaller-reporting
company
p
|
Indicate by check mark if the
registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act). Yes
p
No
þ
The
aggregate market value of the Registrant's Common Stock held by non-affiliates
on June 30, 2008 (the last business day of the Registrant's most recently
completed second fiscal quarter) was approximately $396.4 million, based on
the $11.76 per share closing price as reported on the NASDAQ Global Select
Market.
The
number of shares outstanding of the registrant's Common Stock as of March 13,
2009, was 38,691,241.
Documents
Incorporated by Reference: Portions of the Company's Definitive Proxy
Statement for the 2009 Annual Stockholders' Meeting are incorporated by
reference into Items 10, 11, 12, 13 and 14 of Part III of this filing. The Proxy
Statement for the 2009 Annual Stockholders' Meeting will be filed with the
Securities and Exchange Commission, pursuant to Regulation 14A, not later than
120 days after the end of the 2008 fiscal year, or, if we do not file the proxy
statement within such 120-day period, we will amend this Annual Report on Form
10-K to include the information required under Part III hereof not later than
the end of such 120-day period.
INDEX
AND
CROSS
REFERENCE SHEET
|
|
|
Page
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unresolved
Staff Comments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Submission
of Matters to a Vote of Security Holders
|
|
|
|
|
|
|
|
|
|
|
|
Market for
Registrant
'
s Common Equity
,
Related Stockholder
Matters
and
Issuer Purchases of Equity Securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Management's
Discussion and Analysis of Financial Condition and Results of
Operations
|
|
|
|
|
|
|
|
Quantitative and Qualitative
Disclosures About Market Risk
|
|
|
|
|
|
|
|
Financial
Statements and Supplementary Data
|
|
|
|
|
|
|
|
Changes
in and Disagreements with Accountants on Accounting and Financial
Disclosure
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Directors,
Executive Officers and Corporate Governance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Security Ownership of Certain
Beneficial Owners and Management
and Related Stockholder
Matters
|
|
|
|
|
|
|
|
Certain
Relationships and Related Transactions, and Director
Independence
|
|
|
|
|
|
|
|
Principal
Accounting Fees and Services
|
|
|
|
|
|
|
|
|
|
|
|
Exhibits,
Financial Statement Schedules
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Audited
Consolidated Financial Statements
|
|
CAUTIONARY
NOTE REGARDING FORWARD-LOOKING STATEMENTS
Statements
in this Form 10-K that are not historical, including statements regarding TXCO's
or management's intentions, hopes, beliefs, expectations, representations,
projections, estimations, plans or predictions of the future, are
forward-looking statements and are made pursuant to the safe harbor provisions
of the Private Securities Litigation Reform Act of 1995. Such statements include
those relating to:
|
|
·
|
waivers
or other relief from TXCO lenders,
|
|
|
·
|
estimated
financial results,
|
|
|
·
|
bank
credit and working capital
availability,
|
|
|
·
|
number
of drilling locations,
|
|
|
·
|
expected
drilling plans, including the timing, category, number, depth, cost and/or
success of wells to be drilled,
|
|
|
·
|
expected
geological formations, or
|
|
|
·
|
the
availability of specific services, equipment or
technologies.
|
It is
important to note that actual results may differ materially from the results
predicted in any such forward-looking statements. Investors are cautioned that
all forward-looking statements involve risks and uncertainties including without
limitation:
|
|
·
|
our
ability to obtain capital on reasonable terms, or at all, to fund our
working capital or other needs,
|
|
|
·
|
the
adequacy of our liquidity and our ability to meet our cash commitments,
working capital needs, lender and vendor obligations and our commitments
to pay any cash dividends on our preferred
stock,
|
|
|
·
|
general
market conditions,
|
|
|
·
|
adverse
capital and credit market
conditions,
|
|
|
·
|
uncertainty
about the effectiveness of the U.S. Government's plan to stabilize
financial markets,
|
|
|
·
|
the
impairment of financial
institutions,
|
|
|
·
|
the
costs and accidental risks inherent in exploring and developing new oil
and natural gas reserves,
|
|
|
·
|
the
price for which such reserves and production can be
sold,
|
|
|
·
|
fluctuation
in prices of oil and natural gas,
|
|
|
·
|
the
uncertainties inherent in estimating quantities of proved reserves and
cash flows,
|
|
|
·
|
actions
by third party co-owners in properties in which we also own an
interest,
|
|
|
·
|
acquisitions
of properties and businesses,
|
|
|
·
|
environmental
concerns affecting the drilling of oil and natural gas
wells,
|
|
|
·
|
impairment
of oil and natural gas properties due to depletion or other
causes,
|
|
|
·
|
dependence
on key personnel, and
|
|
|
·
|
hedging
decisions, including whether or not to
hedge.
|
TXCO
undertakes no obligation to revise or update any forward-looking statements, or
to make any other forward-looking statements, whether as a result of new
information, future events or otherwise. Please refer to the Risk Factors
discussion in
Part I, Item 1A
for additional
information.
PART
I
ITEM
1. BUSINESS
GENERAL
At the 2007 Annual Stockholders'
Meeting, our stockholders approved the change of the Company's name to TXCO
Resources Inc. from The Exploration Company of Delaware, Inc. The Exploration
Company was incorporated in the State of Colorado in 1979 and reincorporated in
the State of Delaware in 1999, becoming The Exploration Company of Delaware,
Inc. Our trading symbol on the NASDAQ Global Select Market
SM
is TXCO. Unless the context requires
otherwise, when we refer to "TXCO", "the Company", "we", "us" and "our", we are
describing TXCO Resources Inc. Our contact information is (1) by mail: 777
E. Sonterra Blvd., Suite 350, San Antonio, Texas 78258, (2) by phone:
210/496-5300. Our Web site is www.txco.com.
We file
annual, quarterly, current reports, proxy statements and other information with
the Securities and Exchange Commission ("SEC"). All of these reports are
available on our Web site under the link "SEC Filings" on the "Investor
Relations" menu, as soon as reasonably practicable after we electronically file
with or furnish them to the SEC. Forms 3, 4 and 5 may also be accessed from the
"Insider Filings" link on the "Governance" menu. You may obtain free of charge a
copy of the reports (and any amendment thereto) provided to the SEC by written
request to the Corporate Secretary at the address above.
Also
under the "Governance" menu of our Web site, you can access our corporate
governance documents, including our Code of Conduct and charters for the
Governance and Nominating, and Audit Committees of our Board of Directors. The
"Investor Relations" menu also contains links to recent presentations, news
releases, and supplemental information. The content on any Web site referred to
in this Form 10-K is not incorporated by reference into this Form
10-K.
As of
February 28, 2009, we employed 121 full-time employees including management. We
believe our relations with our employees are good. None of our employees are
covered by union contracts.
We are an
independent oil and natural gas enterprise with interests in the Maverick Basin
of Southwest Texas, the Fort Trinidad area in East Texas, the onshore Gulf Coast
region and the Marfa Basin of Texas, the Midcontinent region of western
Oklahoma, and shallow Gulf of Mexico waters. Our primary business operation is
exploration, exploitation, development, production and acquisition of
predominately onshore domestic oil and natural gas reserves.
RECENT
DEVELOPMENTS
Liquidity
Issues/Going Concern:
During 2008, the Company engaged in its
largest capital expenditure program in its history. Our costs incurred in the
development and purchase of oil and natural gas properties increased from $117
million in 2007 to $182 million in 2008. While pursuing our drilling program,
costs to drill escalated throughout the summer followed by an unprecedented
commodity price collapse. As a result of the time lag between incurring drilling
costs and the resulting increase in revenues from new production, and
deteriorating economic conditions, we have experienced severe cash flow
constraints. We have experienced substantial difficulties in meeting
our short-term cash needs, particularly in relation to our vendor commitments.
Substantially all of our assets are pledged, and extreme volatility in energy
prices and a deteriorating global economy are creating great difficulties in the
capital markets and have greatly hindered our ability to raise debt and/or
equity capital.
At
December 31, 2008, we had a working capital deficiency of $256.9 million,
including $153.0 million reclassified from long-term debt and $66.9 million
reclassified to current liabilities from preferred stock due to defaults under
those instruments, which allow the lenders to demand immediate repayment under
our bank credit facilities and the holders of our preferred stock to demand
redemption. However, under the terms of the Certificates of Designations our
obligation to pay the redemption price of any preferred stock demanded to be
redeemed is suspended until the earlier of (i) October 31, 2012 or (ii) the date
that all of our obligations under the bank credit facilities have been
satisfied. We had $49.7 million in trade payables at December 31, 2008, of which
approximately $4.1 million was 60 days or more past due. Our failure to reach
accommodations with our vendors regarding the timing of payment in light of our
limited liquidity could result in liens filed against our properties or
withdrawal of trade credit, which in turn could limit our ability to conduct
operations on properties. While we continue to examine alternatives to improve
our liquidity and cash resources, including seeking additional short and
long-term capital through bank borrowings, the issuance of debt instruments, the
sale of common stock and preferred stock, the sale of non-strategic assets,
joint-venture financing, and restructuring our existing obligations, our
inability to improve our liquidity and cash resources will cause us to
experience material adverse business consequences, including our inability to
continue in existence.
Our
accompanying financial statements have been prepared assuming we will continue
as a going concern. However, due to our deficiency in short-term and
long-term liquidity, our ability to continue as a going concern is dependent on
our success in generating additional sources of capital in the near future. We
have received a report from our independent registered public accounting firm on
our consolidated financial statements for the year ended December 31, 2008, in
which they have included an explanatory paragraph indicating that our working
capital deficiency, non-compliance with our current ratio covenant under our
bank credit facilities and violation of a provision of the certificate of
designation of the Series D and Series E Convertible Preferred Stock, are
factors which raise substantial doubt about our ability to continue as a going
concern. See "Capital Resources and Liquidity" in Item 7 for further discussion
of liquidity issues.
Bank Credit
Facilities:
In connection with the preparation of our 2008
financial statements, we determined that we were in violation of the current
ratio covenant of our Amended and Restated Credit Agreement, dated April 2,
2007, as amended on July 25, 2007, and our Amended and Restated Term Loan
Agreement, dated July 25, 2007 (collectively, the "bank credit facilities"),
each with Bank of Montreal, as lender and administrative agent, and the other
lenders party thereto.
As a
result of this default, the lenders may, among other things, (i) terminate their
commitments to make loans and participate in the issuance of letters of credit,
and (ii) declare all or any part of the unpaid principal and accrued interest
under the bank credit facilities immediately due and payable. Due to such
covenant violation, our lenders are not permitting us to make additional
borrowings under our bank credit facilities. See "Bank Credit Facilities" in
Item 7 for further discussion of our bank credit facilities.
We are
continuing discussions with the bank credit facilities' lenders regarding a
waiver of the current ratio covenant, or other arrangements whereby the credit
facility lenders would refrain from exercising their rights under the bank
credit facilities as a result of the above-mentioned default. There can be no
assurances that the Company will be able to obtain a waiver of the current ratio
covenant or obtain other relief from our bank credit facility lenders. If the
lenders demand immediate repayment of our outstanding borrowings under the bank
credit facilities, we do not currently have means to repay or refinance the
amounts that would be due. If demanded and we failed to repay the amounts due
under the bank credit facilities, the lenders could exercise their remedies
under the bank credit facilities, including foreclosing on substantially all our
assets, which we pledged as collateral to secure our obligations under the bank
credit facilities. These circumstances could require us to seek relief through a
filing under the U.S. Bankruptcy Code.
Preferred
Stock:
Under the terms of our Certificate of Designations, Preferences
and Rights of Series D Convertible Preferred Stock and Certificate of
Designations, Preferences and Rights of Series E Convertible Preferred Stock
(collectively, the "Certificates of Designations"), the default under the bank
credit facilities results in the holders of the Series D and Series E
Convertible Preferred Stock having a right to demand that we redeem the
preferred stock at the premium redemption price set forth in the Certificates of
Designations. However, under the terms of the Certificates of Designations our
obligation to pay the redemption price of any preferred stock demanded to be
redeemed is suspended until the earlier of (i) October 31, 2012 or (ii) the date
that all of our obligations under the bank credit facilities have been
satisfied. Under the terms of the Certificates of Designations, the Company is
obligated to pay interest at a rate of 1.5% per month in respect of each
preferred share for which redemption has been demanded until paid in full. On
March 9, 2009, a holder of preferred stock demanded redemption of 34,409 shares
of Series D Convertible Preferred Stock and 15,000 shares of Series E
Convertible Preferred Stock. Generally, holders of our preferred stock are
entitled to receive dividends, payable quarterly, at the rate of 6.5% and 6.0%
per annum for Series D and Series E, respectively. In connection with our breach
of the current ratio in our bank credit facilities, the dividend rate is
increased to 12% per annum for both the Series D and Series E Preferred Stock
until such time as the breach of the current ratio covenant is
cured.
Market
Conditions:
Beginning in October 2008 and continuing into early 2009, oil
and natural gas prices declined significantly, and remain volatile. The decline
in commodity prices resulted in significantly reduced revenues, net income and
cash flows for the fourth quarter of 2008, and this reduction has continued in
the first quarter of 2009
.
If oil and natural gas prices remain at current levels for any prolonged period
of time or decline further, our financial condition, operating results and cash
flows, as well as access to debt and equity capital will be further materially
adversely affected. Additionally, perceptions by oil and natural gas companies
that oil and natural gas prices will be lower long-term can similarly reduce or
defer major expenditures, which will impact our ability to attract partners for
certain of our activities.
The
United States, like many foreign countries, is currently experiencing volatility
in its financial and credit markets, which is having an adverse impact on many
companies' ability to obtain credit. Historically, we have relied on access to
the debt and equity markets to finance our capital needs.
Strategic
Alternatives Review:
On February 12, 2009, we announced that we retained
Goldman, Sachs & Co. as a financial advisor for a strategic alternatives
review designed to enhance stockholder value, which may include sale of certain
assets, issuance of stock, additional debt or other securities, or a merger or
sale of the Company.
Management
is actively pursuing options to improve liquidity. This includes drilling joint
ventures, sale of certain assets, reduction in staff, shutting down certain
operations, and other capital raising efforts. This plan attempts to ease our
immediate liquidity problems allowing us time to consider other significant
initiatives through the Goldman, Sachs & Co. strategic alternative review
process.
No formal
decisions have been made and no agreements have been reached at this time. There
can be no assurance that any particular alternative will be pursued or that any
transaction will occur, or on what terms. We do not expect to disclose
developments from this review unless our board of directors approves a
definitive transaction.
2008 Drilling
Activity Summary:
We participated in
drilling a total of 96 gross wells during 2008. Maverick Basin wells totaled 83,
including 20 re-entries. We participated in 11 wells on former Output
assets, one well in the Marfa Basin and one well in the Williston Basin.
Additionally, 11 wells that were in completion at the beginning of the year
resulted in producing well completions during 2008. Activity in these plays is
described in Item 2 under the "Maverick Basin Plays" and "Other Areas"
sections.
Reserves:
Estimated
net proved reserves at year-end 2008 were 81.7 billion cubic feet equivalent
("Bcfe"), a 10.1 Bcfe, or 11.0%, decrease from 91.8 Bcfe at year-end 2007.
Annual production for 2008 was 9.2 Bcfe. Reserves sold during 2008 were 3.8
Bcfe. Net reserve additions for the year were 2.9 Bcfe in the face of downward
revision in reserve estimates due to the decline in oil and natural gas prices
in late 2008. This decline in prices was partially offset by commodity hedges in
place on a portion of our oil and natural gas production.
Exploration,
exploitation and development targets during 2008, presented in descending depth
order, included:
|
·
|
development
on our San Miguel oil sand
projects;
|
|
·
|
expanding
waterflood oil production from the San Miguel interval on the Pena Creek
lease;
|
|
·
|
drilling
horizontal wells in the Austin
Chalk;
|
|
·
|
expanding
oil and natural gas production from Georgetown horizontal
wells;
|
|
·
|
additional
horizontal wells targeting Glen Rose porosity oil
production;
|
|
·
|
expanding
waterflood oil production from the Red River B formation in East Harding
Springs;
|
|
·
|
vertical
wells targeting natural gas from the Eagle Ford and Pearsall
Shales;
|
|
·
|
horizontal
and vertical drilling for Glen Rose shoal natural gas intervals on our
Fort Trinidad leases;
|
|
·
|
evaluation
of the Barnett and Woodford Shales in the Marfa
Basin;
|
|
·
|
an
additional well to the Jurassic
formation; and
|
·
wells
targeting the Springer-Morrow sands in the Anadarko Basin.
We
believe each of these exploration, exploitation and development targets has
potential to establish meaningful additions to our oil and natural gas
production and proved reserves, along with significant numbers of new, proved
undeveloped, lower-risk drilling locations. However, because of the recent
decline in commodity prices, and current liquidity constraints, we do not expect
to be able to exploit all of these opportunities in the near
future.
2009 Capital
Expenditures Budget:
Due to our current liquidity constraints, we
plan to significantly reduce our capital expenditures ("CAPEX") until financial
resources are available to support additional expenditures. Our inability to
continue our drilling programs at or near our 2008 levels, and thereby replace
oil and natural gas reserves that are being depleted by production with new
reserves, will result in a decline in our reserves and revenues and our ability
to conduct operations will be, and our future growth will be, materially
adversely affected. We plan to hold our capital expenditures within cash flow
during 2009 and endeavor to drill wells to hold leases and uphold our
commitments under the EnCana and Anadarko farm-out agreements. There can be no
assurances that we will have sufficient cash flow during 2009 to honor our
commitments under the EnCana and Anadarko farm-out agreements without joint
venture agreements or sale of an interest in the project.
Our CAPEX
may expand or contract based on the results of our strategic alternatives
review, drilling results, operational developments, market conditions, commodity
price fluctuations and working capital availability. Based on currently
projected commodity prices, we expect our profitability to decline in 2009 and
we may experience a net loss.
LONG-TERM
STRATEGY
Our
business strategy is to build stockholder value by acquiring undeveloped mineral
interests and internally developing a multi-year drilling inventory through the
use of advanced technologies, such as 3-D seismic and horizontal drilling. We
strive to discover, develop and/or acquire more oil and natural gas reserves
than we produce each year from these internally developed
prospects.
As
opportunities arise and when financing is available, we may selectively
participate with industry partners in prospects generated internally as well as
by other parties. We attempt to maximize the value of our technical expertise by
contributing our geological, geophysical and operational core competencies
through joint ventures or other forms of strategic alliances with other
well-capitalized industry partners in exchange for carried interests in seismic
acquisitions, leasehold purchases and/or wells to be drilled. From time to time,
we offer portions of our developed and undeveloped mineral interests for sale.
We have financed our activities through internally generated operating cash
flows, as well as debt financing and equity offerings, or sale of interests in
properties when favorable terms or opportunities are available.
Management's
ongoing strategy for improved stockholder value includes maintaining a focus on
our core business of oil and natural gas exploration, exploitation and
production. This strategy allows us to attract recognized industry partners,
expand our core area leasehold acreage, and increase our 3-D seismic database
and interpretative skill set. This strategy, coupled with our drill bit success,
allows us to grow our reserve base. We focus primarily on the Maverick Basin and
have successfully established a multi-year portfolio of drilling targets within
this area.
Our
established operating strategy includes the pursuit of multiple growth
opportunities and diversified exploration and exploitation targets within our
core area of operations. The Maverick Basin offers multiple hydrocarbon-bearing
horizons, including several resource plays. In addition, we are evaluating
opportunities in our Marfa Basin acreage.
On April
2, 2007, we took another step in expanding beyond these core areas through the
acquisition of Output Exploration, LLC ("Output"), a privately held,
Houston-based exploration and production firm. The core of the Output holdings,
in the East Texas Fort Trinidad Field, is prospective for the Glen Rose, Buda,
Austin Chalk, Eagle Ford / Woodbine and Bossier formations. Other Output assets
acquired include acreage in the Midcontinent region of western Oklahoma, the
Gulf Coast region and shallow Gulf of Mexico waters. Certain of the properties
acquired were later sold.
PRINCIPAL AREAS OF ACTIVITY
Oil and Natural
Gas Operations:
During 2008, we spudded
or re-entered a total of 96 wells, including 83 wells in various horizons in the
Maverick Basin, 11 wells on former Output acreage, one well in the Marfa Basin
and one in the Williston Basin. These totals compared to 87, 71, 12, one and
three, respectively, in 2007. Of the 96 total wells begun in 2008, 55 have been
placed on production through February 2009. Producing wells include 47 oil wells
in the Glen Rose, Austin Chalk, San Miguel, Georgetown, and Red River
formations, and five natural gas wells completed in the Glen Rose, San Miguel,
Georgetown, Eagle Ford and Pearsall formations in the Maverick Basin, as well as
two oil wells and one natural gas well completed on former Output holdings. One
well was dry and will be plugged. Additionally, five oil wells and five natural
gas wells that were begun in prior years were placed on production during
2008.
Our
strategy remains focused primarily on our core oil and natural gas producing
properties and higher margin exploration, exploitation and development
activities in the Maverick Basin, while selectively developing opportunities in
our newly acquired Output properties and continuing to evaluate opportunities in
our Marfa Basin acreage. We continue to evaluate economic alternatives related
to our few remaining properties in the Williston Basin, including efforts to
either locate suitable joint venture partners, farmout, or sell our interest in
that basin.
At
year-end 2008, we had an average working interest ("WI") of over 67% on our
Maverick Basin leasehold acreage (approximately 1.0 million gross acres). A
large portion of this
contiguous
lease block is situated on the Chittim Anticline, a large regional geologic
structure. Hydrocarbons have been found in at least 14 separate horizons along
the structure including the Lower Glen Rose or Rodessa interval -- a carbonate
formation that has produced billions of cubic feet of natural gas from patch
reefs and shoals. At year-end 2008, we also had an average WI over 75% on our
Fort Trinidad leasehold acreage, which was approximately 36,500 gross
acres.
We
utilize 3-D seismic survey data as an integral part of our interpretative
methodology for the identification and evaluation of drilling prospects in most
of our active plays. At year-end 2008 we had accumulated over 942 square miles
of 3-D seismic data covering more than 60% of our 1,500-square-mile Maverick
Basin lease block.
Our
geologists and geophysicists have identified and mapped numerous geological
formations at various depths on most of our lease block. This provides a
growing, multi-year inventory of alternative drilling prospects for the ongoing
evaluation of horizons known to be productive for oil and/or natural gas within
and around our leases in the Maverick Basin. The active plays under ongoing
evaluation by our engineers are described under the
"Maverick Basin Plays"
heading in Item 2.
The
following table contains details by formation in descending depth order for our
approximate working interest ownership in certain of our holdings:
|
|
|
Working
Interest
Range
|
|
|
|
San
Miguel Oil Sands - Oil
|
|
|
|
|
San
Miguel Waterflood - Oil
|
|
|
|
|
Eagle
Ford Shale - Natural Gas and Oil
|
|
|
|
|
Georgetown
- Oil and Natural Gas
|
|
|
|
|
Glen
Rose Porosity Zone - Oil
|
|
|
|
|
Other
Maverick Basin Glen Rose - Oil and Natural Gas
|
|
|
|
|
Pearsall
Shale - Natural Gas
|
|
|
|
|
Barnett
and Woodford Shales - Natural Gas
|
|
|
|
|
|
|
|
The
expanding geophysical database, drilling results and the growing number of
prospective formations targeted by our drilling programs with our partners
reaffirmed our longstanding belief that our exploration and development
possibilities on our Maverick Basin lease block remain very
significant.
PRINCIPAL
PRODUCTS AND COMPETITION
Our
principal products are crude oil and natural gas. The production and marketing
of oil and natural gas are affected by a number of factors beyond our control,
the effects of which we can not accurately predict. These factors include crude
oil imports, actions by foreign oil-producing nations, the availability of
adequate pipeline and other transportation facilities, the marketing of
competitive fuels and other matters affecting the availability of a ready
market, such as fluctuating supply and demand. Generally, we sell all of our oil
and natural gas under short-term contracts that can be terminated with 30 days
notice, or less. None of our production was sold under long-term contracts with
specific purchasers during 2008. Consequently, we were able to market our oil
and natural gas production to the highest bidder each month.
At
management's discretion, we may participate in fixed-price contracts for a
portion of our physical natural gas production when attractive opportunities are
available. From time to time, we enter into derivative contracts to reduce
exposure from price fluctuations and provide a more predictable cash flow
stream. All such derivatives call for financial settlement rather than physical
settlement. These derivatives are discussed further in
Item 7A
.
We
operate, drill and direct the drilling of oil and natural gas wells and also
participate in non-operated wells. As operator, we contract service companies,
such as drilling contractors, cementing contractors, etc., for specific tasks.
In some non-operated wells, we participate as an overriding royalty interest
owner.
During
2008, two purchasers of our oil and natural gas production and other natural gas
sales accounted for 51% and 13% of total revenues. We believe that alternative
purchasers could be found for such production at comparable prices if any of
these major customers declined to purchase future production.
During
2006, we purchased and refurbished a drilling rig that has the capacity to drill
vertical and horizontal wells up to a total measured depth of approximately
10,000 feet. It was placed into service in January 2007 and is currently being
used primarily on Glen Rose Porosity wells, for which we have a 100% WI. During
2007, we acquired two additional drilling rigs with lower depth ratings for use
on shallow Maverick Basin targets. One of these began drilling operations in
October 2007 for wells targeting the San Miguel, for which we have a 50% to 100%
WI, while the other is stacked. The rigs allowed us to reduce drilling costs on
our wells and facilitate our ability to meet our minimum drilling obligations.
In December 2008, we temporarily suspended operations on one of the rigs as a
result of our reduction in exploration activities.
The oil
and natural gas industry is highly competitive in the search for and development
of oil and natural gas reserves. We compete with a substantial number of major
integrated oil companies and other companies having significantly greater
financial resources and manpower than we do. These competitors, having greater
financial resources, have a greater ability to bear the economic risks inherent
in all phases of this industry. In addition, unlike us, many competitors produce
large volumes of crude oil that may be used in connection with their operations.
These companies also possess substantially larger technical staffs, which puts
us at a significant competitive disadvantage compared to others in the
industry.
GENERAL
REGULATIONS
Both
state and federal authorities regulate the extraction, production,
transportation, and sale of oil, gas, and minerals. The executive and
legislative branches of government at both the state and federal levels have
periodically considered proposals for promoting alternative fuels, energy
conservation, environmental protection, taxation of crude oil imports,
limitation of crude oil imports, as well as various other related programs. If
any proposals relating to the above subjects were to be enacted, we can not
predict what effect, if any, implementation of such proposals would have upon
our operations. A listing of the more significant current state and federal
statutory authority for regulation of our current operations and business are
provided below.
Federal
Regulatory Controls
Historically,
the transportation and sale of natural gas in interstate commerce have been
regulated by the Natural Gas Act of 1938 (the "NGA"), the Natural Gas Policy Act
of 1978 and associated regulations by the Federal Energy Regulatory Commission
("FERC"). The Natural Gas Wellhead Decontrol Act (the "Decontrol Act") removed,
as of January 1, 1993, all remaining federal price controls from natural gas
sold in "first sales." The FERC's jurisdiction over natural gas transportation
was unaffected by the Decontrol Act.
In 1992,
the FERC issued regulations requiring interstate pipelines to provide
transportation, separate or "unbundled," from the pipelines' sales of natural
gas (Order 636). This regulation fostered increased competition within all
phases of the natural gas industry. In December 1992, the FERC issued Order 547,
governing the issuance of blanket marketer sales certificates to all natural gas
sellers other than interstate pipelines, and applying to non-first sales that
remain subject to the FERC's NGA jurisdiction. These orders have fostered a
competitive market for natural gas by giving natural gas purchasers access to
multiple supply sources at market-driven prices. Order No. 547 increased
competition in markets in which we sell our natural gas.
The
natural gas industry historically has been very heavily regulated; therefore,
there is no assurance that the less stringent regulatory approach pursued by the
FERC and Congress will continue.
State
Regulatory Controls
In each
state where we conduct or contemplate conducting oil and natural gas activities,
these activities are subject to various regulations. The regulations relate to
the extraction, production, transportation and sale of oil and natural gas, the
issuance of drilling permits, the methods of developing new production, the
spacing and operation of wells, the conservation of oil and natural gas
reservoirs and other similar aspects of oil and natural gas operations. In
particular, the State of Texas (where we have conducted the majority of our oil
and natural gas operations to date) regulates the rate of daily production
allowable from both oil and natural gas wells on a market demand or conservation
basis. At the present time, no significant portion of our production has been
curtailed due to reduced allowables. We know of no proposed regulation that will
significantly impede our operations.
Environmental
Regulations
Our
extraction, production and drilling operations are subject to environmental
protection regulations established by federal, state, and local agencies. To our
knowledge, we believe that we are in compliance with the applicable
environmental regulations established by the agencies with jurisdiction over our
operations. While the applicable environmental regulations currently in effect
could have a material detrimental effect upon our earnings, capital
expenditures, or prospects for profitability, our competitors are subject to the
same regulations. Therefore, the existence of such regulations does not appear
to have any material effect upon our position with respect to our competitors.
The Texas Legislature has mandated a regulatory program for the management of
hazardous wastes generated during crude oil and natural gas exploration and
production, natural gas processing, oil and natural gas waste reclamation and
transportation operations. The disposal of these wastes, as governed by the
Railroad Commission of Texas, is becoming an increasing burden on the industry.
Our leases in North Dakota and South Dakota are subject to similar environmental
regulations including archeological and botanical surveys as most of the leases
are on federal and state lands.
Federal
and State Tax Considerations
Revenues
from oil and natural gas production are subject to taxation by the state in
which the production occurred. Prior to 2007, the majority of our revenues have
been from Texas with some additional revenues from North Dakota and Montana.
With the 2007 acquisition of Output, in addition to the above states, we also
receive revenues in Louisiana, Mississippi and Oklahoma with the majority
remaining from Texas. The following table shows the production and severance tax
rates received by these various states:
|
State
|
Oil
|
Natural Gas
|
|
Texas
|
4.6%
|
7.5%
|
|
Louisiana
|
12.5%
|
$0.288
per mcf
|
|
Mississippi
|
6.0%
|
6.0%
|
|
Montana
|
17.2%
|
17.2%
|
|
North
Dakota
|
9.0%
|
11.5%
|
|
Oklahoma
|
7.1%
|
7.1%
|
These
high percentage state taxes can have a significant impact upon the economic
viability of marginal wells that we may produce and require plugging of wells
sooner than would be necessary in a less arduous taxing
environment.
In 2007,
we had a federal tax benefit of $5.3 million resulting from an election to
expense intangible drilling costs. The Company elected to carry-back
its tax net operating loss, resulting in a recovery of taxes paid in prior
years.
ITEM
1A. RISK
FACTORS
Risks Related to Our
Business
We have
received an opinion from our independent registered public accounting firm which
casts doubt on our ability to continue as a going concern.
Our
independent registered public accounting firm has issued an opinion on our
consolidated financial statements that states that the consolidated financial
statements were prepared assuming we will continue as a going concern. The
opinion includes an explanatory paragraph indicating that our working capital
deficiency, non-compliance with our current ratio covenant under our bank credit
facilities and violation of a provision of the certificate of designation of the
Series D and Series E Convertible Preferred Stock, raise substantial doubt about
our ability to continue as a going concern. The "going concern" opinion may
adversely affect our ability to raise additional capital, and could have a
material adverse effect on our business, cash flow, financial condition, and
results of operations.
We
are in violation of the current ratio covenant under our bank credit facilities,
which could result in the acceleration of the amounts due under the bank credit
facilities and the demand of redemption rights under our Series D and Series E
Convertible Preferred Stock.
Our
current ratio as defined in our bank credit facilities was approximately 0.55 to
1 at year-end 2008 before reclassifications due to the covenant violation in
violation of the current ratio covenant of our bank credit facilities, which
requires a ratio of 1 to 1. In accordance with our bank credit facilities, our
lenders have the right to declare all or any part of the unpaid principal and
accrued interest under the bank credit facilities immediately due and payable.
In accordance with the Certificates of Designations, the holders of our
preferred stock have the right to demand redemption of their shares of preferred
stock, and the holder of 34,409 shares of Series D and 15,000 shares of Series E
preferred stock has demanded redemption of those shares. In accordance with
United States generally accepted accounting principles, all of our bank debt and
our remaining preferred stock, after the January 2009 conversions, has been
reclassified to current liabilities. While our lenders have not informed us of
intent to exercise their right to accelerate the payment schedule on the debt at
this time, we have no assurance that they will not elect to do so. In addition,
as a result of such default the lenders have terminated their commitments to
make additional loans and participate in the issuance of letters of credit under
the bank credit facilities.
If the
lenders demand immediate repayment of our outstanding borrowings under the bank
credit facilities, we do not currently have means to repay or refinance the
amounts that would be due. If we failed to repay the amounts due under the bank
credit facilities, the lenders could exercise their remedies under the bank
credit facilities, including foreclosing on substantially all our assets which
we pledged as collateral to secure our obligations under the bank credit
facilities. These circumstances could require us to seek relief through a filing
under the U.S. Bankruptcy Code.
Inadequate
liquidity will affect our ability to meet our short-term cash commitments and
could materially and adversely affect our business operations in the future and
require us to seek relief through a filing under the U.S. Bankruptcy
Code.
Our
efforts to improve our liquidity position will be challenging given the current
economic climate. Current economic fundamentals portray a negative outlook for
the oil and natural gas exploration and development business for at least a
significant portion of 2009 due to extremely low and volatile oil and natural
gas prices coupled with a global recession that is projected to be the longest
and most severe in the post war period. These economic conditions have resulted
in a decline in our revenues and available capital, and have caused us to
significantly decrease our drilling activities and operations. Moreover, the
full impact of many of the actions that we have taken to improve our liquidity
will not be realized until late 2009 at the earliest, even if they are
successfully implemented. As a result of our violation of the current ratio
covenant under our bank credit facilities, we do not have the ability to borrow
any additional amounts under our bank credit facilities. As a result of the
unprecedented volatility and disruption in the capital and credit markets, it is
unlikely that we will be able to obtain additional debt or equity financing in
the near term.
Significant
vendor obligations and our inability to pay our vendors on a timely basis may
have an adverse effect on our ability to secure their future
services.
As of
December 31, 2008, we had outstanding trade payables of $49.7 million, of which
approximately $4.1 million was 60 days or more past due. Failure to timely pay
vendors could result in liens filed against our properties or withdrawal of
trade credit provided by vendors, which would limit our availability to conduct
operations. Until our past due vendor obligations are fully satisfied and we
become current, there remains significant risk that these vendors will take
formal collection actions against us, pursue liens or other legal actions, or
potentially force us into involuntary bankruptcy. Additionally, our inability to
satisfy our vendor obligations on a timely basis may result in irreparable harm
to our relationships with them and their willingness to continue to do business
with us in the future, under terms that would be acceptable to us. We may be
required to make advance payments for services, and some critical and/or
uniquely qualified vendors may refuse to continue to do business with us, which
would worsen our liquidity challenges and potentially prevent us from meeting
our drilling and other operating obligations, and would result in material
adverse consequences to us.
Our
revolving credit facility has borrowing base restrictions, which could adversely
affect our operations.
Our
revolving credit facility limits the amounts we can borrow to certain borrowing
base amounts, determined by our lenders in their sole discretion, based upon,
among other things, our level of proved reserves and the projected revenues from
the oil and natural gas properties securing our loans. The agent, upon request
of lenders holding 66 2/3% of the revolving commitments, can unilaterally adjust
the borrowing base and, accordingly, the borrowings permitted to be
outstanding under the revolving credit facility, provided, that such request
cannot be made more than once in any six-month borrowing base calculation
period. Any increase in the borrowing base requires the consent of all
lenders.
Upon a
downward adjustment of the borrowing base, if borrowings in excess of the
revised borrowing base are outstanding, we could be forced to repay our
indebtedness in excess of the borrowing base under the revolving credit facility
if we do not have any substantial unpledged properties to pledge as additional
collateral. We may not have sufficient funds to make such repayments under our
bank credit facilities. Our lenders are scheduled to perform a redetermination
of our borrowing base in April or May 2009.
General
economic conditions could continue to adversely impact our results of
operations.
A lengthy
continuation of the slowdown in the U.S. economy or other economic conditions
affecting capital markets, such as declining oil and natural gas prices, failing
or weakened financial institutions, inflation, deteriorating business
conditions, interest rates and tax rates, will adversely affect our business and
financial condition further by reducing overall public confidence in our
financial strength, by causing us to curtail planned drilling activities or by
causing the oil field service sector of the domestic oil and natural gas
industry to reduce equipment, labor and services that would otherwise be
available to us.
Further,
some of our properties are operated by third parties whom we depend upon for
timely performance of drilling and other contractual obligations and, in some
cases, for distribution to us of our proportionate share of revenues from sales
of oil and natural gas the properties produce. If current economic conditions
adversely impact our third party operators, we are exposed to the risk that
drilling operations or revenue disbursements to us could be delayed. This
"trickle down" effect would significantly harm our business, cash flow,
financial condition and results of operations.
The
consequences of a recession include a lower level of economic activity and
uncertainty regarding energy prices and the capital and commodity markets. The
lower level of economic activity has resulted in a decline in energy
consumption, which combined with the significant decrease in oil and natural gas
prices, has materially adversely affected, and will continue to materially
adversely affect our revenue, liquidity and future growth. Instability in the
financial markets, as a result of recession or otherwise, also affects the cost
of capital and our ability to raise capital. These events increase our
vulnerability to further adverse general economic consequences and industry
conditions and the likelihood that our cash flows and financial condition will
be materially adversely affected as a result thereof.
In
addition, the instability and uncertainty in the financial markets have made it
difficult for us to follow through with drilling operations and other business
activities that we had planned on implementing before the current financial
crisis. Lower oil and natural gas prices, the financial markets and U.S. economy
have altered our ability and willingness to continue drilling operations at a
pace consistent with 2007 and 2008 levels.
The
economic situation could also have an impact on our customers and suppliers,
causing them to fail to meet their obligations to us, and on our operating
partners, resulting in delays in operations or failure to make required
payments. Additionally, the current economic situation could lead to reduced
demand for oil and natural gas or further reductions in the prices of oil and
natural gas, or both, which could have a negative impact on our financial
position, results of operations and cash flows. While the ultimate outcome and
impact of the current financial crisis cannot be predicted, it has had a
material adverse effect on our liquidity and financial condition.
Adverse
capital and credit market conditions will continue to significantly affect our
ability to meet liquidity needs, our access to capital, our cost of capital, and
our ability to conduct our business.
The
capital and credit markets have been experiencing significant volatility and
disruption for more than twelve months, which has exerted significant downward
pressure on availability of liquidity and credit capacity for substantially all
companies.
We need
liquidity to pay our operating expenses and interest on our debt. Without
sufficient liquidity, we will be forced to further curtail our operations and
sell additional assets, and our business will suffer. The principal sources of
our liquidity have been cash flow from our operations, bank borrowings and
proceeds from the sale of our debt and equity securities.
If cash
flow from operations, bank borrowings, and proceeds from any divestitures do not
satisfy our minimum needs, we may have to seek additional financing. The
availability of additional financing will depend on a variety of factors such as
market conditions, the general availability of credit, the volume of trading
activities, the overall availability of credit to the exploration and production
segment of the oil and natural gas industry, our credit ratings and credit
capacity, and the possibility that our lenders could develop a negative
perception of our long or short-term financial prospects if the level of our
business activity decreases significantly due to market downturns. Our internal
sources of liquidity are currently insufficient to meet our cash needs, and the
current state of the capital markets make it highly unlikely we will be able to
obtain additional financing in the capital and credit markets.
Given our
current liquidity situation and the disruptions, uncertainty and volatility in
the capital and credit markets, we have limited access to the capital required
to operate our business, most significantly our drilling operations. Such lack
of access to capital limits our ability to: replace, in a timely manner, oil and
natural gas reserves that we produce; meet maturing liabilities; generate
revenue to meet liquidity needs; and to maintain and grow our business. Our
results of operations, financial condition, cash flows and capital position
could be materially adversely affected by disruptions in the financial
markets.
Difficult
conditions in the global capital markets and the economy generally may
materially adversely affect our business and results of operations and we do not
expect these conditions to improve in the near future.
Our
results of operations are materially affected by conditions in the domestic
capital markets and the economy generally. The stress experienced by domestic
capital markets that began in the second half of 2008 has continued and
substantially increased during the first quarter of 2009. Recently, concerns
over deflation, energy costs, geopolitical issues, the availability and cost of
credit, the U.S. mortgage market and a declining real estate market in the U.S.
have contributed to increased volatility and diminished expectations for the
economy and the markets going forward. These factors, combined with volatile oil
and natural gas prices, declining business and consumer confidence and increased
unemployment, have precipitated an economic slowdown and recession. In addition,
capital markets have experienced decreased liquidity, increased price
volatility, credit downgrade events, and increased probabilities of default.
These events and the continuing market upheavals may have an adverse effect on
us because our liquidity and ability to fund our capital expenditures is
dependent in part upon our bank borrowings and access to the public capital
markets. Our revenues are likely to decline in such circumstances and our profit
margins could erode. In addition, in the event of extreme prolonged market
events, such as the global credit crisis, we could incur significant losses.
Even in the absence of a market downturn, we are exposed to substantial risk of
loss due to market volatility.
Factors
such as business investment, government spending, the volatility and strength of
the capital markets, and inflation all affect the business and economic
environment and, ultimately, the amount and profitability of our business. In an
economic downturn characterized by higher unemployment, lower corporate earnings
and lower business investment, our operations could be negatively impacted.
Purchasers of our oil and natural gas production may delay or be unable to make
timely payments to us. Adverse changes in the economy could affect earnings
negatively and could have a material adverse effect on our business, cash flow,
results of operations and financial condition.
The
current economic situation could also adversely affect the collectability of our
trade receivables and cause our oil and natural gas hedging arrangements to be
ineffective if our counterparties are unable to perform their obligations or
seek bankruptcy protection.
There
can be no assurance that actions of the U.S. Government, Federal Reserve and
other governmental and regulatory bodies for the purpose of stabilizing the
financial markets will achieve the intended effect.
In
response to the financial crises affecting the banking system and financial
markets and going concern threats to financial institutions, the Federal
Government, Federal Reserve and other governmental and regulatory bodies have
taken or are considering taking actions to address the financial crisis. We
cannot predict what impact such actions will have on the financial markets and
whether such actions will be successful. Such continued volatility could
materially and adversely affect our business, financial condition and results of
operations, or the trading price of our common stock. We cannot predict
whether or when such actions may occur, or what impact, if any, such actions
could have on our business, cash flow, results of operations and financial
condition.
The
impairment of financial institutions could adversely affect us by limiting the
availability of funds to us and the collectability of amounts owed to us under
derivative contracts.
We have
exposure to counterparties in the financial services industry, including
commercial banks that we rely upon for our credit facilities. In the event of
default of one or more of these counterparties, we may have exposure in that
they will not be able to fulfill their obligation to lend us funds under our
bank credit facilities, and the other lenders under such facilities are not
obligated to make up such shortfall. We use derivative instruments to mitigate
our risks in various circumstances. We enter into a variety of derivative
instruments, including swaps, puts and collars, to manage our exposure to
interest rates and oil and natural gas prices. See
Item 7A, "Quantitative and Qualitative Disclosures About Market Risk"
for further information regarding our derivative transactions. If our
counterparties fail or refuse to honor their obligations under these derivative
instruments, our hedges of the related risk will be ineffective. Such failure
could have a material adverse effect on our financial condition and results of
operations. We cannot provide assurance that our counterparties will honor their
obligations now or in the future. Insolvency, inability or unwillingness to make
payments required under terms of derivative instruments with us by any of our
counterparties could have a material adverse effect on our cash flow, financial
condition and results of operations. At the date of filing this Annual Report on
Form 10-K with the SEC, our counterparties included Bank of Montreal, Standard
Bank of London, and Amegy Bank.
Our
future success depends upon our ability to find, develop and acquire additional
oil and natural gas reserves that are economically recoverable.
The rate
of production from oil and natural gas properties declines as reserves are
depleted. As a result, we must locate and develop or acquire new oil and natural
gas reserves to replace those being depleted by production. We must do this even
during periods of low oil and natural gas prices when it is difficult to raise
the capital necessary to finance activities. Without successful exploration or
acquisition activities, our reserves and revenues will decline. We may not be
able to find and develop or acquire additional reserves at an acceptable cost or
have necessary financing for these activities. Due to our current liquidity
crisis, we have substantially reduced our activities related to the development
and acquisition of new oil and natural gas reserves.
Oil
and natural gas drilling is a high-risk activity.
Our
future success will depend on the success of our drilling programs. In addition
to the numerous operating risks described in more detail below, these activities
involve the risk that no commercially productive oil or natural gas reservoirs
will be discovered. In addition, we are often uncertain as to the future cost or
timing of drilling, completing and producing wells. Furthermore, our drilling
operations may be curtailed, delayed or canceled as a result of a variety of
factors, including, but not limited to, the following:
|
·
|
unexpected
drilling conditions;
|
|
·
|
pressure
or irregularities in formations;
|
|
·
|
equipment
failures or accidents;
|
|
·
|
adverse
weather conditions;
|
|
·
|
inability
to comply with governmental requirements;
and
|
|
·
|
shortages
or delays in the availability of drilling rigs and the delivery of
equipment.
|
If we
experience any of these problems, our ability to conduct operations could be
adversely affected.
Factors
beyond our control affect our ability to market oil and gas.
Our
ability to market oil and natural gas from our wells depends upon numerous
factors beyond our control. These factors include, but are not limited to, the
following:
|
·
|
the
level of domestic production and imports of oil and
gas;
|
|
·
|
the
volatility of both oil and natural gas
pricing;
|
|
·
|
the
proximity of natural gas production to natural gas
pipelines;
|
|
·
|
the
availability of pipeline capacity;
|
|
·
|
the
demand for oil and natural gas by utilities and other end
users;
|
|
·
|
the
availability of alternate fuel
sources;
|
|
·
|
the
effect of inclement weather;
|
|
·
|
state
and federal regulation of oil and natural gas marketing;
and
|
|
·
|
federal
regulation of natural gas sold or transported in interstate
commerce.
|
If these
factors were to change dramatically, our ability to market oil and natural gas
or obtain favorable prices for our oil and natural gas could be adversely
affected.
The
marketability of our production may be dependent upon transportation facilities
over which we have no control.
The
marketability of our production depends in part upon the availability,
proximity, and capacity of oil and natural gas pipelines, crude oil trucking,
natural gas gathering systems and processing facilities. Any significant change
in market factors affecting these infrastructure facilities could harm our
business. We transport our crude oil through pipelines and trucks that we do not
own, and we deliver our natural gas through gathering systems and pipelines that
we do not own. These facilities may not be available to us in the future or may
become inadequate for oil and natural gas volumes produced.
Oil and natural gas prices are
volatile. A substantial decrease in oil and natural gas prices occurred during
the fourth quarter of 2008, which impacted our results for that period. If the
recent low commodity price environment continues, it will have a material
adverse affect on our financial results.
Our
future financial condition, results of operations and the carrying value of our
oil and natural gas properties depend primarily upon the prices we receive for
our oil and natural gas production. Oil and natural gas prices historically have
been volatile and likely will continue to be volatile in the future, especially
given current world economic conditions. Current economic fundamentals portray a
negative outlook for the oil and natural gas exploration and development
business for at least a significant portion of 2009 due to extremely low and
volatile oil and natural gas prices coupled with a global
recession.
Our cash
flow from operations is highly dependent on the prices that we receive for oil
and natural gas. This price volatility also affects the amount of our cash flow
available for capital expenditures and our ability to borrow money or raise
additional capital. The amount we can borrow or have outstanding under our bank
credit facilities is subject to semi-annual redeterminations. Oil prices are
likely to affect us more than natural gas prices because approximately 56% of
our proved reserves are oil. The prices for oil and natural gas are subject to a
variety of additional factors that are beyond our control. These factors
include:
|
·
|
the
level of consumer demand for oil and natural
gas;
|
|
·
|
the
domestic and foreign supply of oil and natural
gas;
|
|
·
|
the
ability of the members of the Organization of Petroleum Exporting
Countries to agree to and maintain oil price and production
controls;
|
|
·
|
the
price of foreign oil and natural
gas;
|
|
·
|
domestic
governmental regulations and taxes;
|
|
·
|
the
price and availability of alternative fuel
sources;
|
|
·
|
weather
conditions, including hurricanes and tropical storms in and around the
Gulf of Mexico;
|
|
·
|
political
conditions in oil and natural gas producing regions, including the Middle
East; and
|
|
·
|
worldwide
economic conditions.
|
These
factors and the volatility of the energy markets generally make it extremely
difficult to predict future oil and natural gas price movements with any
certainty. Also, oil and natural gas prices do not necessarily move in tandem.
Declines in oil and natural gas prices would not only reduce revenue, but could
reduce the amount of oil and natural gas that we can produce economically and,
as a result, could have a material adverse effect upon our financial condition,
cash flows, results of operations, oil and natural gas reserves, the carrying
values of our oil and natural gas properties and the amounts we can borrow under
our bank credit facilities. If the oil and natural gas industry continues to
experience significantly lower prices, we may, among other things, be unable to
meet our financial obligations or make planned expenditures.
The
prices we receive for our production and sales may actually vary from prices
posted for national markets and exchanges for commodities. We sell our natural
gas based on the Houston Ship Channel index. We sell our oil on the Flint Hills
Resources postings. These prices may vary significantly from national markets
for these commodities such as NYMEX. While the disparity between these markets
is not significant today, these prices have diverged in the past and could
diverge in the future.
We
may not be able to replace our reserves or generate cash flows if we are unable
to raise capital.
In the
past, we have made substantial capital expenditures for the exploration,
exploitation, acquisition and production of oil and natural gas reserves.
Historically, we have financed these expenditures primarily with cash generated
by operations and proceeds from bank borrowings and equity financing. If the
recent reduction in our revenues continues or worsens, or if our borrowing base
decreases as a result of lower oil and natural gas prices, operating
difficulties or declines in reserves, or if our lenders refuse to make credit
available to us because of our current defaults under our bank credit
facilities, we will not have the capital necessary to maintain our current
operations or undertake or complete future drilling programs. Additional debt or
equity financing or cash generated by operations may not be, and under the
current capital and credit market conditions likely will not be, available to
meet these requirements.
We
face strong competition from other energy companies that may negatively affect
our ability to carry on operations.
We
operate in the highly competitive areas of oil and natural gas exploration,
development and production. Factors which affect our ability to successfully
compete in the marketplace include, but are not limited to, the
following:
|
·
|
the
availability of funds and information relating to a
property;
|
|
·
|
the
standards established by us for the minimum projected return on
investment;
|
|
·
|
the
availability of alternate fuel sources;
and
|
|
·
|
the
intermediate transportation of gas.
|
Our
competitors include major integrated oil companies, substantial independent
energy companies, affiliates of major interstate and intrastate pipelines, and
national and local natural gas gatherers. Many of these competitors possess
greater financial and other resources than we do.
The
inability to control associated entities could adversely affect our
business.
We do not
operate all of our properties on our own. We may enter into partnering
relationships with other entities over which we have little or no control.
Because we have limited or no control over such entities, we may not be able to
direct their operations, or ensure that their operations on our behalf will be
completed in a timely and efficient manner. Any delays in such business
entities' operations could adversely affect our operations.
There
are risks in acquiring producing properties.
We
constantly evaluate opportunities to acquire oil and natural gas properties and
frequently engage in bidding and negotiating for these acquisitions. If
successful in this process, we may alter or increase our capitalization through
the issuance of additional debt or equity securities, the sale of production
payments or other measures. Any change in capitalization affects our risk
profile.
A change
in capitalization, however, is not the only way acquisitions affect our risk
profile. Acquisitions may alter the nature of our business. This could occur
when the character of acquired properties is substantially different from our
existing properties in terms of operating or geologic
characteristics.
Operating
hazards may adversely affect our ability to conduct business.
Our
operations are subject to risks inherent in the oil and natural gas industry,
including, but not limited to, the following:
|
·
|
uncontrollable
flows of oil, natural gas or well
fluids;
|
|
·
|
other
environmental risks.
|
These
risks could result in substantial losses to us from injury and loss of life,
damage to and destruction of property and equipment, pollution and other
environmental damage and suspension of operations. Governmental regulations may
impose liability for pollution damage or result in the interruption or
termination of operations.
If
losses and liabilities from drilling and operating activities are not deemed
fully covered by our insurance policies, it could have a material adverse effect
on our financial condition and operations.
Although
we maintain several types of insurance to cover our operations, we may not be
able to maintain adequate insurance in the future at rates we consider
reasonable, or losses may exceed the maximum limits under our insurance
policies. If a significant event that is not fully insured or indemnified
occurs, it could materially and adversely affect our financial condition and
results of operations.
Compliance
with environmental and other government regulations could be costly and could
negatively impact production.
Our
operations are subject to numerous laws and regulations governing the discharge
of materials into the environment or otherwise relating to environmental
protection. Without limiting the generality of the foregoing, these laws and
regulations may:
|
·
|
require
the acquisition of a permit before drilling
commences;
|
|
·
|
restrict
the types, quantities and concentration of various substances that can be
released into the environment from drilling and production
activities;
|
|
·
|
limit
or prohibit drilling activities on certain lands lying within wilderness,
wetlands and other protected areas;
|
|
·
|
require
remedial measures to mitigate pollution from former operations, such as
plugging abandoned wells; and
|
|
·
|
impose
substantial liabilities for pollution resulting from our
operations.
|
The
recent trend toward stricter standards in environmental legislation and
regulation is likely to continue. The enactment of stricter legislation or the
adoption of stricter regulation could have a significant impact on our operating
costs, as well as on the oil and natural gas industry in
general.
Our
operations could result in liability for personal injuries, property damage, oil
spills, discharge of hazardous materials, remediation and clean-up costs and
other environmental damages. We could also be liable for environmental damages
caused by previous property owners. As a result, substantial liabilities to
third parties or governmental entities may be incurred which could have a
material adverse effect on our financial condition and results of operations. We
maintain insurance coverage for our operations, but we do not believe that
insurance coverage for environmental damages that occur over time or complete
coverage for sudden and accidental environmental damages is available at a
reasonable cost. Accordingly, we may be subject to liability or may lose the
privilege to continue exploration or production activities upon substantial
portions of our properties if certain environmental damages occur.
You
should not place undue reliance on reserve information because reserve
information represents estimates.
While
estimates of our oil and natural gas reserves, and future net cash flows
attributable to those reserves, were prepared by independent petroleum
engineers, there are numerous uncertainties inherent in estimating quantities of
proved reserves and cash flows from such reserves, including factors beyond our
control and the control of engineers. Reserve engineering is a subjective
process of estimating underground accumulations of oil and natural gas that can
not be measured in an exact manner. The accuracy of an estimate of quantities of
reserves, or of cash flows attributable to these reserves, is a function of many
factors, including, but not limited to, the following:
|
·
|
assumptions
regarding future oil and natural gas
prices;
|
|
·
|
estimates
of future production rates;
|
|
·
|
expenditures
for future development and exploitation activities;
and
|
|
·
|
engineering
and geological interpretation and
judgment.
|
Reserves
and future cash flows may also be subject to material downward or upward
revisions based upon production history, development and exploitation activities
and oil and natural gas prices. Actual future production, revenue, taxes,
development expenditures, operating expenses, quantities of recoverable reserves
and value of cash flows from those reserves may vary significantly from the
estimates. In addition, reserve engineers may make different estimates of
reserves and cash flows based on the same available data. For the reserve
calculations, oil was converted to natural gas equivalent at six mcf of natural
gas for one Bbl of oil. This ratio approximates the energy equivalency of
natural gas to oil on a Btu basis. However, it may not represent the relative
prices received from the sale of our oil and natural gas
production.
The
estimated quantities of proved reserves and the discounted present value of
future net cash flows attributable to those reserves included in this document
were prepared by independent petroleum engineers in accordance with the rules of
the SFAS No. 69 and the SEC. These estimates are not intended to represent the
fair market value of our reserves. The future net cash flows are based upon the
prices received on December 31 of each year.
During
2008, the SEC approved new rules related to the estimation of reserves. These
new rules are effective for fiscal years ending on or after December 31, 2009.
These rules change, among other things, the prices to be used for estimation of
reserves, from a year-end price to an average price for the prior 12 months, and
remove the prohibition against counting as reserves future production of oil or
natural gas related to unconventional reservoirs such as coal-bed methane, oil
sands and shales.
Loss
of executive officers or other key employees could adversely affect our
business.
Our
success is dependent upon the continued services and skills of our current
executive management and other key employees. The loss of services of any of
these key personnel could have a negative impact on our business because of such
personnel's skills and industry experience and the difficulty of promptly
finding qualified replacement personnel. The uncertainties resulting from the
recently announced strategic alternatives review could result in one or more of
our key employees choosing to find employment elsewhere.
Our
use of hedging arrangements could result in financial losses or reduce our
income.
We
sometimes engage in hedging arrangements to reduce our exposure to fluctuations
in the prices of oil and natural gas for a portion of our oil and natural gas
production. These hedging arrangements expose us to risk of financial loss in
some circumstances, including, without limitation, when:
|
·
|
production
is less than expected;
|
|
·
|
the
counterparty to the hedging contract defaults on our contract obligations;
or
|
|
·
|
there
is a change in the expected differential between the underlying price in
the hedging agreement and the actual prices
received.
|
In
addition, these hedging arrangements may limit the benefit we would otherwise
receive from increases in prices for oil and natural gas.
Acquisition
of entire businesses may be a component of our growth strategy; our failure to
complete future acquisitions successfully could reduce our earnings and slow our
growth.
We
completed a significant acquisition in 2007 and it is possible that we will
acquire additional entire businesses in the future. Potential risks involved in
the acquisition of such businesses include the inability to satisfy closing
conditions, continue to identify business entities for acquisition, the
inability to successfully integrate such businesses into our operations, and the
inability to make acquisitions on terms that we consider economically
acceptable. Furthermore, there is intense competition for acquisition
opportunities in our industry. Competition for acquisitions may increase the
cost of, or cause us to refrain from, completing acquisitions. Our strategy of
completing acquisitions is dependent upon, among other things, our ability to
obtain debt and equity financing and, in some cases, regulatory approvals. Our
ability to pursue our growth strategy may be hindered if we are not able to
obtain financing or regulatory approvals. Our ability to grow through
acquisitions and manage growth would require us to continue to invest in
operational, financial and management information systems and to attract,
retain, motivate and effectively manage our employees. The inability to
effectively manage the integration of acquisitions could reduce our focus on
subsequent acquisitions and current operations, which, in turn, could negatively
impact our earnings and growth. Our financial position and results of operations
may fluctuate significantly from period to period, based on whether or not
significant acquisitions are completed in particular periods.
Shortages
of oil field equipment, services and qualified personnel could reduce our cash
flow and adversely affect results of operations.
The
demand for qualified and experienced field personnel to drill wells and conduct
field operations, geologists, geophysicists, engineers and other professionals
in the oil and natural gas industry can fluctuate significantly, often in
correlation with oil and natural gas prices, causing periodic shortages.
Historically, there have been shortages of drilling rigs and other
oil field equipment as demand for rigs and equipment has increased along
with the number of wells being drilled. These factors also cause significant
increases in costs for equipment, services and personnel. Higher oil and natural
gas prices generally stimulate demand and result in increased prices for
drilling rigs, crews and associated supplies, equipment and services. It is
beyond our control and ability to predict whether these conditions will exist in
the future and, if so, what their timing and duration will be. These types of
shortages or price increases could significantly decrease our profit margin,
cash flow and operating results, or restrict our ability to drill the wells and
conduct the operations that we currently have planned and budgeted. During times
of reduced demand, costs for equipment and services often decline more slowly
than they increased during times of high demand.
Risks Related to Our Common
Stock
We
may issue additional capital stock to raise capital, or as partial consideration
in acquisitions, which would dilute current investors.
Our board
of directors may determine in the future that we need to obtain additional
capital through the issuance of additional shares of preferred stock, common
stock or other securities. Further, we may issue additional shares of our
capital stock to sellers in mergers or acquisitions as purchase consideration.
Any such issuance will dilute the ownership percentage of the current holders of
our common stock.
We issued
convertible preferred stock, in private placements to raise additional capital
during late 2007 and early 2008. For further information about these
convertible shares, see the discussion in
Note G
to our
Consolidated Financial Statements. Further, a portion of the consideration for
our April 2007 acquisition of Output Exploration, LLC was comprised of shares of
our common stock.
Pursuant
to our Restated Certificate of Incorporation, our board of directors has the
authority to issue additional shares of common stock without approval of our
stockholders, subject to applicable stock exchange requirements.
Our
Restated Certificate of Incorporation permits our Board of Directors to issue
preferred stock with rights greater than our common stock.
Our
Restated Certificate of Incorporation authorizes our board of directors to issue
one or more series of preferred stock and set the terms of the preferred stock
without seeking any further approval from our stockholders. Any preferred stock
that is issued may rank ahead of our common stock for dividend priority and
liquidation premiums and may have greater voting rights, and have other
preferences, to our common stock. In 2007 and 2008, we issued a total of 88,909
shares of convertible preferred stock with an aggregate stated value of $88.9
million. In October 2008, preferred shares with an aggregate value of $12.0
million were converted into approximately 1.1 million shares of our common
stock, including make-whole shares related to preferred dividends. In January
2009, preferred shares with an aggregate value of $10.0 million were converted
into approximately 1.5 million shares of our common stock, including make-whole
shares related to preferred dividends. The remaining 66,909 shares of
convertible preferred stock are convertible into approximately 4.4 million
shares of our common stock, excluding the potential issuance of make-whole
shares related to unpaid dividends if converted within three years of
issuance.
Under the
terms of our Certificate of Designations, Preferences and Rights of Series D
Convertible Preferred Stock and Certificate of Designations, Preferences and
Rights of Series E Convertible Preferred Stock (collectively, the "Certificates
of Designations"), the default under the bank credit facilities results in the
holders of the Series D and Series E Convertible Preferred Stock having a right
to demand that we redeem the preferred stock at the premium redemption price set
forth in the Certificates of Designations. However, under the terms of the
Certificates of Designations our obligation to pay the redemption price of any
preferred stock demanded to be redeemed is suspended until the earlier of (i)
October 31, 2012 or (ii) the date that all of our obligations under the bank
credit facilities have been satisfied. Under the terms of the Certificates of
Designations, the Company is obligated to pay interest at a rate of 1.5% per
month in respect of each unredeemed preferred share until paid in full. On March
9, 2009, a holder of preferred stock demanded redemption of 34,409 shares of
Series D Convertible Preferred Stock and 15,000 shares of Series E Convertible
Preferred Stock. Generally, holders of our preferred stock are entitled to
receive dividends, payable quarterly, at the rate of 6.5% and 6.0% per annum for
Series D and Series E, respectively. In connection with our breach of the
current ratio in our bank credit facilities, the dividend rate is increased to
12% per annum for both the Series D and Series E Preferred Stock until such time
as the breach of the current ratio covenant is cured.
The
exercise of stock options would result in dilution of our common
stock.
To the
extent options to purchase common stock under our stock incentive plans are
exercised, holders of our common stock will be diluted. As of March 13, 2009,
there were outstanding under our 2005 Stock Incentive Plan options to purchase
an aggregate 300,000 shares of our common stock. None of these options are
currently exercisable, however approximately 100,000 become exercisable in
December 2009.
Instituted
in 2000, our Rights Plan and certain provisions in our Restated Certificate of
Incorporation may inhibit a takeover of the Company.
|
·
|
Our
Rights Plan and certain provisions in our Restated Certificate of
Incorporation could have the effect of discouraging a third party from
making a tender offer or otherwise attempting to obtain control of the
Company.
|
|
·
|
Our
Rights Plan, commonly referred to as a "poison pill," provides that when
any person or group acquires beneficial ownership of 15% or more of
Company common stock, or commences a tender offer that would result in
beneficial ownership of 15% or more of such stock, holders of rights under
the Rights Plan will be entitled to purchase, at the Right's then current
exercise price, shares of our common stock having a value of twice the
Right's exercise price.
|
|
·
|
Pursuant
to our Restated Certificate of Incorporation, our Board of Directors has
the authority to issue preferred stock with voting or other rights or
preferences that could impede the success of any attempt to effect a
change in control or takeover of the
Company.
|
|
·
|
Our
Restated Certificate of Incorporation provides that our Board of Directors
will be divided into three classes of approximately equal numbers of
directors, with the term of office of one class expiring each year over a
three-year period. Classification of directors has the effect of making it
more difficult for stockholders to change the composition of our
Board.
|
Sales
of substantial amounts of our common stock may adversely affect our stock price
and make future offerings to raise more capital difficult.
Sales of
a large number of shares of our common stock in the market or the perception
that sales may occur could adversely affect the trading price of our common
stock. We may issue restricted securities or register additional shares of
common stock in the future for our use in connection with future acquisitions.
Except for volume limitations and certain other regulatory requirements
applicable to affiliates, such shares may be freely tradable unless we
contractually restrict their resale.
The
availability for sale, or actual sale, of the shares of common stock eligible
for future sale could adversely affect the market price of our common
stock.
We
do not expect to pay dividends on our common stock.
We have
not paid, nor do we expect to pay any cash dividends with respect to our common
stock in the foreseeable future. We intend to retain any earnings for use in our
business.
ITEM
1B. UNRESOLVED
STAFF COMMENTS
None.
ITEM
2. PROPERTIES
PHYSICAL
PROPERTIES
Our
administrative offices are located at 777 E. Sonterra Blvd., Suite 350, San
Antonio, Texas. These offices, consisting of approximately 25,400 square feet,
are leased through March 2014 at $0.6 million per year. Additionally, we have an
office in the Houston area, consisting of about 6,600 square feet that is leased
through August 2012 at $0.1 million per year.
All our
oil and natural gas properties, reserves, and activities are located onshore in
the continental United States; except for one property acquired with the Output
acquisition in 2007 that is located offshore in shallow federal waters of the
Gulf of Mexico. There are no quantities of oil or natural gas subject to
long-term supply or similar agreements with foreign government
authorities.
PROVED
RESERVES, FUTURE NET REVENUE AND
PRESENT
VALUE OF ESTIMATED FUTURE NET REVENUES
The
following unaudited information as of December 31, 2008, relates to our
estimated proved oil and natural gas reserves, estimated future net revenues
attributable to those reserves and the present value of the future net revenues
using a 10% discount factor ("PV-10 Value"). Our independent
reservoir-engineering firms, DeGolyer and MacNaughton, and William M. Cobb &
Associates, Inc., both Dallas-based worldwide petroleum-consulting firms, made
these estimates for 2005 through 2008. Estimates of proved developed oil and
natural gas reserves attributable to our interest at December 31, 2008, 2007 and
2006 are set forth in Notes to the Audited Consolidated Financial Statements
included in this Report.
The PV-10
Value is based on the estimated future net revenues, as prepared by our
independent reservoir engineering firms in accordance with SFAS No. 69.
Accordingly, the estimate is net of estimated production, future development
costs and future outflows related to asset retirement obligations, and does not
give effect to non-property related expenses, such as corporate general and
administrative expenses, debt service and future income tax expenses or to
depreciation, depletion and amortization. PV-10 Value generally differs from the
standardized measure by the present value of estimated income
taxes.
Oil
prices used in PV-10 Value are based on a December 31, 2008, Flint Hills West
Texas Intermediate posted price of $41.25 per barrel, adjusted by lease for
quality, transportation fees, regional price differentials and fixed price
contracts for the life of each respective contract. Natural gas prices used in
PV-10 Value are based on a December 31, 2008, Houston Ship Channel spot market
price of $5.245 per mmBtu, adjusted by lease for energy content, transportation
fees, and regional price differentials. Prices for hedges that are in place for
a portion of our 2009 through 2011 projected sales were also used to adjust
price expectations for those years. Oil and natural gas prices are held
constant. While the methodology is the same across companies, the reference
price and adjustments will vary between companies based on conditions in their
production areas.
PV-10
Value is considered a non-GAAP financial measure as defined in Item 10(e) of
Regulation S-K. Therefore, we are including the disclosures required by Item
10(e) of Regulation S-K with respect to PV-10 Value. These disclosures include
the following reconciliation to the most directly comparable GAAP financial
measure ("standardized measure"), and discussion of how management uses the
measure and why it is useful to investors.
We believe that the presentation of PV-10 Value is appropriate in our
filings and relevant and useful to our investors because:
|
·
|
it
presents the discounted future net cash flows attributable to our proved
reserves before corporate future income taxes,
and
|
|
·
|
it
is a useful measure for evaluating the relative monetary significance of
our oil and natural gas properties.
|
Further,
investors may utilize the measure as a basis for comparison of the relative size
and value of our reserves to other companies. We use this measure when assessing
the potential return on investment related to our oil and natural gas
properties. The PV-10 Value and the standardized measure of discounted future
net cash flows are not intended to represent the current market value of our
estimated oil and natural gas reserves.
|
Detail
of PV-10 and Reconciliation to Standardized Measure
|
|
PV-10
Value of Estimated Future Net Revenues, by year:
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less:
Present value of estimated income tax expense
|
|
|
|
|
|
|
Proved
oil and natural gas reserves are the estimated quantities of crude oil, natural
gas liquids and natural gas which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions. Proved developed
oil and natural gas reserves are reserves that we can expect to recover through
existing wells with existing equipment and operating methods. No reserve
estimates have been filed with or included in reports to any federal or foreign
government authority or agency, other than the SEC, since our latest Form 10-K
filing.
|
|
2008
|
2007
|
2006
|
|
Proved
Oil & Natural Gas Reserves at December 31,
|
|
Volumes
|
Mix
*
|
Volumes
|
Mix
*
|
Volumes
|
Mix
*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas equivalent (Bcfe) *
|
|
|
|
|
|
|
Oil
equivalent (mmBbls) *
|
|
|
|
|
|
|
* Oil
and natural gas were combined by converting oil to natural gas mcfe on the basis
of 1 barrel of oil = 6 mcfe of gas.
Reserves
declined 10.1 Bcfe, or 11.0%, from 91.8 Bcfe at year-end 2007. Annual production
for 2008 was 9.2 Bcfe. Reserves sold during 2008 were 3.8 Bcfe. Net reserve
additions for the year were 2.9 Bcfe in the face of downward revision in reserve
estimates due to the decline in oil and natural gas prices in late 2008. This
decline in prices was partially offset by commodity hedges in place on a portion
of our oil and natural gas production.
SALES VOLUMES
The
following table summarizes our net oil and natural gas production, average sales
prices, and average production costs per unit of production for the periods
indicated.
|
|
Years
Ended December 31,
|
|
|
|
2008
|
2007
|
2006
|
|
|
|
|
|
Sales
volumes in Barrels (Bbl)
|
|
|
|
Average
realized sales price per Bbl:
|
|
|
|
excluding
the impact of hedging
|
|
|
|
including
the impact of hedging
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
realized sales price per mcf:
|
|
|
|
excluding
the impact of hedging
|
|
|
|
including
the impact of hedging
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
cost per equivalent: (2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Oil
and natural gas were combined by converting oil to natural gas mcfe on the basis
of 1 barrel of oil = 6 mcfe of natural gas.
(2)
Production
costs include direct lease operations and production taxes.
With
respect to newly drilled wells, there can be no assurance that current
production levels can be sustained. Depending upon reservoir characteristics,
such levels of production could decline significantly.
PRODUCING
PROPERTIES - WELLS AND ACREAGE
The
following table sets forth our producing wells and developed acreage assignable
to those wells for the last three fiscal years:
|
|
Developed
|
|
Productive
Wells
|
|
|
|
Acreage
|
Oil
|
Gas
|
Total
|
|
Year
Ended
|
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
wells consist of producing wells and wells capable of production, including
shut-in wells and wells awaiting pipeline connections to commence deliveries and
oil wells awaiting connection to production facilities. Four of the above wells
have active multiple completions.
A "gross
well" or "gross acre" is a well or acre in which we hold a working interest. The
number of gross wells or gross acres is the total number of wells or acres in
which we own working interests. A "net well" or "net acre" is deemed to exist
when the sum of fractional ownership interest in gross wells or gross acres
equals one. The number of net wells or net acres is the sum of fractional
working interests owned in gross wells or gross acres expressed as whole numbers
and fractions thereof.
UNDEVELOPED
ACREAGE
As of
December 31, 2008, we owned, by lease or in fee, the following undeveloped
acres:
|
|
Gross
|
Net
|
Estimated
2009
|
|
United
States
|
|
Acres
|
Acres
|
Delay
Rentals
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ten Texas
leases totaling approximately 373,555 gross acres contain varying requirements
to drill a well every 90 to 180 days to keep undeveloped portions of the
respective leases in effect. We presently drill in accordance with the terms of
the leases and expect the leases to remain in force by virtue of production and
continuous development during the year. However, due to our current liquidity
problems, there can be no assurance that we can continue to hold leases by
development.
DRILLING ACTIVITY
The
following tables set forth our drilling activity for the last three
years:
|
|
2008
|
2007
|
2006
|
|
Completions
Summary:
|
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
Drilling
Well Completions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Drilling Wells Completed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Re-entries Completed
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See the next page for the footnotes to
this table.
(1)
The 2008
column includes four oil wells and one natural gas well spud in prior years and
completed in 2008, while the 2007 column includes two oil wells and two natural
gas wells spud in prior years and completed in 2007, and the 2006 column
includes three oil wells spud in prior years and completed in 2006.
(2)
The
dry holes in the 2006 column were wells spud in prior years.
(3)
Total
re-entries begun but not completed by year were: 2008 -- 10, 2007 -- 13,
2006 -- 3.
|
|
2008
|
2007
|
2006
|
|
In-Progress
Recap:
|
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
Beginning
In-Progress ("BIP")
|
|
|
|
|
|
|
|
|
New
re-entries begun not finished
|
|
|
|
|
|
|
|
|
New
wells spud not finished
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BIP
wells transferred to producing
|
|
|
|
|
|
|
|
|
BIP
wells completed as service wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BIP
wells transferred to others
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
Activity
:
During
2008, we participated in 96 wells, including new drilling of 73 (52.88 net)
wells and the re-entry of 23 (14.31 net) existing wells. We operated 57 (45.92
net) of the 73 newly drilled wells. Of the current-year drilling wells, 22
(13.61 net) remained in-progress at December 31, 2008. 12 of the re-entered
wells were put on production in 2008, while the remaining re-entries were
pending completion at December 31, 2008. During 2008, three (2.04 net) wells
that were in progress at the beginning of the year were transferred to others by
sale or exchange agreements. Additionally, we re-entered six beginning
in-progress wells during 2008 that remain in completion phase.
At
December 31, 2008, in-progress wells included 22 development wells spudded in
2008, four new developmental re-entries spudded in 2008, and 40 developmental
wells that remained in progress from the beginning of 2008. Most of the
in-progress wells are being scheduled for recompletion as horizontal wells or
into other zones.
2007
Activity:
During 2007, we participated in 87 wells, including
new drilling of 61 (46.81 net) wells and the re-entry of 26 (8.05 net) existing
wells. We operated 43 (39.45 net) of the 61 newly drilled wells. Of the 87 wells
begun in 2007, 35 (27.32 net) remained in progress at December 31, 2007. Twelve
of the re-entered wells were placed on production as oil wells, one (0.02 net)
was placed on production as a natural gas well and 13 (10.88 net) wells were in
completion phase. Additionally, four (2.62) wells spudded during 2006 were
completed and put on production in 2007.
At
December 31, 2007, in-progress wells included 22 development wells spudded in
2007, 13 re-entries spudded in 2007, and 26 wells that remained in progress from
the beginning of 2007.
2006
Activity:
We participated in 58 wells, including new drilling
of 46 wells (41.47 net) and the re-entry of 12 (9.58 net) existing wells. We
operated 36 (gross and net) of the newly drilled wells. Of the current-year
drilling wells, 11 (9.50 net) remained in-progress at December 31,
2006. Six (5.45 net) of the re-entered wells were put on production
as oil wells, one is being used as a water injection well, and two (1.13 net)
are waiting to be plugged, while the remaining three (2.0 net) wells are in
completion phase.
At
December 31, 2006, in-progress wells included 11 development wells, two new
developmental re-entries, and one new exploratory re-entry, all spudded in 2006,
as well as 45 developmental wells that remained in progress from the beginning
of 2006.
MAVERICK
BASIN PLAYS
Eagle Ford
Shales:
The
Eagle Ford is a promising, gas-prone shale resource play that underlies our
entire 1 million gross acre Maverick Basin lease block. The formation
underlies a large portion of South Texas, including the Maverick
Basin. In addition to our partners, EnCana Oil & Gas (USA), Inc.
("EnCana"), Anadarko Petroleum Corporation and St. Mary Land & Exploration
Company, several additional well-known companies, such as ConocoPhillips,
Petrohawk and EOG, among others, have established acreage positions in the
region and are now drilling or making preparations to initiate activities in
this play.
During
2008, we entered into a farm-in agreement with Anadarko that called for the
drilling of two Eagle Ford wells in Phase I. We completed Phase I in 2008 and
have begun Phase II under this agreement, which calls for drilling
additional wells during 2009. To date, delineation activities have included
various horizontal drilling and completion innovations, progressing from
uncemented, open-hole, single-stage fracture stimulations to our latest well,
featuring a cemented liner completion with a 10-stage fracture stimulation test.
In tests conducted in early 2009, this well flowed at rates as high as 6 mmcfed,
including a high condensate content. Through February 2009, we have completed
one of the wells required to earn the additional interests in the Phase II of
this farm-in agreement. St. Mary Land & Exploration Company is also
participating with us under this agreement.
Overall
during 2008 we participated in four wells targeting the Eagle Ford formation. At
year end, one of these wells was producing natural gas, one well was producing
oil, one well was awaiting completion, and one well was drilling. Based on
delineation results to date, both Anadarko and St. Mary have indicated their
intent to accelerate drilling activities during 2009.
Pearsall Shale:
This over-pressured resource natural gas shale play underlies
approximately 819,000 gross acres of our Maverick Basin deep-rights holdings. We
participated in the drilling, completion and testing of our first vertical
Pearsall well under the EnCana agreement in the Maverick Basin during 2006,
which began producing natural gas during January 2007. This
data-gathering well was the first in a series targeting the natural gas resource
play in a joint venture (50% WI) with EnCana as operator. To date, delineation
activities have included vertical and horizontal drilling and various completion
innovations, progressing from uncemented, open hole, single stage fracture
stimulations to our latest well, featuring a cemented liner completion with a
9-stage fracture stimulation test.
We
completed Phase I of our modified agreement with EnCana, carrying them on three
wells by the end of July 2008, thus earning additional interests in the acreage
block. Based on the success of the three initial wells, we elected to
move to Phase II of the agreement, committing to drill four additional wells by
the end of October 2009 to further increase our interest in the play, and
through early March 2009, we have begun the first required well.
Overall
during 2008, we participated in a total of six wells targeting the Pearsall
formation. At year-end, two wells were producing natural gas, one well was
waiting for pipeline connection, two wells were awaiting completion, and one
well was completed as a monitor well. Based on delineation results to date, our
partners, EnCana, Anadarko and St Mary have indicated their intent to accelerate
drilling activities during 2009.
Glen Rose Oil:
During 2008, our working interest in much of our non-operated,
95,250-gross acre Comanche Ranch lease was 75.5%. We have a proprietary 3-D
seismic survey that covers the Comanche Ranch lease. We, along with our
partners, acquired and processed the entire 3-D survey several years ago,
identifying numerous Glen Rose prospects. While the first well found a
water-bearing porosity, the second well became the discovery well for the
Comanche Halsell (6500) field and tested at rates over 2,000 barrels of oil per
day ("BOPD") in 2002. That well targeted a prospect on the Comanche Ranch lease,
which contained evidence of multiple Glen Rose prospects stacked over a
previously unidentified structure. Initial drilling found no productive reefs,
but discovered a highly fractured porosity interval.
After the
first three years of development, production on the Comanche Ranch lease was
spread over a 20 square-mile area. Forty-degree gravity, low-sulfur oil is
consistent throughout the entire area, which contains no gas. Our engineering
staff completed extensive reviews of the porosity intervals and our oil and
water production profiles and determined that this is a strong water-drive
reservoir. Additionally, seismic was integrated with the Comanche Halsell field
production profile. The water, which is produced along with the oil, is disposed
of at surface locations or trucked to disposal wells.
Nine new
wells and four re-entries were drilled on the Comanche Ranch lease during 2008
with our operating partner. Additionally, during 2008 we drilled or re-entered
17 Glen Rose oil wells on the adjacent Cage Ranch lease, where we hold a 100%
WI. Of the combined 30 wells drilled or re-entered targeting the porosity zone,
23 were producing oil at year-end 2008, and seven were shut in pending further
evaluation. For comparison, we drilled or re-entered 14 Glen Rose oil wells
during 2007.
Glen Rose
oil sales for 2008 totaled 813,600 barrels of oil ("BO") up from 714,200 BO
during 2007. The combined number of wells drilled since the oil play's discovery
in February 2002 stands at [117] through year-end 2008. Cumulative Glen Rose
gross oil production since its discovery surpassed 6.1 million barrels of oil
through January 2009. The project remains profitable and economics should
improve as we better define the expansive play and perfect drilling techniques
used to maximize the recovery of oil in this strong water-drive formation. Net
proved reserves at December 31, 2008, for the Glen Rose oil porosity zone are
estimated at 1.4 million BO, equivalent to 8.4 Bcfe, compared with 1.6 million
(9.9 Bcfe) for the prior year. We believe that significant additional proved
reserves will be established in the future.
During
2007, we contracted with Schlumberger to conduct a comprehensive reservoir
optimization study that focused on multiple aspects of the GRP project,
including the establishment of higher reserve levels, higher recovery rates,
evaluating secondary recovery opportunities and overall operating efficiencies.
Their report was delivered in 2008 and our technical staff modified certain of
its procedures based on the study.
Georgetown:
During 2008, we spudded six new Georgetown wells and re-entered six
wells, as compared to three Georgetown wells drilled or re-entered in 2007. Of
the 12 Georgetown wells started in 2008, six wells are producing oil and one
well is producing gas, while four wells remain in completion and one well was
dry. Georgetown natural gas sales for 2008 totaled 75.3 mmcf, compared to 38.4
mmcf during 2007, while Georgetown oil sales increased to 73,800 BO from 14,300
BO in 2007. Based on this ongoing success, we have participated in
three Georgetown wells through February 2009. In order to conserve capital, we
entered into a joint venture with Millenium E&P Resource Fund I, LLC
("Millenium") on December 31, 2008, whereby we are carried for a 50% interest at
no cost to us.
We began
using seismic coherency processing to more accurately predict the location of
formation faults and fractures in this field in late 2003. The Georgetown is a
fractured reservoir, which makes it difficult to predict the type and quantity
of ultimate reserves for each well, as such reservoirs typically have hyperbolic
decline curves with high initial production rates that rapidly fall to lower,
sustained rates. Georgetown proved reserve estimates increased to 1.9 Bcfe from
0.7 Bcfe at year-end 2007.
San Miguel
Waterflood:
In 2002, we acquired the Pena Creek oil field in Dimmit
County, Texas, which included 94 producing oil wells, 94 injection wells and 28
shut-in wells. We completed a 3-D seismic survey covering the field and
surrounding acreage. We also completed an extensive geological, engineering and
3-D seismic review, including the review of historic well data acquired with the
property. These evaluations enabled us to identify bypassed infill San Miguel
oil reserves, establishing more than 120 potential infill locations to date,
with further potential to establish additional infill locations as warranted by
ongoing drilling results. We expect additional oil recovery from planned
revamping of injection well configuration.
During
2008, we began 11 infill wells targeting bypassed reserves and three wells not
in the waterflood zone. All of these 14 wells are producing oil at December
31, 2008. During 2007, we drilled 11 wells. San Miguel oil sales in 2008 were
77,800 BO, compared to 78,700 BO in 2007. Net proved reserves at year-end for
this field were estimated at 3.4 million barrels, equivalent to 20.6 Bcfe, down
slightly from 3.9 million barrels (23.2 Bcfe) at year-end 2007. The 10,000-gross
acre Pena Creek prospect is contiguous to our Comanche Ranch lease.
Glen Rose Gas:
In late 2001, we announced the start of a horizontal Glen Rose shoal
natural gas play on a portion of our Chittim and Paloma leases. Our geologists
analyzed a large carbonate shoal (or carbonate "sand" bar) located within the
Glen Rose interval. The Chittim 1-141, the first well completed in this program,
went on production in 2001. Pursuant to our agreement with AROC-Texas Inc.,
covering this portion of the Chittim lease, we drill and complete these
horizontal Glen Rose shoal wells and AROC operates them. Since 2001, we have
completed 32 horizontal Glen Rose natural gas wells, with one well awaiting
completion.
We did
not participate in Glen Rose shoal or reef wells during 2008, compared to six
wells in 2007. One of the 2007 reef wells was later recompleted to the
Georgetown formation. Glen Rose natural gas sales for 2008 totaled 0.7 Bcf,
compared to 0.8 Bcf during 2007. The field has produced more than 16.5 Bcfe
since horizontal drilling techniques were first applied in 2001. At December 31,
2008, net proved natural gas reserves for Glen Rose were estimated at 5.0 Bcfe,
compared to 7.0 Bcfe for the prior year.
Oil
Sands:
The San Miguel Oil Sands feature ("Oil Sands") is prospective
under approximately 83,500 gross acres of our existing Maverick Basin acreage.
Independent reservoir engineers and geologists have estimated that there are 7
to 10 billion BO in place basin wide. We have conducted three pilot projects
that have provided important information that could prove valuable when
favorable crude oil prices allow commercial-scale production at some future
date. Also, Conoco and Mobil did pilot projects on the San Miguel Oil Sands in
the late 1970's and early 1980's and achieved recoveries of over 50% with the
use of steam injection. The Oil Sands are similar to those found in Cold Lake
Field in Canada. In 2005 we entered into a Participation Agreement that has
resulted in a shared leasehold working interest with Newmex Energy (USA) Inc., a
wholly-owned subsidiary of Pearl Exploration and Production, Ltd. (TSX Venture:
"PXX") ("Pearl"). While we are the operator with a 50% WI, we are drawing on
Pearl's technical expertise with similar projects in Canada. The Participation
Agreement includes an Area of Mutual Interest that contains approximately 42,500
gross acres of our joint leasehold and calls for the drilling of three pilot
wells at no cost to us. In addition, we hold a 100% WI in approximately 41,000
contiguous acres over the deposit.
To date,
we have completed our initial, two-well cyclic steam pilot phase, having
mobilized the oil and established a preliminary, favorable WTI price
differential from area refiners. Based on continuing reservoir simulation
studies, we decided to convert this pilot to a Steam-Assisted Gravity Drainage
("SAGD") process by the addition of two horizontal wells. We used our recently
purchased shallow drilling rig to drill two horizontal wells in this conversion.
The SAGD technique is used extensively in Canada. This marks the first time that
a SAGD pilot has been applied to the San Miguel oil sands.
The SAGD
well pair was drilled between the existing cyclic steam wells, which were
converted to temperature-monitoring wells. Existing steam generation capacity
was doubled in 2008 by the addition of a second 25 mmBtu steam generator. The
SAGD project continued steam injection and initial oil production began during
fourth-quarter 2008. We discontinued the SAGD project in February 2009, after
obtaining valuable information to document the recovery rates and costs
associated with harvesting the heavy oil for future use.
We also
further utilized our new drilling rig to establish a second pilot during the
first half of 2008, featuring five to eight new horizontal/vertical wells
utilizing a modified Fracture-Assisted Steamflood Technology (FAST), a technique
proven by Conoco in years past. Two new 50 mmBtu steam generators were installed
in second-quarter 2008.
Due to
the sharp decline in crude oil prices, we shut-in the FAST project in December
2008 until the outlook for oil prices improves, and recorded an impairment
charge of approximately $11 million for this project.
Other
Plays:
During 2008, we drilled three wells to the Austin Chalk
formation, two of which are producing oil, while one was awaiting completion at
December 31, 2008. Three wells were also spud to the Austin Chalk formation
during 2007.
OTHER
AREAS
Former Output
Properties
:
As
described in the "Recent Developments" section of this Item, on April 2, 2007,
we closed on the purchase of Output Exploration LLC. The core of the Output
assets is in the East Texas Fort Trinidad Field and is prospective for the Glen
Rose, Buda, Austin Chalk, Eagle Ford/Woodbine and Bossier formations. Other
Output assets acquired include acreage in the Midcontinent and Gulf Coast
regions and shallow Gulf of Mexico waters. Certain of these assets were sold
during 2008.
TXCO
participated in a total of nine new wells and two re-entries on former Output
assets during 2008. Of the 11 total wells that we participated in three were in
Oklahoma, five were in Texas and three were in shallow waters off the Louisiana
coast. At December 31, 2008, three of these wells were producing, seven awaited
completion and one awaits plugging. Additionally, six wells that were in
progress at December 31, 2007, were completed during 2008 with five producing
natural gas and one producing oil. In 2007, we participated in a total of 12
wells on former Output assets. Our 2008 net sales for former Output properties
totaled 132,000 BO and 1.4 bcf, as compared to 143,600 BO and 1.2 bcf in
2007.
Marfa Basin:
The Marfa Basin is located approximately 200 miles northwest of our
Maverick Basin leases. It is an underexplored area along the Ouachita Overthrust
that is prospective for the Barnett and Woodford Shales. We acquired an interest
in 140,000 gross acres in the Marfa Basin in 2005, and in 2006 brought in
Continental Resources Inc. as our 50% partner. We re-entered one vertical well
targeting the Woodford shale during 2006, which tested gas. A fracture
stimulation procedure was performed on the well during 2007 and certain zones
were perforated in the wellbore during 2008.
Williston
Basin:
At December 31, 2008, we retained approximately 4,400 gross and
2,000 net acres in the Williston Basin. During 2008, we participated in the
drilling of one new well (2.77% WI) in the Red River formation, which is
producing oil. In 2007 we participated in one new and two re-entered oil wells
in this formation. Our 2008 net sales for the Williston Basin totaled 19,900 BO
and 18.3 mmcf, as compared to 19,600 BO and 26.6 mmcf in 2007.
GAS
GATHERING SYSTEM
We
acquired a gathering system in 2002 to enhance our infrastructure in the
Maverick Basin, which we expanded over the intervening years. At December 31,
2008, the system consisted of over 90 miles of natural gas pipeline, a
compressor station with three compressors and three dehydrators that allowed a
deliverable capacity of 35 mmcfd, of which one-third was utilized. The pipeline
begins approximately 12 miles north of Eagle Pass, Texas, in Maverick County,
and runs to Carrizo Springs, Texas, in Dimmit County, where it terminates. The
natural gas can be routed to five separate delivery points and either processed
or sold at multiple markets. No significant additions were made to the gathering
system since 2004.
This
natural gas gathering system transports our production to various markets. It
also transports production for other owners at a set rate per mmBtu. It sells
natural gas at several points along the system with a significant portion being
delivered to purchasers through the Enterprise/Gulf Terra Pipeline System, to
purchasers behind the Duke Three Rivers processing plant, or to a local
distribution customer in Piedras Negras, Mexico. The natural gas is processed
and the natural gas liquids are removed. The residue gas is then sold to various
purchasers. We receive a share of the liquids revenues. Natural gas pricing
fluctuations are reflected at the wellhead for our operated natural gas
properties. The following table summarizes our natural gas marketing sales
volumes and average sales prices per mmBtu for the periods indicated. There can
be no assurance that current access levels to third party pipelines and
processing facilities can be sustained.
|
|
Years
Ended December 31,
|
|
|
|
2008
|
2007
|
2006
|
Residue
gas and NGL sales volumes (mmBtu)
|
|
|
|
Average
sales price per mmBtu
|
|
|
|
In order
to enhance our liquidity, we sold all interests in the pipeline system effective
February 1, 2009, to Clear Springs Energy Company LLC, a Texas limited liability
company. We expect to continue to utilize this pipeline system to transport much
of our natural gas production.
ITEM
3. LEGAL
PROCEEDINGS
We were
involved in the following litigation as of March 13, 2009:
On March
4, 2009, Chieftain Exploration Company, Inc. and other individual plaintiffs
commenced a lawsuit against TXCO and EnCana in the 365
th
Judicial District Court, of Maverick County, Texas alleging a breach of the
terms of certain oil and natural gas leases covering an aggregate one-sixteenth
(1/16) mineral interest in two tracts of (i) 30,386.34 gross mineral acres, and
(ii) 24,979.67 gross mineral acres. Plaintiffs alleged that defendants refused
to sign releases of these oil and natural gas leases thereby enabling plaintiffs
to lease their mineral interests to other companies. Plaintiffs request damages
in excess of $1.7 million, pre-judgment and post-judgment interest, attorneys'
fees, and recovery of possession of the mineral interests they allege should
have been released. The suit is in early stages, but our review indicates that
the plaintiffs' claims are without merit as to our interests, and we intend to
vigorously defend this lawsuit.
On March
9, 2009, Cage Minerals, Ltd. et al. commenced a lawsuit against TXCO in the
150
th
Judicial District Court of Bexar County, Texas alleging that we have breached
the terms of an oil and natural gas lease (the "Cage Lease") covering their
fifteen sixteenths (15/16) mineral interest in 24,979.67 acres of land in
Maverick County, Texas, by failing to pay the full royalties which they allege
they were due on oil and natural gas production from 10 different horizontal
wells drilled across lease lines on pooled units formed partially out of lands
covered by the Cage Lease and partially out of lands covered by leases from
other mineral owners. Plaintiffs are requesting damages in excess of $2.3
million, pre-judgment and post-judgment interest, and attorneys' fees. By virtue
of written notice recently received from plaintiffs, we have reason to believe
that the plaintiffs may amend their lawsuit to request a termination of the Cage
Lease as a result of the alleged nonpayment of royalty interests. We believe
plaintiffs' claims and any request for termination of the Cage Lease are without
merit because royalties were paid correctly to the plaintiffs from the pooled
units in question.
On March
9, 2009, Winship Ranch, Ltd. commenced a lawsuit against TXCO in the 166
th
Judicial District Court of Bexar County, Texas. Plaintiff is the alleged owner
of the surface in 17,106 acres out of the lands covered by the Cage
Lease. Plaintiff claims that in our operations under the Cage Lease
we breached numerous surface use provisions contained in an addendum to such
lease. Plaintiff further alleges that we breached several provisions of a salt
water disposal agreement we entered into with plaintiff. Plaintiff's petition in
this lawsuit requests actual damages, pre-judgment and post-judgment interest,
and attorneys' fees. There is no allegation quantifying the requested damages.
No discovery has been conducted, and we are unable to determine at this time the
potential liability to which we may be exposed in this lawsuit.
We were
not involved in any other potentially material matters of litigation as of March
13, 2009.
ITEM
4. SUBMISSION
OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter
was submitted to a vote of our security holders during the fourth quarter of
2008.
PART
II
|
ITEM 5.
|
MARKET
FOR THE REGISTRANT'S COMMON EQUITY, RELATED
STOCKHOLDER
|
|
|
MATTERS AND
ISSUER PURCHASES OF EQUITY
SECURITIES
|
Our
common stock trades on the NASDAQ Global Select Market under the symbol "TXCO,"
having moved up from the NASDAQ Capital Market during 2006. The following table
sets forth the high and low prices per share of our common stock for the periods
indicated on the NASDAQ Global Select Market.
|
|
Range
of Sale Prices
|
|
Quarter
Ended:
|
|
High
|
|
Low
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of
March 13, 2009, there were 1,108 holders of record of our common stock and
our closing stock price was $0.59. Our transfer agent is the American Stock
Transfer & Trust Company, 59 Maiden Lane, New York, New York 10038. We have
not paid any cash dividends on our Common Stock in the past two years and do not
expect to do so in the foreseeable future. Our credit facilities with Bank of
Montreal prohibit the payment of dividends to common stockholders.
Comparative
Performance Graph:
The following graph compares the performance of the
Company's common stock for the five-year period commencing December 31, 2003, to
(i) the NASDAQ market composite index ("Market Index") and (ii) 48 active NASDAQ
exploration and production companies ("Peer Index"). The graph assumes that a
$100 investment was made in the Company's common stock and each index on
December 31, 2003, and that all dividends were reinvested. Also included are the
respective investment returns based upon the stock and index values as of the
end of each year during such five-year period. The information was provided by
Zacks Investment Research, Inc. of Chicago, Illinois ("Zacks"). The Peer Index
used includes all available NASDAQ stocks under SIC codes 1310-19 (companies
engaged in oil and natural gas exploration and production operations) actively
traded on NASDAQ during the comparative term. The list of comparative companies
is available to stockholders directly from Zacks or may be obtained at no cost
by contacting the Company and requesting the information.
|
Date
|
|
Company
Index
|
|
Market
Index
|
|
Peer
Index
|
|
|
|
|
|
|
|
|
|
12/31/2004
|
|
3.61
|
|
8.84
|
|
42.70
|
|
12/30/2005
|
|
2.24
|
|
2.13
|
|
45.40
|
|
12/29/2006
|
|
106.48
|
|
9.85
|
|
-3.00
|
|
12/31/2007
|
|
-9.59
|
|
8.44
|
|
14.56
|
|
12/31/2008
|
|
-87.64
|
|
-51.82
|
|
-49.91
|
The
foregoing performance graph is being furnished as part of this Report solely in
accordance with the requirement under Rule 14a-3(b)(9) to furnish our
stockholders with such information and, therefore, is not deemed to be filed, or
incorporated by reference into any filing, by the Company under the Securities
Act of 1933 or the Securities Exchange Act of 1934.
Equity
Compensation Plan Information:
The Equity Compensation Plan table
provides information as of December 31, 2008 with respect to shares of the
Company's common stock that may be issued under its existing equity compensation
plans:
|
Plan
category
(securities
in thousands)
|
|
Number
of securities
to
be issued upon
exercise
of
outstanding
options,
warrants
and rights
(a)
|
Weighted-average
exercise
price of
outstanding
options,
warrants
and rights
(b)
|
Number
of securities remaining
available
for future issuance
under
equity compensation
plans
(excluding securities
reflected
in column (a))
(c)
(1) (2)
|
Equity
compensation plans approved by security holders
|
|
|
|
Equity
compensation plans not approved by security holders
|
|
|
|
|
|
|
|
|
(1) All
2,396,613 shares may be issued in the form of restricted stock.
(2) Under
the current terms of the 2005 Stock Incentive Plan, the maximum number of shares
of the Company's common stock that are available for awards under this plan is
limited to 10% of the total number of the Company's issued and outstanding
shares of common stock.
Unregistered
Sales of Equity Securities:
No unregistered sales of equity
securities were made during the fourth quarter of 2008.
Issuer Purchases
of Equity Securities:
We did not reacquire any
of our own securities during the fourth quarter of 2008.
ITEM
6. SELECTED
FINANCIAL DATA
The
following selected financial information is derived from and qualified in its
entirety by our Audited Consolidated Financial Statements and the Notes thereto
as set forth in this Report commencing on
page
F-1
.
|
|
|
Years
Ended December 31
|
|
|
(In
thousands, except earnings per share data)
|
|
2008
|
2007(a)
|
2006
|
2005
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss)
income available to common stockholders
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
(loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
cash provided by operating activities
|
|
|
|
|
|
|
|
|
|
|
|
Net
cash provided (used) by investing activities
|
|
|
|
|
|
|
|
|
|
|
|
Net
cash provided (used) by financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
obligations
(
c
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
n/a - No
cash dividends have been paid.
(a) - The
growth in several factors listed for 2007 was largely due to the 2007
acquisition of Output Exploration, LLC. See the related discussion in the
"Recent Developments" section in Part I, Item 1.
(b) - The
"current liabilities" line for 2008 includes $153.0 million that has been
reclassified from long term debt, and $66.9 million that was reclassified from
stockholder's equity related to convertible preferred stock, on the Consolidated
Balance Sheet due to a current ratio covenant violation at December 31,
2008.
(c) - The
"long-term obligations" line for 2008 excludes $153.0 million that has been
reclassified to current liabilities on the Consolidated Balance Sheet due to a
current ratio covenant violation at December 31, 2008.
|
ITEM 7.
|
MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
|
OVERVIEW
The
following is a discussion of our financial condition and results of operations
("MD&A"). This discussion should be read in conjunction with our Financial
Statements and Notes thereto, beginning on page F-1 of this Report.
We are an
independent oil and natural gas enterprise with interests primarily in the
Maverick Basin in Southwest Texas, the Fort Trinidad field in East Texas, and
the Marfa Basin of West Texas, with a consistent record of long-term growth in
proved oil and natural gas reserves, leasehold acreage position, production and
cash flow through our established exploration and development programs. Our
business strategy is to build stockholder value primarily by acquiring
undeveloped as well as under-developed mineral interests, and internally
developing a multi-year drilling inventory through the use of advanced
technologies, such as 3-D seismic and horizontal drilling. We account for our
oil and natural gas operations under the successful efforts method of accounting
and trade our common stock on the Nasdaq Global Select Market
SM
under
the symbol "TXCO."
We
currently have two drilling rigs operating on our extensive 1 million gross
(653,360 net) acre position in the Maverick Basin. Completions in 2008 included
56 oil and 10 natural gas wells, which included 12 re-entries, while 22 wells
spud during the year remained in progress at year-end. The initial 2009 CAPEX
included plans for participation in 18 to 20 wells targeting the Glen Rose
Porosity, Georgetown, Pearsall, and Eagle Ford formations, as well as funds for
seismic development, leasehold and infrastructure. However, in light of our
current liquidity constraints, we may be unable to fulfill these
plans.
Due to
the number of promising prospects on our Maverick Basin acreage, as well as
higher oil and natural gas prices, drilling activity remained high during the
first nine-months of 2008. (For further discussion of this activity, see Item 1
Business,
"Principal Areas of Activity"
). However,
the significant decline in commodity prices during the fourth quarter resulted
in reduced activity for that period, as well as the first quarter of 2009.
Recognition of additional reserves for newly drilled wells requires a period of
sustained production, causing a delay between the expenditures and the recording
of reserves. The low commodity prices at year-end 2008 caused some
oil and natural gas deposits to become less than economic and, therefore, not
recognized as proved reserves under the applicable rules at this
time.
We reported net loss
available to common stockholders of $0.5 million, or $(0.01) per basic share and
diluted share, for the year ended December 31, 2008, compared to net income
available to common stockholders of $0.9 million, or $0.03 per basic share and
diluted share, for the prior year. Higher revenues were offset by increases in
impairment charges, depreciation, depletion and amortization. These factors are
discussed in the
Results of Operations
section
.
Liquidity
Issues/Going Concern:
During 2008, the Company engaged in its largest
capital expenditure program in its history. Our cost incurred in the development
and purchase of oil and natural gas properties increased from $117 million in
2007 to $182 million in 2008. While pursuing our drilling program, costs to
drill escalated throughout the summer followed by an unprecedented commodity
price collapse. As a result of the time lag between incurring drilling costs and
the resulting increase in revenues from new production, and deteriorating
economic conditions, we have experienced severe cash flow constraints. We have
experienced substantial difficulties in meeting our short-term cash needs,
particularly in relation to our vendor commitments. Substantially all of our
assets are pledged, and extreme volatility in energy prices and a deteriorating
global economy are creating great difficulties in the capital markets and have
greatly hindered our ability to raise debt and/or equity capital.
At
December 31, 2008, we had a working capital deficiency of $256.9 million,
including $153.0 million reclassified from long-term debt and $66.9 million
reclassified from preferred stock to current liabilities due to defaults under
those instruments which allow the lenders to demand immediate repayment under
our bank credit facilities and the holders of our preferred stock to demand
redemption. However, under the terms of the Certificates of Designations our
obligation to pay the redemption price of any preferred stock demanded to be
redeemed is suspended until the earlier of (i) October 31, 2012 or (ii) the date
that all of our obligations under the bank credit facilities have been
satisfied. We had $49.7 million in trade payables at December 31, 2008, of which
approximately $4.1 million was 60 days or more past due. Our failure to reach
accommodations with our vendors regarding the timing of payment in light of our
limited liquidity could result in liens filed against our properties or
withdrawal of trade credit, which in turn could limit our ability to conduct
operations on properties. While we continue to examine alternatives to improve
our liquidity and cash resources, including seeking additional short and
long-term capital through bank borrowings, the issuance of debt instruments, the
sale of common stock and preferred stock, the sale of non-strategic assets,
joint venture financing, and restructuring our existing obligations, our
inability to improve our liquidity and cash resources will cause us to
experience material adverse business consequences, including our inability to
continue in existence.
Our
accompanying financial statements have been prepared assuming we will continue
as a going concern. However, due to our deficiency in short-term and long-term
liquidity, our ability to continue as a going concern is dependent on our
success in generating additional sources of capital in the near future. We have
received a report from our independent registered public accounting firm on our
consolidated financial statements for the year ended December 31, 2008, in which
they have included an explanatory paragraph indicating that our working capital
deficiency, non-compliance with our current ratio covenant under our bank credit
facilities and violation of a provision of the certificate of designation of the
Series D and Series E Convertible Preferred Stock raise substantial doubt about
our ability to continue as a going concern. See "Capital Resources and
Liquidity" in Item 7 for further discussion of liquidity issues.
Market
Conditions:
Beginning in October 2008 and continuing into early 2009, oil
and natural gas prices declined significantly, and remain volatile. The decline
in commodity prices resulted in significantly reduced revenues, net income and
cash flows for the fourth quarter of 2008, and this reduction has continued in
the first quarter of 2009. If oil and natural gas prices remain at current
levels for any prolonged period of time or decline further, our financial
condition, operating results and cash flows, as well as access to debt and
equity capital, will be materially adversely affected. Additionally, perceptions
by oil and natural gas companies that oil and natural gas prices will be lower
long-term can similarly reduce or defer major expenditures, which will impact
our ability to attract partners for certain of our activities. See "Item 1A.
Risk Factors. Difficult conditions in the global capital markets and the economy
generally may materially adversely affect our business and results of operations
and we do not expect these conditions to improve in the near
future."
The
United States and foreign countries are currently experiencing volatility in
their financial and credit markets, which is having an adverse impact on the
ability of many companies', including us, to obtain credit. Historically, we
have relied on access to the debt and equity markets to finance our capital
needs. In addition, as a result of our violation of the current ratio covenant
under our bank credit facilities, our lenders are not permitting us to make any
additional borrowings under our bank credit facilities. See "
Bank Credit Facilities
" under "Capital Resources and
Liquidity" later in this Item for further discussion of our bank credit
facilities.
TXCO Response to
Liquidity Issues and Market Conditions:
We initiated a number of actions
beginning in the fourth quarter of 2008 to mitigate the impact on TXCO of
the unprecedented deterioration of market conditions. These actions
included:
|
|
·
|
a
reduction in drilling activity in light of projected reductions in cash
flows;
|
|
|
·
|
assessing
the prospect of selling our pipeline assets and certain non-core leasehold
interests;
|
|
|
·
|
obtaining
a credit facility to finance our drilling subsidiary,
and
|
|
|
·
|
evaluating
our derivative positions.
|
We took
the following actions during December 2008:
|
|
·
|
discontinued
our FAST oil sands pilot project,
|
|
|
·
|
temporarily
stacked one of our drilling rigs,
|
|
|
·
|
laid-off
approximately 20% of our work
force,
|
|
|
·
|
entered
into a $4 million credit facility secured by our drilling
rigs,
|
|
|
·
|
initiated
discussions with the agent for our revolving credit agreement to discuss
our financial condition, and
|
|
|
·
|
initiated
talks with prospective buyers regarding the sale of our pipeline
system.
|
Subsequent
to year-end, we:
|
|
·
|
closed
out certain of our derivative positions for cash and replaced them with
50% participating swaps, as further described in
Note
L
to our Consolidated Financial Statements included elsewhere herein
and in Item 7A "Quantitative and Qualitative Disclosures about Market
Risk",
|
|
|
·
|
closed
the sale of our pipeline assets effective February 1, 2009, to Clear
Springs Energy Company, LLC, a San Antonio based, Texas limited liability
company,
|
|
|
·
|
initiated
a strategic alternatives review (discussed below),
and
|
|
|
·
|
discontinued
our SAGD oil sands pilot project.
|
We also
reviewed the creditworthiness of the banks and financial institutions with which
we maintain our senior revolving credit facility, and which are counter-parties
to our derivative arrangements. We believe that these parties are weathering the
current financial crisis and can meet their commitments to us in the foreseeable
future.
Strategic
Alternatives Review:
On February 12, 2009, we announced that we retained
Goldman, Sachs & Co. as a financial advisor for a strategic alternatives
review designed to enhance stockholder value. All options are under
consideration, including the potential sale of leasehold interests or other
assets, a merger or sale of the Company. No formal decisions have been made and
no agreements have been reached at this time. There can be no assurance that any
particular alternative will be pursued or that any transaction will occur, or on
what terms. We do not expect to disclose developments from this review unless
our board of directors approves a definitive transaction.
2008 Acquisitions
& Disposals:
During 2008, we acquired additional interests in our
Fort Trinidad acreage in East Texas and sold 15 non-core properties in South
Texas. Both of the properties were part of the Output acquisition during 2007.
Neither transaction reflected a material acquisition or disposal.
2007
Acquisitions:
On April 2, 2007, we closed on the purchase of Output
Exploration, LLC ("Output"), a privately held, Houston-based exploration and
production firm, for $95.6 million. The consideration for the purchase was $91.6
million in cash, subject to certain adjustments, and $4.0 million of our common
stock. The transaction, the largest in our history, effectively doubled our
proved reserves and increased current oil and natural gas production by nearly
two thirds relative to pre-acquisition levels. The core of the Output
assets is in the East Texas Fort Trinidad Field and is prospective for the Glen
Rose, Buda, Austin Chalk, Eagle Ford/Woodbine and Bossier formations. Other
Output assets acquired include acreage in the Midcontinent and Gulf Coast
regions and shallow Gulf Coast waters.
Separately
in February 2007, we acquired an interest in primarily shallow horizons under
85,681 gross acres in an agreement with EnCana. In September 2007, we acquired
additional shallow horizons from EnCana under our Comanche, Cage Ranch and other
existing leases along with the option to earn Pearsall and deeper horizons.
Effective December 1, 2007, we acquired additional interests in our Fort
Trinidad area holdings from other working interest holders.
2007 Sales of
Certain Interests:
During the fourth quarter of 2007, we sold
our interests in two properties that had been acquired as part of the Output
acquisition, for approximately $6.0 million in cash.
2006 Sale of
Partial Interest:
In April 2006, we sold a 50% WI in 140,000 gross
acres in the Marfa Basin. The cash proceeds from this sale were used in our
capital expenditures program. The Marfa Basin is located in West Texas, along
the Ouachita Overthrust, and is prospective for natural gas from the Barnett and
Woodford shales.
Oil
and
Natural Gas
Reserves:
Estimated net proved reserves at year-end 2008 were 81.7 billion cubic
feet equivalent ("Bcfe"), a 10.1 Bcfe, or 11.0%, decrease from 91.8 Bcfe at
year-end 2007. Annual production for 2008 was 9.2 Bcfe. Reserves sold
during 2008 were 3.8 Bcfe. Net reserve additions for the year were 2.9 Bcfe in
the face of downward revision in reserve estimates due to the decline in oil and
natural gas prices in late 2008. The decline in price was partially offset by
commodity hedges in place on a portion of our oil and natural gas production. In
2008, our reserve replacement rate from the drill bit was 32%, while our
all-source reserve replacement rate was negative 9% due to the sale of certain
non-core properties. Our three-year average all source reserve replacement rate
was 286% for the 2006 through 2008 period. Positive cash flow provided from
operations totaled $100.6 million. Excluding changes in operating assets and
liabilities, operating cash flow was $78.8 million, a 59.8% increase from $49.3
million in the prior year primarily due to higher revenue for 2008 due to
increased production from drilling. The following table illustrates key features
of our continuous development over the four fiscal years presented.
|
|
Year
Ended December 31,
|
|
|
Development:
|
|
2008
|
|
2007
|
|
2006
|
|
2005
|
|
No.
of oil wells completed
|
|
|
|
|
|
|
|
|
No.
of natural gas wells completed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas reserve additions from drilling (mmcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
reserves additions from drilling (mBbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas equivalent sales (Bcfe)
|
|
|
|
|
|
|
|
|
Oil
equivalent sales (mBOE)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions
of previous estimates
|
|
|
|
|
|
|
|
|
Net
(sold) purchased in place
|
|
|
|
|
|
|
|
|
Total
change in reserves (Bcfe)
(1)
|
|
|
|
|
|
|
|
|
Reserve
replacement rate
(2)
|
|
|
|
|
|
|
|
|
|
|
32%
|
|
308%
|
|
135%
|
|
|
|
Drill
bit less sold reserves, plus purchased reserves (all
sources)
|
(9)%
|
|
731%
|
|
135%
|
|
|
|
Non-developed
Texas gross acreage leased
|
|
|
|
|
|
|
|
|
Non-developed
Oklahoma & Louisiana acreage leased
|
|
|
|
|
|
|
|
|
Non-developed
Williston Basin acreage leased
|
-
|
|
-
|
|
82,761
|
|
|
|
See the next page for the footnotes to
this table.
(1)
Make-up of
total proved developed reserves at year-end 2008: 56% oil, 44% natural
gas.
(2)
The reserve
replacement ratio is calculated by dividing proved reserve additions, which
includes extensions and discoveries, revisions to previous estimates and
reserves purchased, as the numerator, by the sales volumes for the year as the
denominator. For the drill bit only ratio, any purchased reserves are excluded
from the numerator. See discussion regarding risk factors included in
Part I, Item 1A of this Form 10-K
. See the discussion below
regarding how management uses this information and potential time horizons for
realization of these reserves.
Reserve
Replacement
:
Historically, we have added proved reserves through both drilling and
acquisition activities. We believe we will generally add reserves each year,
however, external factors beyond our control, such as governmental regulations
and commodity market factors, could limit our ability to drill wells and acquire
proved properties in the future. The depressed commodity prices at year-end 2008
resulted in fewer reserves being recognized due to the requirement to use
December 31 prices for these calculations. The SEC has issued new regulations
governing the calculation of reserves that are effective for annual periods
ending on or after December 31, 2009. We calculate and analyze reserve
replacement ratios to use as benchmarks against our competitors. Oil and natural
gas companies are judged by their management and the investing public by their
effectiveness in replacing annual production, hence the need for these ratios.
The ratios are limited in use by the inherent uncertainties in the reserve
estimation process and other factors. Our reserve additions for each year are
estimates. Reserve volumes can change over time, and therefore can not be
absolutely known or verified until all volumes have been produced and a
cumulative production total for a well or field can be calculated. Many factors
will impact the ability to access these reserves, such as availability of
capital, new and existing government regulations, competition within the
industry, the requirement of new or upgraded infrastructure at the production
site, and technological advances. See
"Risk Factors" (Part I,
Item 1A)
for further discussion of risks and uncertainties related to
reserves.
The
reserve report prepared by independent reservoir engineers and used for both the
PV-10 Value and the standardized measure indicates the last year of production
is estimated as 2095. However, as shown in the
table in Item
2
of this Form 10-K, we expect to realize approximately 57.0% of that
production by year-end 2013.
CAPITAL
RESOURCES AND LIQUIDITY
Liquidity
is a measure of ability to access cash. We primarily need cash for exploration,
development and acquisitions of oil and natural gas properties, payment of
contractual obligations, redemption of preferred stock, payment of preferred
stock dividends and working capital funding. At December 31, 2008, we had a
working capital deficiency of $256.9 million, including $153.0 million
reclassified from long-term debt and $66.9 million reclassified from preferred
stock. We had $49.7 million in trade payables at December 31, 2008 , which if
not timely paid could result in liens filed against the Company's properties or
withdrawal of trade credit provided by vendors, which in turn could limit the
Company's availability to conduct operations on its properties.
Our
accompanying financial statements have been prepared assuming we will continue
as a going concern; however, due to our deficiency in short-term and long-term
liquidity, our ability to continue as a going concern is dependent on our
success in generating additional sources of capital in the near future. We have
received a report from our independent registered certified public accounting
firm on our consolidated financial statements for the year ended December 31,
2008, in which they have included an explanatory paragraph indicating that our
working capital deficiency, non-compliance with our current ratio covenant under
our bank credit facilities and violation of a provision of the certificate of
designation of the Series D and Series E Convertible Preferred Stock raise
substantial doubt about our ability to continue as a going concern.
We have
historically addressed our short and long-term liquidity requirements through
cash provided by operating activities, the issuance of debt and equity
securities when market conditions permit, sale of non-strategic assets, and our
bank
credit facilities
. The prices for future oil
and natural gas production and the level of production have significant impacts
on operating cash flows and can not be predicted with any degree of
certainty.
We
continue to examine our sources of short and long-term capital, including
alternative sources of bank borrowings, the issuance of debt instruments, the
sale of common stock and preferred stock, the sales of non-strategic assets, and
joint venture financing. Availability of these sources of capital and,
therefore, our ability to execute our operating strategy will depend upon a
number of factors, some of which are beyond our control. Future cash flows are
subject to a number of variables including the level of production and oil and
natural gas prices. No assurances can be made that operations and other capital
resources will provide cash in sufficient amounts to maintain our operations or
desired levels of capital expenditures. Actual levels of capital expenditures
may vary significantly due to a variety of factors, including, but not limited
to, availability of capital, vendor relations, drilling results, product pricing
and future acquisition and divestitures of properties. Our internal sources of
liquidity are currently insufficient to meet our cash needs, and the current
state of the capital markets make it highly unlikely we will be able to obtain
additional financing in the capital and credit markets. Our inability to raise
capital to fund our operations will cause us to experience material adverse
business consequences, including our inability to continue in
existence.
In
February 2009, we announced the commencement of a strategic alternatives review
and that we are in violation of our current ratio covenant under our bank credit
facilities. We are in discussions with the lenders and have requested a waiver
whereby they will refrain from exercising their right, as a result of the
violation, to require the immediate repayment of our debt, although there can be
no assurance that such discussions will be successful or that our lenders will
not demand immediate repayment of our debt. As a result of such covenant
violation, we do not currently have the ability to borrow any additional amounts
under our bank credit facilities. If the lenders demand immediate repayment of
our outstanding borrowings under the bank credit facilities, we do not currently
have means to repay or refinance the amounts that would be due. If we failed to
repay the amounts due under the bank credit facilities, the lenders could
exercise their remedies under the bank credit facilities, including foreclosing
on substantially all our assets which we pledged as collateral to secure our
obligations under the bank credit facilities. These circumstances could require
us to seek relief through a filing under the U.S. Bankruptcy Code.
Bank Credit Facilities
In
connection with our acquisition of Output in April 2007, we replaced our credit
facility with Guaranty Bank with two new facilities with the Bank of Montreal,
as agent. Both of these facilities were amended and restated in July 2007, as
described below. As disclosed in our Form 8-K filed with the SEC on February 27,
2009, we are in violation of the current ratio covenant under these agreements.
As a result of that violation we have classified all outstanding balances under
these agreements as current liabilities on the Consolidated Balance Sheet as of
December 31, 2008.
Senior Credit
Agreement
--
At
December 31, 2008, we had a $125 million senior revolving credit facility with
the Bank of Montreal (the "SCA"). The SCA was entered into in April 2007,
amended in July 2007, and expires in April 2011.
At
December 31, 2008, the borrowing base was $55 million, $50 million was
outstanding at a weighted average interest rate of 4.0% and the unused borrowing
base was $5 million. The SCA is secured by a first-priority security interest in
substantially all of TXCO's and certain of its subsidiaries' assets, including
proved oil and natural gas reserves and in the equity interests of such
subsidiaries. In addition, TXCO's obligations under the SCA are guaranteed by
these certain subsidiaries. As of March 13, 2009, the balance outstanding under
the SCA was $50.0 million, with a weighted average interest rate of 4.00%, using
the base rate option. Our lenders are scheduled to perform a redetermination of
our borrowing base in April or May 2009.
Loans
under the SCA are subject to floating rates of interest based on (1) the
total amount outstanding under the SCA in relation to the borrowing base and
(2) whether the loan is a LIBOR loan or a base rate loan. LIBOR loans bear
interest at the LIBOR rate (for the applicable 1-, 2-, 3- or 6-month maturity
chosen by TXCO) plus the applicable margin, and base rate loans bear interest at
the base rate plus the applicable margin. The applicable margin varies with the
ratio of total outstanding to the borrowing base. For base rate loans it ranges
from zero to 100 basis points and for LIBOR rate loans it ranges from 150 to 250
basis points. The SCA allows the lenders to increase the interest rate by 200
basis points at any time we are in default under the SCA.
Under the
SCA, we are required to pay a commitment fee on the difference between amounts
available under the borrowing base and amounts actually borrowed. The commitment
fee is (1) 0.375%, so long as the ratio of amounts outstanding under the SCA to
the borrowing base is less than 30%, and (2) 0.50%, in the event such ratio is
30% or greater. Borrowings under the SCA may be repaid and reborrowed from time
to time without penalty.
Term Loan
Agreement
--
At
December 31, 2008, we had a $100 million, five-year term loan facility with Bank
of Montreal (the "TLA") and certain other financial institutions party thereto
with a current interest rate of 5.9375%. The TLA is secured by a second-priority
security interest in substantially all of TXCO's and certain of its
subsidiaries' assets, including proved oil and natural gas reserves and in the
equity interests of such subsidiaries. Loans under the TLA are subject to
floating rates of interest equal to, at TXCO's option, the LIBOR rate plus 4.50%
or the base rate plus 3.50%. The "LIBOR rate" and the base rate are calculated
in the same manner as under the SCA. See additional discussion regarding the
interest rate swap in Item 7A "Quantitative and Qualitative Disclosures about
Market Risk" and
Note L
to our Consolidated Financial
Statements included elsewhere herein. The TLA allows the lenders to increase the
interest rate by 200 basis points at any time we are in default under the
TLA.
Borrowings
under the TLA may be prepaid (but not reborrowed). However, no prepayments are
permitted if the ratio of the total amount outstanding under the SCA to the
borrowing base thereunder exceeds 75% or if any default exists
thereunder.
Covenants Under Bank Credit
Facilities
-- Both the SCA and the TLA contain certain restrictive
covenants, as defined in the agreements, which, among other things, limit the
incurrence of additional debt, investments, liens, dividends, redemptions of
capital stock, prepayments of indebtedness, asset dispositions, mergers and
consolidations, transactions with affiliates, derivative contracts, sale
leasebacks and other matters customarily restricted in credit agreements. The
amended SCA and TLA require TXCO and its subsidiaries to meet a maximum
consolidated leverage ratio of 3.00 to 1.00, a minimum current assets to current
liabilities ratio of 1.00 to 1.00 ("Current Ratio"), a minimum interest coverage
ratio of 2.00 to 1.00 and a minimum net present value to consolidated total debt
ratio of 1.50 to 1.00. The ratios are calculated on a quarterly basis and
include certain adjustments based on the definitions in the agreements. We were
in compliance with all such covenants at December 31, 2008, except the Current
Ratio covenant. At that date, our Current Ratio as defined in the agreement was
0.55 to 1 before reclassifications due to the covenant violation. Both
agreements also contain customary events of default. If an event of default
occurs and is continuing, lenders may require Bank of Montreal to declare all
amounts outstanding under the SCA and TLA to be immediately due and payable. To
date, such amounts have not been declared immediately due and payable. However,
our lenders under the SCA and TLA are not permitting us to make additional
borrowings under the SCA and TLA.
As a
result of the Current Ratio covenant violation, all borrowings under the SCA and
TLA have been classified as current liabilities in our Consolidated Balance
Sheet as of December 31, 2008. We are continuing discussions with the lenders
regarding a waiver of the Current Ratio covenant and other arrangements whereby
the lenders would refrain from exercising their rights under the bank credit
facilities as a result of the above mentioned default. There can be no assurance
that we will be able to obtain a waiver or obtain other relief from the
lenders.
Drilling Rig
Financing
--
At
December 31, 2008, we had a $4.0 million senior revolving credit facility with
Western National Bank (the "Rig Loan"). The Rig Loan was entered into in
December 2008. At December 31, 2008, the borrowing base was $4.0 million, all of
which was outstanding at a weighted average interest rate of 4.25%. The Rig Loan
is secured by a first-priority security interest in our subsidiaries' drilling
rigs. The Rig Loan bears interest at Prime Rate (as published in The Wall Street
Journal) plus 1.00%. Under the rig loan, we are required to pay interest
monthly. In addition, the borrowing base declines by $83,333 per month, and may
require a cash payment of the same if the line of credit is funded above the
borrowing base after this monthly reduction.
The Rig
Loan also contains certain restrictive covenants, which, among other things,
limit the incurrence of additional debt, investments, liens, dividends,
redemptions of capital stock, prepayments of indebtedness, asset dispositions,
mergers and consolidations, transactions with affiliates, derivative contracts,
sale leasebacks and other matters customarily restricted in credit agreements.
The Rig Loan agreements require our subsidiary to meet a maximum debt service
coverage ratio of 1.50 to 1.00, a minimum current assets to current liabilities
ratio of 3.00 to 1.00, a minimum tangible net worth of $8,500,000 and a maximum
debt to tangible net worth ratio of 1.00 to 1.00. The ratios are calculated on a
quarterly basis. We were in compliance with all such covenants at December 31,
2008. The agreements also contain customary events of default. We have
classified the outstanding balance due under this note as current, as a result
of the covenant violation under our SCA and TLA, due to a cross-default
provision. The lender has the right to increase the interest rate and/or
accelerate the payment schedule due to the default.
Preferred Stock Issuances:
In
November 2007, we issued 55,000 shares of Series C preferred stock in a private
placement raising approximately $52.8 million net of expenses. In February 2008,
we issued 20,000 shares of Series E preferred stock in a private placement
raising approximately $17.8 million net of expenses, and the buyers of the
Series C preferred stock exchanged their 55,000 issued and outstanding shares of
our Series C preferred stock for 55,000 shares of Series D preferred stock. The
Series D preferred stock provides for the same terms as the Series C. The Series
D preferred stock pays dividends at a rate of 6.5% per annum and the Series E
preferred stock pays dividends at a rate of 6% per annum. In general, the Series
D preferred stock is convertible into common stock at a conversion price of
$14.48 per share and the Series E preferred stock is convertible into common
stock at a conversion price of $17.76 per share. Upon occurrence of certain
specified events, the holders of the Series D preferred stock and Series E
preferred stock have the right to request redemption of their preferred stock,
the redemption price of which is, in general, an amount equal to the product of
(a) 115% and (b) the sum of such shares' stated value, accrued and unpaid
dividends, and any make-whole amounts related to preferred stock dividends.
However, our obligation to pay the redemption price of any preferred stock
requested to be redeemed is suspended until the earlier of (a) October 31, 2012
or (b) the date that all of our obligations under the bank credit facilities
have been satisfied.
In March
2008 the Company received notification that one of the purchasers of the Series
D Preferred Stock was exercising its right to purchase additional shares of
Series D Preferred Stock. The purchaser acquired an additional 13,909 shares of
Series D Preferred Stock in early April 2008. Payment for the subscribed shares
was received in early April 2008. All other rights to acquire additional shares
of Series D Preferred Stock expired unexercised in late March
2008.
With each
issuance of convertible preferred stock, we concurrently entered into call
spread options related to those shares that may offset the dilution to common
shares caused by a conversion at a time when the market price of the common
shares is greater than the conversion price and less than or equal to the sold
option price per share. Each call spread is a combination of a bought and a sold
call option. For more information, see the discussion under the heading "SELLING
STOCKHOLDERS' -- Private Placement and Share Exchange -- Call Spread
Transactions" in the Company's 424B3 Prospectus filed with the SEC on August 4,
2008, File No. 333-150107.
In
October 2008, holders of 12,000 shares of TXCO Series D Preferred Stock, with an
aggregate stated value of $12.0 million and a conversion price of $14.48,
converted those shares into a total of approximately 829,000 shares of TXCO's
common stock. An additional 231,000 shares of TXCO common stock were issued for
the make-whole provision related to preferred dividends.
Subsequent
to year end, holders of 5,000 shares of TXCO Series D Preferred Stock (with a
conversion price of $14.48) and 5,000 shares of TXCO Series E Preferred Stock
(with a conversion price of $17.36), with an aggregate stated value of $10.0
million, converted those shares into a total of approximately 633,300 shares of
TXCO's common stock. An additional 836,600 shares of TXCO common stock were
issued for the make-whole provision related to preferred dividends.
In
February 2009, it was determined that TXCO has violated the Current Ratio
covenant under its bank credit facilities. Under the terms of our Certificates
of Designations, the above default results in the holders of the Series D and
Series E Preferred Stock having a right to demand that we redeem the preferred
stock at the premium redemption price set forth in the Certificates of
Designation. However, under the terms of such Certificates of Designations, our
obligation to pay the redemption price of any preferred stock demanded to be
redeemed is suspended until the earlier of (a) October 31, 2012 or (b) the date
that all of our obligations under the bank credit facilities have been
satisfied. Under the terms of the Certificates of Designations, the Company is
obligated to pay interest at a rate of 1.5% per month in respect of each
unredeemed preferred share until paid in full. On March 9, 2009, a holder of
preferred stock demanded redemption of 34,409 shares of Series D Convertible
Preferred Stock and 15,000 shares of Series E Convertible Preferred
Stock.
Generally,
holders of our convertible preferred stock are entitled to receive dividends,
payable quarterly, at the rate of 6.5% and 6.0% per annum for Series D and
Series E, respectively. In connection with our breach of the current ratio
covenant in our bank credit facilities, the dividend rate is increased to 12%
per annum for both the Series D and Series E preferred stock until such time as
the breach of the current ratio covenant is cured. Our convertible preferred
stock is described more fully in
Note G
to the consolidated
financial statements
2009
Capital Requirements Outlook
Overall:
We have significantly curtailed our planned drilling operations in light of the
recent decline in oil and natural gas prices and our liquidity constraints.
Should product prices weaken further, or expected new oil and natural gas
production levels not be attained, the resulting reduction in projected revenues
would cause us to re-evaluate our working capital options and would adversely
affect our ability to carry out our current operating plans.
We
established an initial 2009 capital budget with a range of $25 million to $40
million, targeting 18 to 20
gross wells, as well as
certain leasehold acquisitions, dependent upon whether our working capital is
adequate to fund these plans. Funding for our CAPEX program will likely come
from working capital and any asset sales.
Our
capital budget may be revised, based on liquidity constraints, drilling plan
changes by partners, vendor relations, rig availability, drilling results,
operational developments, unanticipated transaction opportunities, market
conditions or commodity price fluctuations. Other companies will operate some of
these wells and, therefore, we do not have direct control over when they will be
drilled or what final costs will actually be incurred. The following table
details typical gross well costs budgeted for 2009 wells:
|
|
|
Typical Gross Well
Costs
|
|
|
(
In thousands)
|
|
Dry
Hole
|
|
Completed
|
|
Glen
Rose oil porosity zone horizontal well
|
|
|
|
|
|
Georgetown
horizontal oil well
|
|
|
|
|
|
Eagle
Ford horizontal natural gas well
|
|
|
|
|
|
Pearsall
horizontal natural gas well
|
|
|
|
|
|
Sources
and Uses of Cash
Net cash
provided by operating activities increased over the three-year period presented
from $24.7 million in 2006 to $100.6 million in 2008. The 2007 figure included a
$16.7 million year-end accrual for property acquisition costs related to a
transaction with a December 1, 2007, effective date. The following table
illustrates the impact of certain items on cash provided by operating activities
and how, on an adjusted basis, the respective periods compare. We use the
"adjusted cash provided by operating activities" measure, which is a non-GAAP
financial measure, in our internal analysis and review of our operational
performance. We believe that this non-GAAP measure provides management, our
lenders and investors with useful information in comparing our performance over
different periods, particularly when comparing one of these periods to a period
in which we did not incur significant acquisition costs. By using this non-GAAP
measure we believe management, our lenders and investors get a better picture of
the performance of our underlying business. However, investors should consider
this adjusted non-GAAP measure in addition to, not as a substitute for or as
superior to, financial reporting measures prepared in accordance with
GAAP
Adjusted
Cash Provided by Operating Activities
|
For
the Years Ended December 31,
|
|
(In
thousands)
|
|
2008
|
|
2007
|
|
2006
|
|
Net
cash provided by operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued
property acquisition cost
|
|
|
|
|
|
|
|
|
|
Federal
income tax, current & deferred
|
|
|
|
|
|
|
|
Adjusted
cash provided by operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
following tables set forth the Company's cash sources, and uses of cash, during
the three years presented. "Adjusted cash provided" and "cash utilized" are
non-GAAP measures. We believe that the presentation of non-GAAP financial
measures in the form of "adjusted cash provided" and "cash utilized" provides
important supplemental information to management, our lenders and investors
regarding the sources of liquidity and uses of cash by the Company during the
respective fiscal period. Our management uses these non-GAAP financial measures
when evaluating the Company's liquidity and funds available to meet future debt
services, capital expenditures and working capital requirements. The Company has
chosen to provide this information to investors so they can analyze the
Company's liquidity and financial condition in the same way that management does
and use this information in their assessment of the valuation of the Company.
However, investors should consider these measures in addition to, not as a
substitute for or as superior to, financial reporting measures prepared in
accordance with GAAP.
Total
adjusted cash provided from all sources, listed in the following table, includes
funds from private placements of the Company's common stock in 2006, preferred
stock in 2007 and 2008.
|
|
For
the Years Ended December 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
cash provided by operating activities
|
|
|
|
|
|
|
|
|
|
Internally
generated funds
|
|
|
|
|
|
|
|
|
|
Proceeds
from sale of assets
|
|
|
|
|
|
|
|
|
|
Issuance
of common and/or preferred stock, net of expenses
|
|
|
|
|
|
|
|
|
|
Proceeds
from sale of upper call option
|
|
|
|
|
|
|
|
|
|
Proceeds
from bank credit facilities
|
|
|
|
|
|
|
|
|
|
Proceeds
from installment obligations
|
|
|
|
|
|
|
|
|
|
Total
other sources of cash
|
|
|
|
|
|
|
|
|
|
Adjusted
Cash Provided, from all sources
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We
applied these funds as indicated in the following table:
|
|
For
the Years Ended December 31,
|
|
|
|
|
|
|
|
|
|
Drilling
and completion costs, 3-D seismic, and leasehold
acquisitions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
property and equipment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt
principal payments, excluding interest
|
|
|
|
|
|
|
|
Purchase
of lower call option
|
|
|
|
|
|
|
|
Purchase
of treasury shares
|
|
|
|
|
|
|
|
Payment
of preferred stock dividends in cash
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings
on the bank credit facilities were used to purchase Output Exploration, LLC in
2007. Proceeds from the sale of preferred stock, in 2007 and 2008, were used to
pay down debt and to provide additional liquidity in order to complement funding
of 2008 CAPEX.
Working
Capital and Current Ratio Calculations
|
For
the Years Ended December 31,
|
(In
thousands, except ratios)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less:
Current liabilities, before reclassifications due to covenant
violation
|
|
|
|
|
|
|
|
|
Net
working capital (deficit), before reclassifications due to covenant
violation
|
|
|
|
|
|
|
|
|
Current
ratio, before reclassifications due to covenant
violation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
liabilities, after reclassifications due to covenant
violation
|
|
|
|
|
|
|
|
|
Net
working capital (deficit), after reclassifications due to covenant
violation
|
|
|
|
|
|
|
|
|
Current
ratio, after reclassifications due to covenant
violation
|
|
|
|
|
|
|
2006
through 2007 Sales and Acquisitions
:
Please
see the discussion regarding the acquisitions and sales included in the
Overview
section of this MD&A.
See "Item
1A. Risk Factors" for disclosures regarding risks related to our liquidity
issues.
RESULTS OF OPERATIONS
The
following table highlights the percentage change from the preceding year for
selected items that are significant in our industry. For full information see
the
Consolidated Statements of Operations
in our Audited
Consolidated Financial Statements and the
Sales Volumes
discussion.
|
|
|
2008
vs.
|
|
2007
vs.
|
|
2006
vs.
|
|
|
Percentage
Change in Selected Income Statement Items:
|
|
2007
|
|
2006
|
|
2005
|
|
Oil
and natural gas revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment
& abandonments
|
|
|
|
|
|
|
|
Depreciation,
depletion & amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
available to common stockholders
|
|
|
|
|
|
|
|
Basic
income per common share
|
|
|
|
|
|
|
|
|
|
|
2008
vs.
|
|
2007
vs.
|
|
2006
vs.
|
|
|
Percentage
Change in Selected Operating Items:
|
|
2007
|
|
2006
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
residue and NGL sales volumes
|
|
|
|
|
|
|
|
Oil
average sales price per Bbl, excluding hedging
impact
|
|
|
|
|
|
|
|
Gas
average sales price per mcf, excluding hedging
impact
|
|
|
|
|
|
|
|
Residue
& NGL sales price per mmBtu
|
|
|
|
|
|
|
|
n/m - The
percentage change is not meaningful since moved from an income to a loss between
these periods.
The
following table provides further detail on our natural gas gathering
operations:
|
Gas Gathering Results:
($ in
thousands)
|
|
2008
|
|
2007
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas liquids sales
|
|
|
|
|
|
|
|
Transportation
and other revenue
|
|
|
|
|
|
|
|
Total
gas gathering revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Third-party
natural gas purchases
|
|
|
|
|
|
|
|
Transportation
and marketing expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
gas gathering operations expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 Compared to
2007
Revenues
The 56.0%
increase in oil and natural gas revenue is primarily due to the inclusion of a
full year of Output revenues, along with higher average realized prices for
crude oil and natural gas, as well as higher volumes for both products. Sales
volumes increased 15.6% on an equivalent unit basis. Natural gas sales volumes
were up 14.0% due to inclusion of Output volumes for the full period, as well as
increased volumes in the Pearsall play, partially offset by reductions
reflecting normal maturing natural gas well decline curves and the sale of 15
non-core properties with approximately 1.3 mmcfed of production during the third
quarter. Oil sales volumes increased 16.2% primarily due to Glen Rose Porosity
wells put on production during 2008. Excluding the impact of hedging, average
realized sales prices for natural gas were up 32.4%, while those for crude oil
were up 37.0%. Derivative losses on hedges reduced revenues by $6.0 million for
the period, compared with $3.0 million for the prior year.
On an
equivalent-unit basis, average sales prices were up 36.4%. Higher average
realized sales prices had a $35.5 million positive impact on revenues in 2008.
Increased sales volumes had a $13.4 million positive impact on revenues for the
year. Commodity prices have been, and continue to be, volatile. During 2008,
realized natural gas prices ranged from a high of $11.81 per mcf in June to a
low of $4.41 per mcf in November, while realized crude oil prices ranged from a
high of $140.18 in July to a low of $33.68 in December.
Lease
Operations
The 34.3%
increase reflects the inclusion of Output costs for the full year and costs
related to 46.15 net oil wells and 3.42 net natural gas wells placed on
production during 2008, and increased costs due to greater demand for
third-party services in the field, partially offset by elimination of costs for
properties sold during fourth quarter 2007 and third quarter 2008, and reduced
costs on properties for which we assumed operation. The increase reflects the
incremental direct costs of operating the new wells, including the usual costs
such as pumper, electricity, water disposal, and other direct overhead charges.
Operating expense per mcfe increased $0.42 to $2.75.
Exploration
Expenses
The
13
1
.1
% increase primarily reflects
dry hole costs and
delay rental payments on
certain leased properties.
Gas
Gathering
The 18.4%
increase in gas gathering revenues (and 10.2% increase in related expenses)
reflects higher realized prices and higher sales volumes. See the "Gas Gathering
Results" table above.
Impairment
We
periodically, at least annually, assess our producing and non-producing
properties for impairment. The increase in impairment expense primarily reflects
impairment related to our oil sands projects ($11.3 million) and increased
impairment recognized on oil and natural gas properties ($3.0 million) due to
currently projected lower product prices.
Depreciation,
Depletion and Amortization
The 44.8%
increase is due to the inclusion of Output costs for the full year and higher
finding costs, depletion rates and costs related to new wells placed on
production over the last year.
General
and Administrative
The $1.7
million increase was primarily due to higher non-cash stock compensation expense
and proxy contest expenses, offset in part by reduction in costs related to
acquisitions. G&A expense as a percentage of revenue decreased to 9.6 %,
from 12.9% for the prior year, primarily due to higher commodity sales prices.
The higher level of absolute-dollar costs also reflects our higher sustained
level of operations and a full year of costs from the Output
acquisition.
|
($
in thousands)
|
|
2008
|
2007
|
$
change
|
%
change
|
|
Non-cash,
stock compensation expense
|
|
$3,626
|
$1,799
|
|
+1,827
|
|
+101.6
|
|
Non-cash,
value of ORRI on acquired properties
|
|
237
|
1,025
|
|
-788
|
|
-76.9
|
|
Costs
related to assimilating Output acquisition
|
|
-
|
525
|
|
-525
|
|
-100.0
|
|
Other
G&A expense
|
|
9,925
|
8,709
|
|
+1,216
|
|
+14.0
|
|
Total
G&A expense
|
|
|
|
|
|
|
|
Costs are
expected to decline somewhat in 2009 due to a reduction in workforce of
approximately 20% in late December 2008.
Interest
Expense
The
decrease in interest expense reflects lower interest rates, partially offset by
higher average balances, on our credit facility.
Loss
on Sale of Assets
The loss
recorded in 2008 reflects the sale of 15 non-core properties in South Texas for
less than the associated book value.
Income
Tax Expense
Our
effective tax rate was 31.2%, which is less than the statutory rate due
primarily to the tax benefit received on the exercise of stock options during
first-quarter 2008. In the prior year we recorded a tax benefit of 169.5% due to
statutory tax depletion and similar items.
Net
Loss / Earnings Per Share
We
reported a net loss available to common stockholders of $0.5 million, $(0.01)
per basic and diluted share, compared to net income of $0.9 million, $0.03 per
basic and diluted share for the prior year.
2007 Compared to
2006
Revenues
Total
revenues increased by $21.5 million. Natural gas sales volumes increased by
1.021 bcf while oil sales volumes increased by 182,969 BO, resulting in a
combined increase of 2.1 bcfe or 353,130 BOE. Average daily net natural gas
sales were 5.8 mmcf, a 92.5 % increase. The increase in natural gas sales
volumes was primarily due to the acquisition of Output, partially offset by
normal declines experienced in maturing natural gas wells. Average daily net oil
production rates were 2,670 BO, a 23.2% increase. The increase in oil sales
volumes reflects higher Glen Rose Porosity production.
On an
equivalent-unit basis, prices averaged 8.3% higher. Crude oil prices averaged
13.7% higher while natural gas prices were up 1.2%. Higher average realized
sales prices had an $8.5 million positive impact on revenues in 2007. Increased
sales volumes had an $18.8 million positive impact on revenues for the year.
Commodity prices have been, and continue to be, volatile. During 2007, realized
natural gas prices ranged from a high of $8.85 per mcf in October to a low of
$6.20 per mcf in January, while realized crude oil prices ranged from a high of
$93.17 in November to a low of $51.75 in January.
Lease
Operations
Lease
operating expense increased $6.9 million, or 94.6%. This increase was primarily
due to the Output acquisition and the addition of 40 new oil wells and seven new
natural gas wells during 2007. The increase reflects the incremental direct
costs of operating the new wells, including the usual costs such as pumper,
electricity, water disposal, and other direct overhead charges. Operating
expense per mcfe increased $0.66 to $2.33.
Gas
Gathering
Gas
gathering revenues decreased 24.6%, while related operating expenses decreased
18.4%. These decreases are consistent with the decreased natural gas throughput
for the gathering system compared to the prior period. See the "Gas Gathering
Results" table above.
Impairment
Pursuant
to the successful efforts method of accounting for mineral properties, we
periodically assess our producing and non-producing properties for impairment.
Impairment and abandonments increased by 15.1% due to recognizing the impairment
on certain oil and natural gas properties.
Depreciation,
Depletion and Amortization
DD&A
increased by $12.4 million, or 51.9%, consistent with the number of acquired and
newly drilled producing wells being depleted. The increase in depreciation was
due to increased investments in other equipment including computer and equipment
additions (including drilling rigs). The increase in amortization primarily
reflects the acquisition of Output.
General
and Administrative
G&A
costs increased 65.2% and were 12.9% of revenues. This compares to 2006 when
G&A expenses were 10.1% of revenues. The higher level of absolute-dollar
costs reflects our higher sustained level of operations and the Output
acquisition. The increase also reflects higher salaries, benefits, and
office-related expenses for a full year related to 6 employees hired during
2006, and a partial year for an additional 10 employees hired during
2007.
|
($
in thousands)
|
|
2007
|
2006
|
$
change
|
|
%
change
|
|
Non-cash,
stock compensation expense
|
|
$1,799
|
$1,207
|
|
+592
|
|
49.0
|
|
Non-cash,
value of ORRI
|
|
1,025
|
-
|
|
+1,025
|
|
n/m
|
|
Costs
related to assimilating Output acquisition
|
|
525
|
-
|
|
+525
|
|
n/m
|
|
Other
G&A expense
|
|
8,709
|
6,091
|
|
+2,618
|
|
43.0
|
|
Total
G&A expense
|
|
|
$7,298
|
|
|
|
|
n/m - not
meaningful since prior year was zero
During
2007, we incurred some non-recurring G&A costs in the following forms. These
costs included the cost of integrating the Output acquisition into our
operations (see table above). These costs include salaries during a transition
period paid to Output employees and consultants, and moving the Output office.
Also of a non-recurring nature, was a $1.0 million charge for the value of the
1% overriding royalty interest ("ORRI") in conjunction with the Output
acquisition that will be assigned, under a 1996 agreement, with our president.
No comparable charge was recorded in the prior year.
We expect
G&A costs to return to our historical levels as a percentage of revenues in
2008.
Interest
Income / Expense
The
increase in interest expense reflects higher average balances on our credit
facility related to our April 2007 acquisition of Output.
Net
Income / Earnings Per Share
We
reported net income available to common stockholders of $0.9 million, $0.03 per
basic and diluted share, compared to a net income of $7.2 million,
$0.23 per basic share and $0.22 per diluted share for the prior
year.
CONTRACTUAL OBLIGATIONS AND CONTINGENT LIABILITIES AND
COMMITMENTS
The
following is a summary of our future payments on obligations as of December 31,
2008.
|
|
|
Payments
Due by Period
|
|
|
|
|
Less
than
|
|
1-3
|
|
3-5
|
|
More
than
|
|
|
|
|
Contractual
Obligations
(in
thousands)
|
|
1
Year
|
|
Years
|
|
Years
|
|
5
Years
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
lease obligations (2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Contractual Cash Obligations
|
|
|
|
|
|
|
|
|
|
|
|
(1)
excluding interest. Because of our financial covenant default under our bank
credit facilities, our lenders have the right to declare these amounts to be
immediately due and payable. In addition, because of the financial
covenant default under our bank credit facilities, the holders of our Series D
Preferred Stock and Series E Preferred Stock have the right to request us to
redeem their preferred stock, the redemption price of which is, in general, an
amount equal to the product of (a) 115% and (b) the sum of such preferred
shares' stated value, accrued and unpaid dividends, and any make-whole amounts
related to preferred stock dividends. However, our obligation to pay
the redemption price of any preferred stock requested to be redeemed is
suspended until the earlier of (a) October 31, 2012 or (b) the date that all of
our obligations under the bank credit facilities have been
satisfied. Because of the financial covenant default, all of our
outstanding long-term debt and all of our outstanding preferred stock, at its
stated value of $1,000 per share (after the January 2009 conversions), has been
reclassified as a current liability on our Consolidated Balance Sheet at
December 31, 2008 included in our Consolidated Financial Statements
included elsewhere herein. The foregoing table does not reflect this
redemption obligation. See "Liquidity and Capital Resources" above for more
information about our bank credit facilities and preferred stock.
(2)
excludes contingent payments of up to $27 million that would become due in early
2010 if drilling of the required Phase II wells under both farm-out agreements
is not completed
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The
discussion and analysis of our financial condition and results of operations is
based upon the consolidated financial statements, which have been prepared in
accordance with United States generally accepted accounting principles ("GAAP").
The preparation of these financial statements requires us to make estimates and
judgments that affect the reported amounts of assets, liabilities, revenues and
expenses. Our significant accounting policies are described in
Note A to the Audited Consolidated Financial Statements
.
Certain of these policies are of particular importance to the portrayal of our
financial position and results of operations, and require the application of
significant judgment by management. We analyze our estimates, including those
related to reserves, depletion and impairment of oil and natural gas properties,
and the ultimate utilization of the deferred tax asset, and base our estimates
on historical experience and various other assumptions that we believe to be
reasonable under the circumstances. Actual results may differ from these
estimates under different assumptions or conditions. We believe the following
critical accounting policies affect our more significant judgments and estimates
used in the preparation of our financial statements:
Successful
Efforts Method of Accounting
We
account for our natural gas and crude oil exploration and development activities
utilizing the successful efforts method of accounting. Under this method, costs
of productive exploratory wells, development dry holes and productive wells,
costs to acquire mineral interests and 3-D seismic costs are capitalized.
Exploration costs, including personnel costs, certain geological and geophysical
expenses including 2-D seismic costs and delay rentals for oil and natural gas
leases, are charged to expense as incurred.
When an
entire interest in an unproved property is sold, a gain or loss is recognized
for the difference between the carrying value of the property and the sales
price. If a partial interest in an unproved property is sold, the amount
received is treated as a reduction of the cost of the interest retained. On the
sale of an entire or partial interest in a proved property, the asset is
relieved along with the corresponding accumulated depreciation, depletion, and
amortization. When compared with the sales price, a resulting gain or loss is
recognized in income.
The
application of the successful efforts method of accounting requires managerial
judgment to determine the proper classification of wells designated as
developmental or exploratory which will ultimately determine the proper
accounting treatment of the costs incurred. The results from drilling can take
considerable time to analyze and the determination that commercial reserves have
been discovered requires both judgment and industry experience. Wells may be
completed that are assumed to be productive and ultimately deliver oil and
natural gas in quantities insufficient to be economic, which may result in the
abandonment or recompletion of the wells at later dates. Wells are drilled that
have targeted geologic structures that are both developmental and exploratory in
nature and an allocation of costs is required to properly account for the
results. The evaluation of oil and natural gas leasehold acquisition costs
requires managerial judgment to estimate the fair value of these costs with
reference to drilling activity in a given area. Drilling activities in an area
by other companies may also effectively condemn leasehold
positions.
The
successful efforts method of accounting can have a significant impact on
operational results reported when we are entering a new exploratory area in
hopes of finding an oil and natural gas field that will be the focus of future
development. The initial exploratory wells may be unsuccessful and will be
expensed.
Revenue
Recognition
We
recognize oil and natural gas revenue from our interest in producing wells as
the oil and natural gas is sold to third parties. Gas gathering operations
revenues are recognized upon delivery of the product to third
parties.
Reserve
Estimates
Our
estimates of oil and natural gas reserves, by necessity, are projections based
on geologic and engineering data, and there are uncertainties inherent in the
interpretation of such data as well as the projection of future rates of
production and the timing of development expenditures. Reserve engineering is a
subjective process of estimating underground accumulations of oil and natural
gas that are difficult to measure. The accuracy of any reserve estimate is a
function of the quality of available data, engineering and geological
interpretation and judgment. Estimates of economically recoverable oil and
natural gas reserves and future net cash flows depend upon a number of variable
factors and assumptions, all of which may in fact vary considerably from actual
results. These factors and assumptions include historical production from the
area compared with production from other producing areas, the assumed effects of
regulations by governmental agencies and assumptions governing future oil and
natural gas prices, future operating costs, severance taxes, development costs
and workover costs. The future drilling costs associated with reserves assigned
to proved undeveloped locations may ultimately increase to an extent that these
reserves may be later determined to be uneconomic. For these reasons, estimates
of economically recoverable quantities of oil and natural gas attributable to
any particular group of properties, classifications of such reserves based on
risk of recovery, and estimates of future net cash flows expected there from may
vary substantially. Any significant variance in the assumptions could materially
affect the estimated quantity and value of the reserves, which could affect the
carrying value of our oil and natural gas properties and/or the rate of
depletion of the oil and natural gas properties. Actual production, revenues and
expenditures, with respect to our reserves, will likely vary from estimates and
such variances may be material. We contract with independent engineering firms
to provide reserve estimates for reporting purposes.
Impairment
of Oil and Natural Gas Properties
We review
our oil and natural gas properties for impairment at least annually and whenever
events and circumstances indicate a decline in the recoverability of their
carrying value. We estimate the expected future cash flows of our oil and
natural gas properties and compare such future cash flows to the carrying amount
of the properties to determine if the carrying amount is recoverable. If the
carrying amount exceeds the estimated undiscounted future cash flows, we will
adjust the carrying amount of the oil and natural gas properties to their fair
value. The factors used to determine fair value include, but are not limited to,
estimates of proved reserves, future commodity pricing, future production
estimates, anticipated capital expenditures, and a discount rate commensurate
with the risk associated with realizing the expected cash flows
projected.
Given the
complexities associated with oil and natural gas reserve estimates and the
history of price volatility in the oil and natural gas markets, events may arise
that would require us to record an impairment of the recorded book values
associated with oil and natural gas properties. We have recognized impairments
in both the current and prior years and there can be no assurance that
impairments will not be required in the future.
Income
Taxes
Significant
management judgment is required to determine the provisions for income taxes and
determine whether deferred tax assets will be realized in full or in part.
Deferred income tax assets and liabilities are measured using enacted tax rates
expected to apply to taxable income in the years in which those temporary
differences are expected to be recovered or settled. When it is more likely than
not that all or some portion of specific deferred income tax assets will not be
realized, a valuation allowance must be established for the amount of deferred
income tax assets that are determined not to be realizable.
Additionally,
despite our belief that our tax return positions are consistent with applicable
tax law, we believe that certain positions may be challenged by taxing
authorities. Settlement of any challenge can result in no change, a complete
disallowance, or some partial adjustment reached through
negotiations.
In July
2006, the FASB issued FASB Interpretation No. 48, "Accounting for Uncertainty in
Income Taxes, an interpretation of FASB Statement No. 109" ("FIN 48"). FIN 48
clarifies the accounting for uncertainty in income taxes recognized in a
company's financial statements in accordance with SFAS No. 109, "Accounting for
Income Taxes." We adopted FIN 48 effective on January 1, 2007. FIN 48 clarified
the accounting for uncertainty in income taxes recognized in the financial
statements by prescribing a recognition threshold and measurement attribute for
a tax position taken or expected to be taken in a tax return. FIN 48 prescribes
how a company should recognize, measure, present and disclose any uncertain tax
positions that the company has taken or expects to take in its income tax
returns. FIN 48 requires that only income tax benefits that meet the "more
likely than not" recognition threshold be recognized or continue to be
recognized after its effective date.
Commodity
Hedging Contracts
All of
our price-risk management transactions are considered derivative instruments and
accounted for in accordance with SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." These derivative instruments are intended
to hedge our price risk and may be considered hedges for economic purposes, but
certain of these transactions may or may not qualify for cash flow hedge
accounting. All derivative instrument contracts are recorded on the balance
sheet at fair value. In prior years, we had elected to account for certain of
our derivative contracts as investments as set out under SFAS No. 133.
Therefore, the changes in fair value in those contracts were recorded
immediately as unrealized gains or losses on the Consolidated Statements of
Operations. The change in fair value for the effective portion of contracts
designated as cash flow hedges is recognized as Other Comprehensive Income
(Loss) as a component in the Stockholders' Equity section of the Consolidated
Balance Sheets.
NEW
ACCOUNTING STANDARDS
In
September 2006, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 157, "Fair Value Measurement" ("SFAS No. 157"). SFAS No. 157 defines fair
value, establishes a framework for measuring fair value, and expands disclosures
about fair value measurements. The standard applies whenever other standards
require (or permit) assets or liabilities to be measured at fair value, but does
not expand the use of fair value in any new circumstances. In February 2008, the
FASB granted a one-year deferral of the effective date of this statement as it
applies to non-financial assets and liabilities that are recognized or disclosed
at fair value on a nonrecurring basis (e.g. those measured at fair value in a
business combination and goodwill impairment). SFAS No. 157 is
effective for all recurring measures of financial assets and financial
liabilities (e.g. derivatives and investment securities) for financial
statements issued for fiscal years beginning after November 15, 2007. We adopted
SFAS No. 157 effective January 1, 2008, and its adoption did not have
a material impact on our financial position or results of
operations.
In
February 2007, the FASB issued SFAS No. 159, "The Fair Value Option for
Financial Assets and Financial Liabilities" ("SFAS No. 159"). SFAS No. 159
allows entities the option to measure eligible financial instruments at fair
value as of specified dates. Such election, which may be applied on an
instrument by instrument basis, is typically irrevocable once elected. SFAS No.
159 is effective for fiscal years beginning after November 15, 2007. We adopted
SFAS No. 159 effective January 1, 2008, but did not elect to apply the fair
value option to eligible assets and liabilities during the year ended December
31, 2008.
In
December 2007, the FASB issued SFAS No. 141(R), "Business
Combinations" ("SFAS No. 141(R)"), which replaces SFAS No. 141.
SFAS No. 141(R) establishes principles and requirements for how an acquirer
recognizes and measures in its financial statements the identifiable assets
acquired, the liabilities assumed, any non-controlling interest in the acquiree
and the goodwill acquired. The Statement also establishes disclosure
requirements, which will enable users to evaluate the nature and financial
effects of the business combination. SFAS No. 141(R) is effective for
fiscal years beginning after December 15, 2008. The adoption of
SFAS No. 141(R) will have an impact on accounting for business combinations
once adopted, but the effect is dependent upon acquisitions at that
time.
In
December 2007, FASB issued SFAS No. 160, "Noncontrolling Interests in
Consolidated Financial Statements -- an amendment of Accounting Research
Bulletin No. 51" ("SFAS No. 160"), which establishes accounting
and reporting standards for ownership interests in subsidiaries held by parties
other than the parent, the amount of consolidated net income attributable to the
parent and to the non-controlling interest, changes in a parent's ownership
interest and the valuation of retained non-controlling equity investments when a
subsidiary is deconsolidated. The Statement also establishes reporting
requirements that provide sufficient disclosures that clearly identify and
distinguish between the interests of the parent and the interests of the
non-controlling owners. SFAS No. 160 is effective for fiscal years
beginning after December 15, 2008. We do not currently have non-controlling
interests in any of our subsidiaries.
In March
2008, the FASB released SFAS No. 161, "Disclosures about Derivative
Instruments and Hedging Activities -- an amendment of FASB Statement
No. 133." This Statement is effective for financial statements issued for
fiscal years and interim periods beginning after November 15, 2008, which
for us is the interim period ending March 31, 2009. This statement requires that
objectives for using derivative instruments be disclosed in terms of underlying
risk and accounting designation, in order to better convey the purpose of
derivative use in terms of the risks that we are intending to manage. We are
currently assessing and evaluating the new disclosure requirements for our
derivative instruments.
In May
2008, the FASB issued FASB Staff Position (FSP) Financial Accounting Standard
142-3, Determination of the Useful Life of Intangible Assets, which is effective
for fiscal years beginning after December 15, 2008 and for interim periods
within those years, which for us is the interim period ending March 31, 2009.
FSP FAS 142-3 provides guidance on the renewal or extension assumptions
used in the determination of the useful life of a recognized intangible asset.
The intent of FSP FAS 142-3 is to better match the useful life of the
recognized intangible asset to the period of the expected cash flows used to
measure its fair value. We do not expect FSP FAS 142-3 to have a material
effect on our consolidated financial statements.
In
December 2008, the SEC published a Final Rule, "Modernization of Oil and
Gas Reporting". The new rule permits the use of new technologies to determine
proved reserves if those technologies have been demonstrated to lead to reliable
conclusions about reserves volumes. The new requirements also will allow
companies to disclose their probable and possible reserves to investors. In
addition, the new disclosure requirements require companies to: (a) report the
independence and qualifications of its reserves preparer or auditor; (b) file
reports when a third party is relied upon to prepare reserves estimates or
conducts a reserves audit; and (c) report oil and natural gas reserves using an
average price based upon the prior 12-month period rather than year-end prices.
The use of average prices will affect future impairment and depletion
calculations.
The new
disclosure requirements are effective for annual reports on Forms 10-K for
fiscal years ending on or after December 31, 2009. A company may not apply
the new rules to disclosures in quarterly reports prior to the first annual
report in which the revised disclosures are required. We have not yet determined
the impact of this Final Rule on our disclosures, financial position or results
of operations, which will vary depending on changes in commodity prices.
ITEM
7A. QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity
Risk
:
Our major market-risk
exposure is the commodity pricing applicable to our oil and natural gas
production. Realized commodity prices received for such production are primarily
driven by the prevailing worldwide price for crude oil and spot prices
applicable to natural gas. Prices have fluctuated significantly over the last
five years and such volatility is expected to continue, and the range of such
price movement is not predictable with any degree of certainty. We enter into
financial price hedges from time to time covering a portion of our monthly
volumes. The amount and timing are generally determined by requirements under
our credit facilities. Our current hedges are described in the table below. A
10% fluctuation in the price received for oil and gas production would have an
approximate $8.2 million impact on our annual revenues based on 2008 sales
volumes.
Derivative Contracts at Year
End:
|
Transaction
Date
|
Trans-
action
Type
|
Beginning
|
Ending
|
Average
Floor
Price
Per Unit
|
|
Average
Ceiling Price
Per
Unit
|
|
Volumes
Per
Month
|
|
|
Crude
Oil
-
Bbl (1)
:
|
|
08/07-08/08
|
Collars
|
01/01/2008
|
12/31/2008
|
$75.35
|
|
$97.09
|
|
35,500
|
|
|
08/07-08/08
|
Collars
|
01/01/2009
|
12/31/2009
|
$71.40
|
|
$87.41
|
|
20,700
|
|
|
08/07-08/08
|
Collars
|
01/01/2010
|
06/30/2010
|
$68.33
|
|
$80.77
|
|
15,000
|
|
|
12/07-04/08
(3)
|
Collars
|
07/01/2010
|
12/31/2010
|
$75.80
|
|
$100.35
|
|
13,200
|
|
|
04/08
(3)
|
Collars
|
01/01/2011
|
06/30/2011
|
$90.00
|
|
$122.80
|
|
11,500
|
|
|
Natural Gas
-
mmBtu
(2
)
:
|
|
08/07-08/08
|
Collars
|
01/01/2008
|
12/31/2008
|
$6.61
|
|
$10.45
|
|
105,500
|
|
|
08/07-08/08
|
Collars
|
01/01/2009
|
12/31/2009
|
$6.60
|
|
$11.64
|
|
86,500
|
|
|
08/07-04/08
|
Collars
|
01/01/2010
|
06/30/2010
|
$6.58
|
|
$11.62
|
|
74,000
|
|
|
12/07-04/08
(3)
|
Collars
|
07/01/2010
|
12/31/2010
|
$6.55
|
|
$11.08
|
|
69,500
|
|
|
04/08
(3)
|
Collars
|
01/01/2011
|
06/30/2011
|
$8.00
|
|
$9.85
|
|
62,000
|
|
(1)
These crude
oil hedges were entered into on a per barrel delivered price basis, using the
West Texas Intermediate Index, with settlement for each calendar month occurring
following the expiration date, as determined by the contracts.
(2)
These natural gas hedges were
entered into on an mmBtu delivered price basis, using the Houston Ship Channel
Index, with settlement for each calendar month occurring following the
expiration date, as determined by the contracts.
See the
next page for footnote (3) for this table.
(3)
A portion of
our 2010 and 2011 commodity collars were closed for cash during January 2009 and
replaced with new 50% participation swaps, which allow a floor price on the full
notional volume and a cap at the same price on one-half of the notional volume.
The changes are shown below:
|
Transaction
Date
|
Trans-
action
Type
|
Beginning
|
Ending
|
Average
Floor
Price
Per Unit
|
|
Average
Ceiling Price
Per
Unit
|
|
Volumes
Per
Month
|
|
|
CLOSED
POSITIONS
:
Crude
Oil
-
Bbl
:
|
|
|
08/07-08/08
|
Collars
|
01/01/2010
|
06/30/2010
|
$68.33
|
|
$79.95
|
|
9,000
|
|
|
12/07-04/08
|
Collars
|
07/01/2010
|
12/31/2010
|
$90.00
|
|
$124.50
|
|
700
|
|
|
04/08
|
Collars
|
01/01/2011
|
06/30/2011
|
$90.00
|
|
$122.80
|
|
11,500
|
|
|
Natural Gas
-
mmBtu
:
|
|
|
08/07-04/08
|
Collars
|
01/01/2010
|
06/30/2010
|
$6.93
|
|
$11.56
|
|
14,000
|
|
|
NEW
PARTICIPATION SWAPS
:
Crude
Oil
-
Bbl
:
|
|
|
01/09
|
Swaps
|
01/01/2010
|
06/30/2010
|
$49.75
|
|
|
|
8,000
|
|
|
01/09
|
Swaps
|
07/01/2010
|
12/31/2010
|
$51.40
|
|
|
|
14,000
|
|
|
01/09
|
Swaps
|
01/01/2011
|
06/30/2011
|
$52.25
|
|
|
|
2,000
|
|
|
01/09
|
Swaps
|
07/01/2011
|
12/31/2011
|
$53.50
|
|
|
|
12,000
|
|
|
Natural Gas
-
mmBtu
:
|
|
|
01/09
|
Swaps
|
01/01/2010
|
06/30/2010
|
$5.51
|
|
|
|
53,000
|
|
Call Spread
Transactions
:
In
connection with the offer and sale of each series of the preferred stock, we
entered into convertible preferred stock hedge transactions, or "call spread"
transactions, with one of the buyers of the stock (the "Counterparty"). These
transactions are intended to reduce the potential dilution upon conversion of
the preferred stock, if the market value per share of our common stock at the
time of exercise is greater than approximately 120% of the issue price (which
corresponds to the initial conversion price of the related convertible preferred
stock). These transactions include a purchased call option and a sold call
option. The purchased call options cover approximately the same number of shares
of our common stock, par value $0.01 per share, which, under most circumstances,
represents the maximum number of shares of common stock underlying the preferred
stock. The sold call options have an exercise price of 150% of the issue price
and are expected to result in some dilution should the price of our common stock
exceed this exercise price.
Interest Rate
Risk
:
We have
borrowed funds under our bank credit facilities with the Bank of Montreal, as
agent, with interest based on LIBOR rates plus an applicable margin. At March
13, 2009, we had $50.0 million in total borrowings under the Facilities, with an
average interest rate of 4.00%. At our current borrowing level, an annualized
10% fluctuation in interest charged on the floating rate balance at March 13,
2009, would have $0.5 million impact on our annual net income, before
taxes.
Financial
Instruments
:
Our
financial instruments consist of cash equivalents and accounts receivable. Our
cash equivalents are cash investment funds that are placed with a major
financial institution. Substantially all of our accounts receivable result from
oil and natural gas sales or joint interest billings to third parties in the oil
and natural 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 any significant credit losses on such
receivables.
ITEM
8. FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA
|
ITEM 9.
|
CHANGES
IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
|
None
ITEM
9A. CONTROLS
AND PROCEDURES
A review
and evaluation was performed under the supervision and with the participation of
our Chief Executive Officer (the "CEO") and Chief Financial Officer (the "CFO")
of the effectiveness of the design and operation of our disclosure controls and
procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the
Exchange Act) as of the end of the period covered by this Form 10-K. Based on
that review and evaluation, the CEO and CFO have concluded that our current
disclosure controls and procedures, as designed and implemented, are effective
to provide reasonable assurance that the information required to be disclosed in
our Exchange Act reports is recorded, processed, summarized, and reported within
the time periods specified by the SEC, and that information is communicated to
management, including the CEO and CFO, as appropriate, to allow timely decisions
regarding required disclosure. During the fourth quarter of 2008, there were no
changes in the Company's internal controls or in other factors that materially
affected, or are reasonably likely to materially affect, our internal controls
over financial reporting. There were no material weaknesses identified in the
course of the review and evaluation and, therefore, no corrective measures were
required.
Management's
Report On Internal Control Over Financial Reporting
Our
management is responsible for establishing and maintaining adequate internal
control over financial reporting
,
as it is defined in Exchange
Act Rules 13a-15(f). Internal control over financial reporting is a process
designed to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of our financial statements for external purposes
in accordance with generally accepted accounting principles ("GAAP"). Under the
supervision and with the participation of our management, including the CEO and
the CFO, we conducted an evaluation of the effectiveness of our 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.
Our
internal control over financial reporting includes those policies and procedures
that:
|
·
|
pertain
to the maintenance of records that in reasonable detail accurately and
fairly reflect the transactions and dispositions of our
assets;
|
|
·
|
provide
reasonable assurance that transactions are recorded as necessary to permit
preparation of our financial statements in accordance with GAAP, and that
our receipts and expenditures are being made only in accordance with
authorizations of our management and Directors;
and
|
|
·
|
provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use or disposition of our assets that could have
a material effect on our financial
statements.
|
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation
of effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
Based on
our evaluation under the framework in
Internal Control
--
Integrated Framework
,
our management believes
that our internal control over financial reporting was effective as of December
31, 2008.
The
effectiveness of our internal control over financial reporting as of December
31, 2008 has been audited by Akin, Doherty, Klein & Feuge, P.C., an
independent registered public accounting firm, as stated in their report that
follows.
|
James
E. Sigmon
|
P.
Mark Stark
|
|
Chairman,
and Chief Executive Officer
|
Vice
President and Chief Financial
Officer
|
Attestation
Report Of Independent Registered Public Accounting Firm
On
Internal Control Over Financial Reporting
To The
Board of Directors And Stockholders of
TXCO
Resources Inc. and Subsidiaries
San
Antonio, Texas
We have
audited TXCO Resources Inc. and subsidiaries (the Company) internal control over
financial reporting as of December 31, 2008, based on criteria established in
Internal Control--Integrated
Framework
issued by the Committee of Sponsoring Organizations of the
Treadway Commission (the COSO criteria). The Company's management is responsible
for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial
reporting included in the accompanying
Management
'
s Report on Internal Control
Ov
er
Financial Reporting
. Our
responsibility is to express an opinion on the Company's internal control over
financial reporting based on our audit.
We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness exists, testing
and evaluating the design and operating effectiveness of internal control based
on the assessed risk. Our audit also included performing such other
procedures as we considered necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinion.
A
company's internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial
statements.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
In our
opinion, the Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2008, based on the COSO
criteria.
We also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheets as of December
31, 2008 and 2007 and the related consolidated statements of operations,
stockholders' equity, and cash flows for each of the three years in the period
ended December 31, 2008, of TXCO Resources Inc. and subsidiaries and our report
dated March 13, 2009, expressed an unqualified opinion thereon, with an
explanatory paragraph which states we are assuming the Company will continue as
a going concern.
/s/ Akin,
Doherty, Klein & Feuge, P.C.
San
Antonio, Texas
March 13,
2009
ITEM
9B. OTHER
INFORMATION
None
PART
III
ITEM
10. DIRECTORS,
EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The
information required by this Item relating to our directors and nominees,
executive officers, compliance with Section 16(a) of the Exchange Act and
certain corporate governance matters is included under the captions "Proposal I
-- Election of Directors," "Executive Officers" and " Section 16(a) Beneficial
Ownership Reporting Compliance, "Corporate Governance," and "Other Matters" in
our Proxy Statement for the 2008 Annual Meeting of Stockholders ("Proxy
Statement") and is incorporated herein by reference. The Proxy Statement will be
filed with the Securities and Exchange Commission pursuant to Regulation 14A of
the Exchange Act of 1934, as amended, not later than 120 days after December 31,
2008.
Code of Business
Conduct:
Pursuant to Nasdaq Rule 4350(n), we have adopted a Code of
Business Conduct and Ethics ("Code") that applies to all of our employees,
officers and directors. This Code also meets the requirements of a code of
ethics under Item 406 of Regulation S-K. You can access the Code on
the "Governance" section of our website at www.txco.com. You may obtain a
printed copy of the Code by submitting a written request to our Corporate
Secretary at TXCO Resources Inc., 777 E. Sonterra Blvd., Suite 350, San Antonio,
Texas 78258.
ITEM
11. EXECUTIVE
COMPENSATION
The
information required by this Item is included in the "Director Compensation,"
"Executive Compensation," "Compensation Committee Report," and "Compensation
Committee Interlocks and Inside-participation" sections in the Proxy Statement
and is incorporated herein by reference.
|
ITEM 12.
|
SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
STOCKHOLDER MATTERS
|
The
information required by this Item is included in the Proxy Statement under the
heading "Security Ownership of Directors and Executive Officers" and is
incorporated herein by reference.
|
ITEM 13.
|
CERTAIN
RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
|
Information
required by this Item is included in the Proxy Statement under the heading
"Certain Relationships and Related Persons Transactions" and "Director
Independence," and is incorporated by reference.
ITEM
14. PRINCIPAL
ACCOUNTING FEES AND SERVICES
The
information required by this Item is included in the Proxy Statement under the
heading "Auditor Independence" and is incorporated herein by
reference.
PART
IV
ITEM
15. EXHIBITS,
FINANCIAL STATEMENT SCHEDULES
(A) The
following documents are being filed as part of this annual report on Form 10-K
after the signature page, commencing on page F-1.
|
(1)
|
Consolidated
Financial Statements:
|
|
|
Report
of Independent Registered Public Accounting Firm.
|
|
|
Consolidated
Balance Sheets, December 31, 2008 and December 31,
2007.
|
|
|
Consolidated
Statements of Operations, Years Ended December 31, 2008, 2007 and
2006.
|
|
|
Consolidated
Statements of Stockholders' Equity, Years Ended December 31, 2008, 2007
and 2006.
|
|
|
Consolidated
Statements of Cash Flows, Years Ended December 31, 2008, 2007 and
2006.
|
|
|
Notes
to Audited Consolidated Financial Statements.
|
|
|
|
|
(2)
|
Financial
Statement Schedules.
|
|
|
Schedule
II - Valuation and Qualifying Reserves.
|
|
|
|
|
|
All
other schedules for which provision is made in the applicable accounting
regulations of the Securities and Exchange Commission are omitted as the
required information is inapplicable or the information is presented in
the Consolidated Financial Statements or Notes
thereto.
|
|
(3)
|
Exhibits:
|
|
Exhibit
Number
|
Exhibit Description
|
Filed
Herewith
|
Form
|
|
Exhibit
|
Filing
Date
|
|
|
Agreement
and Plan of Merger, dated February 20, 2007, by and among Registrant,
Output Acquisition Corp., and Output Exploration,
LLC.
|
|
|
|
|
|
|
|
Amendment
No. 1 to Agreement and Plan of Merger listed in Exhibit 2.1
above.
|
|
|
|
|
|
|
|
Restated
Certificate of Incorporation of Registrant.
|
|
|
|
|
|
|
|
Certificate
of Designations, Preferences and Rights of Series D Convertible Preferred
Stock of Registrant.
|
|
|
|
|
|
|
|
Certificate
of Designations, Preferences and Rights of Series E Convertible Preferred
Stock of Registrant.
|
|
|
|
|
|
|
|
Amended
and Restated Bylaws of TXCO Resources Inc.
|
|
|
|
|
|
|
|
Specimen
common stock certificate.
|
|
|
|
|
|
|
|
Registration
Rights Agreement, dated November 20, 2007, among Registrant and the
parties listed therein.
|
|
|
|
|
|
|
|
Rights
Agreement, dated June 29, 2000, between Registrant and Fleet National
Bank.
|
|
|
|
|
|
|
|
Agreement
of Substitution and Amendment of Common Shares Rights Agreement dated
November 1, 2007, between Registrant and American Stock Transfer and Trust
Company.
|
|
|
|
|
|
|
|
Amendment
No. 2 to Rights Agreement, between Registrant and American Stock Transfer
and Trust Company.
|
|
|
|
|
|
|
|
Registration
Rights Agreement, dated March 4, 2008, among Registrant and the parties
listed therein.
|
|
|
|
|
|
|
|
Amendment
No. 3 to Rights Agreement, between Registrant and American Stock Transfer
and Trust Company.
|
|
|
|
|
|
|
|
Upper
Call Option Transaction, dated February 28, 2008, between Registrant and
the investor named therein.
|
|
|
|
|
|
|
|
Lower
Call Option Transaction, dated February 28, 2008, between Registrant and
the investor named therein.
|
|
|
|
|
|
|
|
Upper
Call Option Transaction, dated April 4, 2008, between Registrant and the
investor named therein.
|
|
|
|
|
|
|
|
Lower
Call Option Transaction, dated April 4, 2008, between Registrant and the
investor named therein.
|
|
|
|
|
|
|
|
Employment
Agreement between Registrant and James E. Sigmon, dated October 1,
1984.
|
|
|
|
|
|
|
|
1995
Flexible Incentive Plan
|
|
|
|
|
|
|
|
Amendment
to the 1995 Flexible Incentive Plan.
|
|
|
|
|
|
|
|
Amendment
to the 1995 Flexible Incentive Plan.
|
|
|
|
|
|
|
|
Amendment
to the 1995 Flexible Incentive Plan.
|
|
|
|
|
|
|
|
Form
of Amended and Restated Change of Control Letter
Agreement.
|
|
|
|
|
|
|
|
Form
of Restricted Stock Award.
|
|
|
|
|
|
|
|
Registration
Rights Agreement, dated April 4, 2006, between Registrant and several
investors named therein.
|
|
|
|
|
|
|
Exhibit
Number
|
Exhibit Description
|
Filed
Herewith
|
Form
|
|
Exhibit
|
Filing
Date
|
|
|
Amended
and Restated Credit Agreement, dated April 2, 2007, among Registrant, as
Borrower, Output Acquisition Corp., as a Guarantor, the other Guarantors
described therein, Bank of Montreal, as Lender and Administrative Agent
for the Lenders, the other Lenders party thereto, and BMO Capital Markets
Corp., as Arranger.
|
|
|
|
|
|
|
|
First
Amendment to the Amended and Restated Credit Agreement, dated July 25,
2007, among the same parties listed in Exhibit 10.22
above.
|
|
|
|
|
|
|
|
Amended
and Restated Term Loan Agreement, dated July 25, 2007, among the same
parties listed in Exhibit 10.22 above.
|
|
|
|
|
|
|
|
Senior
Secured Second Lien Term Loan Facility $20,000,000 Increased Facility
Amount Supplemental Commitment Letter, among the same parties listed in
Exhibit 10.22 above.
|
|
|
|
|
|
|
|
Securities
Purchase Agreement, dated November 20, 2007, among Registrant and the
parties listed therein.
|
|
|
|
|
|
|
|
Upper
Call Option Transaction, dated November 20, 2007, between Registrant and
the investor named therein.
|
|
|
|
|
|
|
|
Lower
Call Option Transaction, dated November 20, 2007, between Registrant and
the investor named therein.
|
|
|
|
|
|
|
|
Supplemental
fee letter dated January 14, 2008, among Registrant, BMO Capital Markets
and Bank of Montreal, et al.
|
|
|
|
|
|
|
|
Securities
Purchase Agreement dated February 28, 2008, by and among Registrant and
the parties listed therein.
|
|
|
|
|
|
|
|
Settlement
Agreement, dated March 15, 2008, among the Registrant, Third Point, Daniel
S. Loeb, and the other parties named therein.
|
|
|
|
|
|
|
|
Form
of Restricted Stock Award Agreement, dated March 18, 2008, for Messrs.
Jacob Roorda and Anthony Tripodo.
|
|
|
|
|
|
|
|
TXCO's
2005 Stock Incentive Plan, as amended and restated.
|
|
|
|
|
|
|
|
TXCO's
Overriding Royalty Purchase Plan.
|
|
|
|
|
|
|
|
Amended
and Restated Change in Control Letter Agreement for Gary
Grinsfelder.
|
|
|
|
|
|
|
|
Form
of Stock Option Award under TXCO's 2005 Stock Incentive
Plan.
|
|
|
|
|
|
|
|
Subsidiaries
of the Registrant at December 31, 2008
|
|
|
|
|
|
|
|
Consent
of Akin, Doherty, Klein & Feuge, P.C.
|
|
|
|
|
|
|
|
Consent
of DeGolyer and MacNaughton
|
|
|
|
|
|
|
|
Consent
of Cobb & Associates
|
|
|
|
|
|
|
|
Certification
of Chief Executive Officer required pursuant to Rule 13a-14(a) and
15d-14(a) of the Securities Exchange Act of 1934, as
amended.
|
|
|
|
|
|
|
|
Certification
of Chief Financial Officer required pursuant to Rule 13a-14(a) and
15d-14(a) of the Securities Exchange Act of 1934, as
amended.
|
|
|
|
|
|
|
|
Certification
of Chief Executive Officer required pursuant to 18 U.S.C. Section 1350 as
required by the Sarbanes-Oxley Act of 2002.
|
|
|
|
|
|
|
|
Certification
of Chief Financial Officer required pursuant to 18 U.S.C. Section 1350 as
required by the Sarbanes-Oxley Act of 2002.
|
|
|
|
|
|
|
|
Management
contract or compensatory plan or arrangement.
|
|
|
This
exhibit shall not be deemed "filed" for purposes of Section 18 of the
Securities Exchange Act of 1934, or otherwise subject to the liability of
that section, and shall not be deemed to be incorporated by reference into
any filing under the Securities Act of 1933 or the Securities Exchange Act
of 1934.
|
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.
TXCO RESOURCES
INC.
Registrant
|
March
16, 2009
|
By:
/
s/ James E.
Sigmon
|
|
|
James
E. Sigmon, Chief Executive Officer and
Chairman
of the Board
|
|
|
|
Pursuant
to the requirements of the Securities Exchange Act of 1934, this Report
has been signed below by the following persons on behalf of the registrant
and in the capacities and on the dates indicated.
|
|
|
|
Signatures
|
Title
|
Date
|
|
|
|
|
|
|
Chief
Executive Officer and
|
|
|
|
|
|
|
|
(Principal
Executive Officer)
|
|
|
|
|
|
|
|
|
March
16, 2009
|
|
|
|
|
|
|
|
|
/s/ Dennis B.
Fitzpatrick
|
|
March
16, 2009
|
|
|
|
|
|
|
|
|
/s/ Jon Michael
Muckleroy
|
|
March
16, 2009
|
|
|
|
|
|
|
|
|
|
|
|
March
16, 2009
|
|
|
|
|
|
|
|
|
|
|
|
March
16, 2009
|
|
|
|
|
|
|
|
|
|
|
|
March
16, 2009
|
|
|
|
|
|
|
|
|
|
|
|
March
16, 2009
|
|
|
|
|
|
|
|
|
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING
FIRM
The Board
of Directors and Stockholders
TXCO
Resources Inc. and Subsidiaries
San
Antonio, Texas
We have
audited the consolidated balance sheets of TXCO Resources Inc. and subsidiaries
(the "Company") as of December 31, 2008 and 2007, and the related consolidated
statements of operations, stockholders' equity and cash flows for each of the
three years in the period ended December 31, 2008. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our
audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our
opinion, the financial statements referred to above present fairly, in all
material respects, the consolidated financial position of TXCO Resources Inc.
and subsidiaries as of December 31, 2008 and 2007, and the consolidated results
of their operations and cash flows for each of the three years in the period
ended December 31, 2008, in conformity with
U. S.
generally accepted accounting principles.
The
accompanying consolidated financial statements have been prepared assuming that
the Company will continue as a going concern. As discussed in Note B
to the consolidated financial statements, the Company has a working capital
deficiency, was not in compliance with its current ratio debt covenant under its
bank facilities and has violated a provision of the certificate of designation
of their Series D and Series E Convertible Preferred Stock, all of which raise
substantial doubt about its ability to continue as a going concern.
Management's plans concerning these matters are also described in Note
B. The consolidated financial statements do not include any
adjustments that might result from the outcome of this uncertainty.
As
discussed in
Note A
to the consolidated financial
statements, in 2006 the Company changed its method of accounting for share-based
compensation and in 2007 the Company changed its method for accounting for
income taxes.
Our
audits referred to above included audits of the financial statement schedule
listed under Item 15. In our opinion, this financial statement schedule presents
fairly, in all material respects, in relation to the financial statements taken
as a whole, the information required to be set forth therein.
We have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the effectiveness of TXCO Resources Inc. and
subsidiaries' internal control over financial reporting as of December 31, 2008
based on criteria established in
Internal Control -- Integrated
Framework
issued by the Committee of Sponsoring Organizations of the
Treadway Commission and our report dated March 13, 2009 expressed an unqualified
opinion thereon.
/s/ Akin,
Doherty, Klein & Feuge, P.C.
San
Antonio, Texas
March 13,
2009
|
TXCO
RESOURCES INC.
Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
|
December
31
|
|
|
(in
thousands)
|
|
2008
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and natural gas sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prepaid
expenses and other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and Equipment
,
net - successful efforts
method
of accounting for oil and natural gas properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes
to audited consolidated financial statements.
|
TXCO
RESOURCES INC.
Consolidated
Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
|
December
31
|
|
|
(in
thousands, except shares and per share amounts)
|
|
2008
|
|
2007
|
|
Liabilities
And Stockholders' Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
payables and accrued liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Redeemable
preferred stock
|
|
|
|
|
|
Derivative
settlements payable
|
|
|
|
|
|
Preferred
dividends payable
|
|
|
|
|
|
Accrued
derivative obligation
|
|
|
|
|
|
Total
Current Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt, net of current portion
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued
derivative obligation
|
|
|
|
|
|
Asset
retirement obligation
|
|
|
|
|
|
Total
Long-Term Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
stock; authorized 10,000,000 shares;
Series
A & B, -0- shares issued and outstanding;
Series
C, -0- and 55,000 shares issued and outstanding;
Series
D, 56,909 and -0- shares issued and outstanding;
Series
E, 20,000 and -0- shares issued and outstanding
|
|
|
|
|
|
Common
stock, par value $0.01 per share; authorized
100,000,000
shares, issued 37,420,953 and 34,269,038 shares, and
outstanding
37,254,100 and 34,150,619
|
|
|
|
|
|
Additional
paid-in capital
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
other comprehensive income (loss), net of tax
|
|
|
|
|
|
Less
treasury stock, at cost, 166,853 shares and 118,419
shares
|
|
|
|
|
|
Total
Stockholders' Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and
Stockholders' Equity
|
|
|
|
|
|
See notes
to audited consolidated financial statements.
|
TXCO
RESOURCES INC.
Consolidated
Statements of
Operations
|
|
|
|
|
|
|
|
|
|
|
|
Years
Ended December 31
|
|
|
(in
thousands, except earnings per share data)
|
|
2008
|
|
2007
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
Oil
and natural gas sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment
and abandonments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
|
|
|
|
|
General
and administrative
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss)
gain on sale of assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative
mark-to-market gain
|
|
|
|
|
|
|
|
Derivative
settlements loss
|
|
|
|
|
|
|
|
Total
Other Income (Expense), Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before income taxes
|
|
|
|
|
|
|
|
Income
tax expense (benefit) --
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
(Loss) Income Available to Common Stockholders
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
(Loss) Per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average number of common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes
to audited consolidated financial statements.
|
Consolidated
Statements of Stockholders' Equity
|
|
|
Accumu-
|
|
|
|
|
|
|
|
Common
Stock
|
|
Preferred
Stock
|
Addi-tional
Paid-in
|
Retained
Earnings (Accumu- lated
|
lated
Other
Compre- hensive
|
Treas-ury
|
|
|
|
|
(in
thousands)
|
|
Shares
|
|
$
|
|
Shares
|
|
$
|
Capital
|
Deficit)
|
Loss
|
Stock
|
|
Total
|
|
Balance
at December 31, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise
of stock options & warrants
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance
of common stock - net of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
hedge gain - net of $372 in
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
at December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock
grants, net of forfeitures
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise
of stock options & warrants
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance
of common stock -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance
of convertible preferred - net of expenses of
$2,223
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash
stock compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase
of treasury stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
hedge loss - net of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
at December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock
grants, net of forfeitures
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise
of stock options & warrants
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance
of convertible preferred - net of expenses of $1,626
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conversion
of convertible preferred
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash
stock compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reclassification
of convertible preferred stock to
liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
-
|
|
-
|
|
|
|
Purchase
of treasury stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
hedge gain - net of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
at December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes
to audited consolidated financial statements.
|
TXCO
RESOURCES INC.
|
|
|
|
|
Consolidated Statements of Cash Flows
|
|
Years
Ended December 31
|
|
|
(in
thousands)
|
|
2008
|
|
2007
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
|
|
Depreciation,
depletion and amortization
|
|
|
|
|
|
|
|
Impairments,
abandonments and dry hole costs
|
|
|
|
|
|
|
|
Loss
(gain) on sale of assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess
tax benefits from stock-based compensation
|
|
|
|
|
|
|
|
Non-cash
compensation expense
|
|
|
|
|
|
|
|
Non-cash
derivative mark-to market (gain)
|
|
|
|
|
|
|
|
Non-cash
change in components of Other Comprehensive Income
|
|
|
|
|
|
|
|
Changes
in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prepaid
expenses and other
|
|
|
|
|
|
|
|
Accounts
payable and accrued expenses
|
|
|
|
|
|
|
|
Current
income taxes receivable (payable)
|
|
|
|
|
|
|
|
Net
cash provided by operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
and purchases of oil and natural gas properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase
of other equipment
|
|
|
|
|
|
|
|
Proceeds
from sale of assets
|
|
|
|
|
|
|
|
Net
cash used by investing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds
from bank credit facility
|
|
|
|
|
|
|
|
Payments
on bank credit facility
|
|
|
|
|
|
|
|
Payments
on installment and other obligations
|
|
|
|
|
|
|
|
Proceeds
from installment and other obligations
|
|
|
|
|
|
|
|
Issuance
of preferred stock, net of expenses
|
|
|
|
|
|
|
|
Purchase
of lower call option
|
|
|
|
|
|
|
|
Proceeds
from sale of upper call option
|
|
|
|
|
|
|
|
Payment
of preferred stock dividends
|
|
|
|
|
|
|
|
Proceeds
from issuance of common stock, net of expenses
|
|
|
|
|
|
|
|
Cost
of shares retired upon option exercises
|
|
|
|
|
|
|
|
Excess
tax benefits from stock-based compensation
|
|
|
|
|
|
|
|
Proceeds
from exercise of stock options
|
|
|
|
|
|
|
|
Purchase
of treasury shares
|
|
|
|
|
|
|
|
Net
cash provided by financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change
in Cash and Equivalents
|
|
|
|
|
|
|
|
Cash
and Equivalents at Beginning of Year
|
|
|
|
|
|
|
|
Cash
and Equivalents at End of Year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Discl
osures
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
paid for income taxes
|
|
|
|
|
|
|
|
See notes
to audited consolidated financial statements.
NOTE A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization and
Operations:
TXCO Resources Inc. ("TXCO" or "Company"),
formerly The Exploration Company of Delaware, Inc., is an independent energy
company engaged in the acquisition, exploration, development and production of
oil and natural gas properties. The Company's primary focus is on developing oil
and natural gas reserves on leases located in Texas. The Company also has
interests in leases in Oklahoma, Louisiana, South Dakota and North
Dakota.
Consolidation:
The financial statements include the accounts of the Company and its
wholly-owned subsidiaries. The subsidiaries engage in exploration, exploitation,
development, production of oil and natural gas prospects, including oil sands,
drill oil and natural gas wells for the consolidated group, own and operate a
natural gas gathering system and the operation of well drilling and servicing
equipment. All significant intercompany balances and transactions have been
eliminated in consolidation.
Revenue
Recognition:
The Company recognizes oil and natural gas revenue from its
interest in producing wells as the oil and natural gas is sold to third parties.
Gas gathering operations revenues are recognized upon delivery of the product to
third parties.
Reclassifications:
Certain amounts for
2007 and 2006, none of which were significant, have been reclassified to conform
to the 2008 presentation.
Cash and
Equivalents:
The Company considers all highly liquid investments with an
original maturity of three months or less to be cash and
equivalents.
Accounts
Receivable:
Accounts receivable is reported at outstanding principal net
of an allowance for doubtful accounts of approximately $27,000 at December 31,
2008, 2007 and 2006. The allowance for doubtful accounts is generally determined
based on the Company's historical losses, as well as a review of specific
accounts. Accounts are charged off when collection efforts have failed and the
account is deemed uncollectible. The Company normally does not charge interest
on accounts receivable.
Oil and Natural
Gas Properties:
The Company uses the successful efforts method of
accounting for its oil and natural gas activities. Costs to acquire mineral
interests, developmental 3-D seismic costs, development wells, and costs to
drill and equip exploratory wells that find proved reserves are capitalized.
Costs, net of salvage value, for exploratory wells that do not find proved
reserves, geological and geophysical costs, 2-D seismic costs, and costs of
carrying and retaining unproved properties are expensed as
incurred.
Management
considers 3-D seismic shoots over the proved area of an oil or natural gas
reservoir as developmental in nature. The Company uses its 3-D seismic database
when selecting drilling sites, assessing recompletion opportunities, determining
the cause when performance of a producing property is not as expected, as well
as qualifying reservoir size and determining probable extensions and/or drainage
areas for existing fields. The Company amortizes the cost of its capitalized
developmental 3-D seismic shoots over a 60-month period.
Any well
not drilled within the proved area of an oil or natural gas reservoir targeting
a known productive depth is considered exploratory. Costs for exploratory wells
in-progress are capitalized until a determination is made that no proven
reserves are likely to be realized from the well's various potential intervals.
If the determination is made that no proven reserves are likely to be realized
from a target interval, the costs associated with that target interval are
expensed. Costs associated with wells having several potential intervals remain
capitalized until the determination of proven reserves is made for the final
interval. Costs attributed to lower zones may be written off while upper zones
remain in-progress due to planned re-completion efforts.
Depreciation,
depletion and amortization ("DD&A") of oil and natural gas properties is
computed using the unit-of-production method based upon recoverable reserves as
determined by the Company's independent reservoir engineers. Depletion of
coalbed methane properties begins following the dewatering phase of each coalbed
methane project.
Impairment of
Long-Lived Assets:
The Company reviews its long-lived assets
for impairment at least annually or when events or changes in circumstances
indicate that the carrying value of such assets may not be
recoverable.
For
proved oil and natural gas properties, management estimates the expected future
cash flows related to the properties, generally on a field basis. If the
expected future cash flows exceed the carrying value of the asset, no impairment
is recognized. If the carrying value of the asset exceeds the expected future
cash flows, an impairment exists, and it is measured by the excess of the
carrying value over the estimated fair value of the asset. Impairments
recognized are permanent and may not be restored. The Company recognized
impairments on its proved oil and natural gas properties of $1,609,000 in 2008,
$1,578,000 in 2007 and $1,556,000 in 2006.
NOTE
A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - continued
For
unproved properties, impairment is based on the Company's plans for future
development and other activities impacting the life of the property and the
ability of the Company to recover its investment. When the Company believes the
costs of the unproved property are no longer recoverable, an impairment charge
is recorded based on the estimated fair value of the asset. As a result of such
assessment, the Company recorded total impairment charges of $13,931,000 in
2008, of which $11,337,000 related to its San Miguel oil sands project and
$2,594,000 related to other drilling. Impairments on unproved properties totaled
$405,000 in 2007 and $166,000 in 2006.
Other Property
and Equipment:
Other property and equipment is recorded at cost.
Depreciation is computed using the straight-line method over the estimated
useful lives of the assets ranging from five to fifteen years. Major renewals
and betterments are capitalized while repairs are expensed as
incurred.
Income
Taxes:
The Company follows the liability method of accounting for income
taxes under which deferred tax assets and liabilities are recognized for the
future tax consequences. Accordingly, deferred tax assets and liabilities are
determined based on the temporary differences between the financial statement
and tax basis of assets and liabilities, using enacted tax rates in effect for
the year in which the differences are expected to reverse. The Company is also
subject to state income taxes in the states in which it operates.
Earnings (Loss)
Per Share:
Basic earnings per share ("EPS") is computed by dividing net
income, adjusted for preferred stock dividends, by the weighted average number
of common shares outstanding during each year. The diluted earnings per share
calculation is similar to basic EPS, except the denominator includes dilutive
common stock equivalents and the income included in the numerator excludes the
effects of the impact of dilutive common stock equivalents, if any. Common
equivalent shares are excluded from the computation in periods in which they
have an anti-dilutive effect. The Company uses the treasury stock method to
calculate the impact of outstanding stock options and warrants. Any stock option
or warrant for which the exercise price exceeds the average market price over
the period would have an anti-dilutive effect on earnings per common share and,
accordingly, would be excluded from the calculation. In order to determine the
potential dilution from convertible preferred stock, the Company utilizes the
"if-converted" method. If the written call option were "in-the-money," the
Company would use the "reverse treasury stock method" to determine the dilutive
impact.
Concentrations of
Credit Risk:
The Company's financial
instruments that are exposed to concentrations of credit risk consist primarily
of cash equivalents and accounts receivable. The Company places its temporary
cash investments with major financial institutions which, from time-to-time, may
exceed federally insured limits, and believes the risk of loss is minimal. At
December 31, 2008, the Company had no deposits in excess of federal insurance
protection, since all of the banks holding our funds were participating in the
FDIC's Temporary Liquidity Guarantee Program. Substantially all of the Company's
accounts receivable result from oil and natural gas sales or joint interest
billings to third parties in the oil and natural gas industry. Collateral is
generally not required. This concentration of customers and joint interest
owners may impact the Company's overall credit risk in that these entities may
be similarly affected by changes in economic and other conditions. Historically,
the Company has not experienced credit losses on such receivables.
Hedging
Contracts:
The Company occasionally enters into derivative contracts,
primarily options and swaps, to hedge future natural gas and crude oil
production in order to mitigate the risk of changes in market price, as well as
interest rate swaps to effectively lock the interest rate on a portion of its
bank debt. All derivatives are recognized on the balance sheet and measured at
fair value (marked to market). The Company determines the accounting policy of
its hedges on a case by case basis. Unrealized changes in the fair value of
derivatives classified as investments, if any, are recognized in earnings,
while unrealized changes in the fair value of derivatives classified as cash
flow hedges are recognized as other comprehensive income or loss directly as a
component in Stockholders' Equity.
Fair Value of
Financial Instruments:
The following methods
and assumptions were used to estimate the fair value of each class of financial
instrument held by the Company:
|
·
|
Current
assets and current liabilities -- The carrying value approximates fair
value due to the short maturity of these
items.
|
|
·
|
Long-term
debt -- The fair value of the Company's long-term debt is based on
secondary market indicators. Since the Company's debt is not quoted,
estimates are based on each obligation's characteristics, including
remaining maturities, interest rate, credit rating, collateral,
amortization schedule and liquidity. The carrying amount approximates fair
value.
|
|
·
|
Commodity
and interest rate hedging contracts -- The Company's derivative
instruments are adjusted to, and recorded at, fair value on the balance
sheet.
|
NOTE
A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - continued
Use of
Estimates:
The preparation of financial statements in conformity with U.
S. generally accepted accounting principles requires management to make
estimates and assumptions. These estimates and assumptions affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements, as well as the reported
amounts of revenues and expenses during the reporting period. Actual results
could differ from those estimates. Estimates that may significantly impact the
Company's financial statements include reserves, depletion and impairment on oil
and natural gas properties.
Government
Regulations:
The Company's oil and
natural gas operations are subject to federal, state and local provisions
regulating the discharge of materials into the environment. Management believes
that its current practices and procedures for the control and disposition of
such wastes substantially comply with applicable federal and state
requirements.
401(k)
Plan:
The Company has a 401(k) plan covering substantially all employees
with over three months of service and 21 years of age. At its discretion, the
Company may match a certain percentage of the employees' contributions to the
Plan. The matching percentage is determined by the Board of Directors.
Contributions to the Plan by the Company totaled $149,400 in 2008, $154,100 in
2007 and $75,200 in 2006.
Restoration,
Removal and Environmental Matters:
The estimated costs of restoration and
removal of producing property well sites are accrued when it is probable that a
liability has been incurred and the amount of remediation costs can be
reasonably estimated. For wells drilled during the year, the liability is
recognized, based on target depth, as the wells are spud. See
Note E.
Recent Accounting
Pronouncem
ents:
Financial
Accounting Standards Board ("FASB")
FASB Interpretation No. 48,
"Accounting for Uncertainty in Income Taxes, an interpretation of FASB
Statement 109":
Interpretation 48 prescribes a recognition threshold
and a measurement attribute for the financial statement recognition and
measurement of a tax position taken or expected to be taken in a tax return.
Benefits from tax positions should be recognized in the financial statements
only when it is more likely than not that the tax position will be sustained
upon examination by the appropriate taxing authority that would have full
knowledge of all relevant information. A tax position that meets the
more-likely-than-not recognition threshold is measured at the largest amount of
benefit that is greater than fifty percent likely of being realized upon
ultimate settlement. Tax positions that previously failed to meet the
more-likely-than-not recognition threshold should be recognized in the first
subsequent financial reporting period in which that threshold is met. Previously
recognized tax positions that no longer meet the more-likely-than-not
recognition threshold should be derecognized in the first subsequent financial
reporting period in which that threshold is no longer met. Interpretation 48
also provides guidance on the accounting for and disclosure of unrecognized tax
benefits, interest and penalties. Interpretation 48 was effective for the
Company on January 1, 2007, and did not have a significant impact on its
financial statements.
FASB Statement of Accounting
Standard No. 157,
"
Fair Value Measurement
"
(
"
SFAS No. 157
"
)
: SFAS No. 157, issued in
September 2006, defines fair value, establishes a framework for measuring fair
value, and expands disclosures about fair value measurements. The standard
applies whenever other standards require (or permit) assets or liabilities to be
measured at fair value, but does not expand the use of fair value in any new
circumstances. In February 2008, the FASB granted a one-year deferral of the
effective date of this statement as it applies to non-financial assets and
liabilities that are recognized or disclosed at fair value on a nonrecurring
basis (e.g. those measured at fair value in a business combination and goodwill
impairment). SFAS No. 157 is effective for all recurring measures of financial
assets and financial liabilities (e.g. derivatives and investment securities)
for financial statements issued for fiscal years beginning after November 15,
2007. We adopted SFAS No. 157 effective January 1, 2008, and its adoption did
not have a material impact on our financial position or results of
operations.
FASB Statement of Accounting
Standard
No.
159
,
"
The Fair Value Option for Financial
Assets and Financial Liabilities
"
(
"
SFAS No. 159
"
)
: SFAS No. 159, issued in
February 2007, allows entities the option to measure eligible financial
instruments at fair value as of specified dates. Such election, which may be
applied on an instrument by instrument basis, is typically irrevocable once
elected. SFAS No. 159 is effective for fiscal years beginning after November 15,
2007. We adopted SFAS No. 159 effective January 1, 2008, but did not elect
to apply the fair value option to eligible assets and liabilities during the
year ended December 31, 2008.
NOTE
A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - continued
In
December 2007, the FASB issued SFAS No. 141(R), "Business
Combinations" ("SFAS No. 141(R)"), which replaces SFAS No. 141.
SFAS No. 141(R) establishes principles and requirements for how an acquirer
recognizes and measures in its financial statements the identifiable assets
acquired, the liabilities assumed, any non-controlling interest in the acquiree
and the goodwill acquired. The Statement also establishes disclosure
requirements, which will enable users to evaluate the nature and financial
effects of the business combination. SFAS No. 141(R) is effective for
fiscal years beginning after December 15, 2008. The adoption of
SFAS No. 141(R) will have an impact on accounting for business combinations
once adopted, but the effect is dependent upon acquisitions at that
time.
In
December 2007, the FASB issued SFAS No. 160, "Noncontrolling Interests
in Consolidated Financial Statements -- an amendment of Accounting Research
Bulletin No. 51" ("SFAS No. 160"), which establishes accounting
and reporting standards for ownership interests in subsidiaries held by parties
other than the parent, the amount of consolidated net income attributable to the
parent and to the non-controlling interest, changes in a parent's ownership
interest and the valuation of retained non-controlling equity investments when a
subsidiary is deconsolidated. The Statement also establishes reporting
requirements that provide sufficient disclosures that clearly identify and
distinguish between the interests of the parent and the interests of the
non-controlling owners. SFAS No. 160 is effective for fiscal years
beginning after December 15, 2008. The Company does not currently have
non-controlling interests in any of its subsidiaries.
In March
2008, the FASB released SFAS No. 161, "Disclosures about Derivative
Instruments and Hedging Activities -- an amendment of FASB Statement
No. 133." This Statement is effective for financial statements issued for
fiscal years and interim periods beginning after November 15, 2008, which
for TXCO is the interim period ending March 31, 2009. This statement requires
that objectives for using derivative instruments be disclosed in terms of
underlying risk and accounting designation, in order to better convey the
purpose of derivative use in terms of the risks that we are intending to manage.
The Company is currently assessing and evaluating the new disclosure
requirements for its derivative instruments.
In May
2008, the FASB issued FASB Staff Position (FSP) Financial Accounting Standard
142-3, Determination of the Useful Life of Intangible Assets, which is effective
for fiscal years beginning after December 15, 2008 and for interim periods
within those years, which for us is the interim period ending March 31, 2009.
FSP FAS 142-3 provides guidance on the renewal or extension assumptions
used in the determination of the useful life of a recognized intangible asset.
The intent of FSP FAS 142-3 is to better match the useful life of the
recognized intangible asset to the period of the expected cash flows used to
measure its fair value. The Company does not expect FSP FAS 142-3 to have a
material effect on its consolidated financial statements.
In
December 2008, the SEC published a final rule entitled "Modernization of
Oil and Gas Reporting". The new rule permits the use of new technologies to
determine proved reserves if those technologies have been demonstrated to lead
to reliable conclusions about reserves volumes. The new requirements also will
allow companies to disclose their probable and possible reserves to investors.
In addition, the new disclosure requirements require companies to: (a) report
the independence and qualifications of its reserves preparer or auditor; (b)
file reports when a third party is relied upon to prepare reserves estimates or
conducts a reserves audit; and (c) report oil and natural gas reserves using an
average price based upon the prior 12-month period rather than year-end prices.
The use of average prices will affect future impairment and depletion
calculations.
The new
disclosure requirements are effective for annual reports on Forms 10-K for
fiscal years ending on or after December 31, 2009. A company may not apply
the new rules to disclosures in quarterly reports prior to the first annual
report in which the revised disclosures are required. The Company has not yet
determined the impact of this Final Rule on its disclosures, financial position
or results of operations, which will vary depending on changes in commodity
prices.
NOTE
B - GOING CONCERN
The
accompanying financial statements have been prepared assuming the Company will
continue as a going concern. The Company had a working capital deficiency of
$256.9 million, including reclassifications to current liabilities of $153.0
million from long-term debt and $66.9 million from preferred stock. The Company
had $49.7 million in trade payables at December 31, 2008, which if not timely
paid could result in liens filed against the Company's properties or withdrawal
of trade credit provided by vendors, which in turn could limit the Company's
availability to conduct operations on its properties.
At
December 31, 2008, the Company was not in compliance with the current ratio
covenant under its senior credit facility. In accordance with the credit
agreements, the lenders have the right to accelerate the debt as a result of the
covenant violation. Additionally, the lenders are scheduled to perform a
redetermination of the borrowing base for the Company in April or May 2009,
which may result in a reduction of the borrowing base. While the Company's
lenders have not informed us of an intent to exercise their right to accelerate
the payment schedule on the debt, neither have they granted us a waiver or
relief of the default at this time.
Due to
cross-default provisions in the certificate of designations for the convertible
preferred stock, the holders of that stock can demand redemption of the
preferred stock, although the obligation to redeem such stock is suspended until
the earlier of October 31, 2012 or satisfaction in full of the Company's
obligations under its term loan agreement and senior credit
agreement.
The
Company is subject to contractual obligations to drill wells under separate
farm-out agreements with EnCana and Anadarko (the "Partners") that require TXCO
to drill and complete, at its expense, and carry the Partners on six additional
wells during 2009. If the Company does not perform under these agreements, it is
subject to substantial payments as liquidated damages under the agreements.
While TXCO hopes to complete the wells in accordance with the agreements, it may
be unable to obtain adequate funding. TXCO and EnCana have agreed to a
three-month extension from the July 2009 deadline in their original agreement,
and are in discussions for a further extension. The deadline under the Anadarko
agreement is December 2009.
TXCO's
efforts to improve its liquidity position will be very challenging given the
current economic climate. Management is actively pursuing options to improve the
Company's liquidity position as quickly as possible. This includes drilling
joint ventures, sale of certain assets, reduction in staff, shutting down
certain operations, and other capital raising transactions. This plan is
designed to ease our immediate liquidity problems.
The
Company has also retained Goldman, Sachs & Co. as a financial advisor for a
strategic alternatives review designed to enhance shareholder
value. All options are under consideration, including the potential
sale of leasehold interests or other assets, a merger or sale of the Company. No
formal decisions have been made and no agreements have been reached at this
time. There can be no assurance the Company will be successful in any of these
efforts.
These
factors raise substantial doubt about the Company's ability to continue as a
going concern.
NOTE
C - PROPERTY AND EQUIPMENT
Property
and equipment consists of the following at December 31:
|
(in
thousands)
|
|
2008
|
|
2007
|
|
Oil
and natural gas properties
|
|
|
|
|
|
Other
property and equipment
|
|
|
|
|
|
Total
Property and Equipment
|
|
|
|
|
|
Accumulated
depreciation, depletion and amortization
|
|
|
|
|
|
Reserve
for impairment on unproved properties
|
|
|
|
|
|
Reserve
for impairment on oil sands project
|
|
|
|
|
|
Net
Property and Equipment
|
|
|
|
|
|
2007
Acquisition:
On April 2, 2007, the Company closed on the purchase of
Output Exploration LLC, a privately held, Houston-based exploration and
production firm, for $95.6 million. The consideration for the purchase was $91.6
million in cash, subject to certain adjustments, and $4.0 million of TXCO common
stock. Compared to pre-acquisition levels, the transaction effectively doubled
our proved reserves and increased current oil and natural gas production by
nearly two thirds. See
Note M
.
2008 Acquisitions
& Disposals:
During 2008, TXCO acquired additional interests in its
Fort Trinidad acreage in East Texas and sold 15 non-core properties in South
Texas. Both of the properties were part of the Output acquisition during 2007.
Neither transaction reflected a material acquisition or disposal for
TXCO.
NOTE
D - LONG-TERM
DEBT
Debt
consists of the following at December 31:
|
($'s
in thousands)
|
|
2008
|
|
2007
|
|
Note
payable to a financial institution under term loan agreement, with
interest at LIBOR or the base rate plus applicable margin, quarterly
payments of interest only, with maturity in 2012 and collateralized by
certain of the Company's proven oil and natural gas
properties.
|
|
|
|
|
|
Note
payable to a financial institution under senior credit agreement, with
interest at LIBOR or prime plus applicable margin, quarterly payments of
interest only, with maturity in 2011 and collateralized by certain of the
Company's proven oil and natural gas properties.
|
|
|
|
|
|
Note
payable to a financial institution under a revolving credit facility with
interest at The Wall Street Journal prime rate plus 1.00%, monthly
payments of interest plus $83, with maturity in 2012 and collateralized by
TXCO subsidiaries' drilling rigs.
|
|
|
|
|
|
Installment
note to finance company on insurance policies, with interest at 4.89%,
monthly installments of $65, and unsecured.
|
|
|
|
|
|
Installment
notes to finance company on insurance policies, with interest from 6.50%
to 7.95%, monthly installments of $60, and
unsecured.
|
|
|
|
|
|
|
|
|
|
|
|
|
The
following is a schedule of principal maturities of debt as of December 31, 2008,
which reflects the bank debt as current due to the covenant
violations:
|
Year Ended December 31,
|
|
Amount
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank Credit
Facilities:
As disclosed in TXCO's
Form 8-K filed with the SEC on February 27, 2009, the Company is in violation of
the Current Ratio covenant under its term loan agreement and senior credit
agreement. As a result of that violation, all outstanding balances under these
agreements have been classified as current liabilities on the Consolidated
Balance Sheet as of December 31, 2008.
Senior Credit
Agreement
--
At
December 31, 2008, the Company had a $125 million senior revolving credit
facility with the Bank of Montreal (the "SCA"). The SCA was entered into in
April 2007, amended in July 2007, and expires in April 2011.
At
December 31, 2008, the borrowing base was $55 million, $50 million was
outstanding at a weighted average interest rate of 4.0% and the unused borrowing
base was $5 million. The SCA is secured by a first-priority security interest in
substantially all of TXCO's and certain of its subsidiaries' assets, including
proved oil and natural gas reserves and in the equity interests of such
subsidiaries. In addition, TXCO's obligations under the SCA are guaranteed by
these certain subsidiaries. As of March 13, 2009, the balance outstanding under
the SCA was $50 million, with a weighted average interest rate of 4.00%, using
the base rate option, and the unused borrowing base was $5 million.
Loans
under the SCA are subject to floating rates of interest based on (1) the
total amount outstanding under the SCA in relation to the borrowing base and
(2) whether the loan is a LIBOR loan or a base rate loan. LIBOR loans bear
interest at the LIBOR rate (for the applicable 1-, 2-, 3- or 6-month maturity
chosen by the Company) plus the applicable margin, and base rate loans bear
interest at the base rate plus the applicable margin. The applicable margin
varies with the ratio of total outstanding to the borrowing base. For base rate
loans it ranges from zero to 100 basis points and for LIBOR rate loans it ranges
from 150 to 250 basis points. The SCA allows the lenders to increase the
interest rate by 200 basis points at any time we are in default under the
SCA.
Under the
SCA, TXCO is required to pay a commitment fee on the difference between amounts
available under the borrowing base and amounts actually borrowed. The commitment
fee is (1) 0.375%, so long as the ratio of amounts outstanding under the SCA to
the borrowing base is less than 30%, and (2) 0.50%, in the event such ratio is
30% or greater. Borrowings under the SCA may be repaid and reborrowed from time
to time without penalty.
NOTE
D - LONG-TERM DEBT - continued
Term Loan
Agreement
--
At
December 31, 2008, the Company had a $100 million five-year term loan facility
with Bank of Montreal (the "TLA") and certain other financial institutions party
thereto with a current interest rate of 5.00%. The TLA is secured by a
second-priority security interest in substantially all of TXCO's and certain of
its subsidiaries' assets, including proved oil and natural gas reserves and in
the equity interests of such subsidiaries. Loans under the TLA are subject to
floating rates of interest equal to, at TXCO's option, the LIBOR rate plus 4.50%
or the base rate plus 3.50%. The "LIBOR rate" and the base rate are calculated
in the same manner as under the SCA. See additional discussion regarding the
interest rate swap in
Note L
.
Borrowings
under the TLA may be repaid (but not reborrowed). Additionally, no prepayments
are permitted if the ratio of the total amount outstanding under the SCA to the
borrowing base thereunder exceeds 75% or if any default exists under the
SCA.
Both the
SCA and the TLA contain certain restrictive covenants, as defined in the
agreements, which, among other things, limit the incurrence of additional debt,
investments, liens, dividends, redemptions of capital stock, prepayments of
indebtedness, asset dispositions, mergers and consolidations, transactions with
affiliates, derivative contracts, sale leasebacks and other matters customarily
restricted in such agreements. The amended SCA and TLA require TXCO and its
subsidiaries to meet a maximum consolidated leverage ratio of 3.00 to 1.00, a
minimum current assets to current liabilities ratio of 1.00 to 1.00 ("Current
Ratio"), a minimum interest coverage ratio of 2.00 to 1.00 and a minimum net
present value to consolidated total debt ratio of 1.50 to 1.00. The ratios are
calculated on a quarterly basis and include certain adjustments based on the
definitions in the agreements. The Company was in compliance with all such
covenants at December 31, 2008, except the Current Ratio covenant. Both
agreements also contain customary events of default. If an event of default
occurs and is continuing, lenders with a majority of the aggregate outstanding
term loans may require Bank of Montreal to declare all amounts outstanding under
the SCA and TLA to be immediately due and payable. As a result of the covenant
violation, all borrowings under the SCA and TLA have been classified as current
liabilities in our Consolidated Balance Sheet as of December 31, 2008. We are
continuing discussions with the lenders regarding a waiver of certain covenants,
whereby they would refrain from exercising their rights under the SCA and TLA as
a result of this default. There can be no assurance that we will be able to
obtain a waiver or obtain other relief from the lenders.
Drilling Rig
Financing
--
At
December 31, 2008, the Company had a $4.0 million senior revolving credit
facility with Western National Bank (the "Rig Loan"). The Rig Loan was entered
into in December 2008. At December 31, 2008, the borrowing base was $4.0
million, all of which was outstanding at a weighted average interest rate of
4.25%. The Rig Loan is secured by a first-priority security interest in TXCO
subsidiaries' drilling rigs. The Rig Loan bears interest at the prime rate as
published in The Wall Street Journal plus 1.00%. Under the rig loan, TXCO's
subsidiary is required to pay interest monthly. In addition, the borrowing base
declines by $83,333 per month, and may require a cash payment of the same if the
line of credit is funded above the borrowing base after this monthly
reduction.
The Rig
Loan also contains certain restrictive covenants, as defined in the agreements,
which, among other things, limit the incurrence of additional debt, investments,
liens, dividends, redemptions of capital stock, prepayments of indebtedness,
asset dispositions, mergers and consolidations, transactions with affiliates,
derivative contracts, sale leasebacks and other matters customarily restricted
in such agreements. The Rig Loan agreements require TXCO Drilling to meet a
maximum debt service coverage ratio of 1.50 to 1.00, a minimum current assets to
current liabilities ratio of 3.00 to 1.00, a minimum tangible net worth of
$8,500,000 and a maximum debt to tangible net worth ratio of 1.00 to 1.00. The
ratios are calculated on a quarterly basis. The Company was in compliance with
all such covenants at December 31, 2008. The agreements also contain customary
events of default. The outstanding balance due under this note is classified as
current, as a result of the covenant violation under the SCA and TLA, due to a
cross-default provision. The lender has the right to increase the interest rate
and/or accelerate the payment schedule due to the default.
NOTE E - ASSET RETIREMENT COSTS AND OBLIGATIONS
Statement
of Financial Accounting Standards No. 143 "Accounting for Asset Retirement
Obligations" requires that the fair value of a liability for an asset retirement
obligation be recognized in the period in which it is incurred if a reasonable
estimate of fair value can be made. In addition, the associated asset retirement
costs must be capitalized as part of the carrying amount of the long-lived
asset.
The
following is a reconciliation of the asset retirement obligation for the years
presented in the Consolidated Balance Sheets:
|
|
|
Balance,
December 31, 2006
|
|
|
|
Revision
to estimated plugging costs on existing liabilities
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
December 31, 2007
|
|
|
|
Revision
to estimated plugging costs on existing liabilities
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
December 31, 2008
|
|
|
|
|
(1)
|
Upward
revisions due to escalating costs in the field in excess of normal
inflation.
|
(2) Asset
retirement obligation of Output Exploration LLC when TXCO acquired
it.
NOTE
F - COMMITMENTS AND CONTINGENCIES
The
Company leases its primary office space through March 2014, and has maintenance
contracts on certain equipment through November 2011. The Company incurred rent
expense of approximately $1,842,000 in 2008, $1,531,000 in 2007 and $939,000 in
2006. Future minimum rentals, for the next five years, under all non-cancelable
leases and contracts are as follows:
|
Year Ended December 31,
|
|
Amount
(in thousands
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Registration
Rights
: In November 2007 and March 2008, the Company entered into
Registration Rights Agreements ("RRAs") with the buyers listed therein whereby
the Company agreed to file a registration statement, within a certain time
period, covering the resale of the shares of common stock to be acquired by the
buyers upon conversion of their preferred stock, described in
Note G
. The Company filed a registration statement with the
SEC in April 2008 that was amended in May and July of 2008, and declared
effective in August 2008. Should the registration statement's effectiveness not
be maintained in accordance with the terms of the RRA, the Company has agreed to
pay affected buyers cash payments totaling 1% of the aggregate purchase price of
those buyers' registrable securities included in such registration statement on
each of certain specified dates, up to a maximum amount of 10% of the preferred
stock's stated value. The aggregate stated value of the Series D and Series E
preferred stock is currently $76.9 million therefore the maximum amount of
payment would be $7.7 million. Since TXCO's management does not consider the
likelihood of this outcome to be probable, no contingent liability was
accrued.
Pending
or Threatened Litigation:
The Company is involved in various claims and
legal actions arising in the ordinary course of business. Subsequent to year end
the Company was named as a defendant in three separate cases alleging various
breaches regarding certain oil and natural gas leases covering an aggregate of
approximately 40,000 gross acres in its Maverick Basin leaseholds. The Company
and its counsel believe the suits are without merit and the Company intends to
vigorously defend each lawsuit. The Company believes it is unlikely that the
final outcome of any of the claims or proceedings to which it is a party would
have a material adverse effect on the Company's financial position or results of
operations.
NOTE G - STOCKHOLDERS' EQUITY AND REDEEMABLE PREFERRED
STOCK
Redeemable
Preferred Stock:
The Company has authorized 10 million shares of
preferred stock. At December 31, 2008, there were no Series A or Series B
preferred shares issued and outstanding. The Board of Directors has not
established terms of the stock. In 2003, the Company issued 16,000 shares of
redeemable preferred stock, Series B, all of which was redeemed in
2005.
2007 Issuance
- In
November 2007, the Company issued 55,000 shares of convertible perpetual
preferred stock, Series C (the "Series C Preferred Stock"). The Series C
Preferred Stock had a stated value of $1,000 per share and a par value of $0.01
per share. It was issued in a private placement, raising a total of
approximately $52.8 million after offering costs. The Series C Preferred Stock
was convertible into the Company's common stock at a price of $14.48 per
share, aggregating approximately 3.8 million shares. Holders of the Series
C Preferred Stock were entitled to receive dividends, payable quarterly in cash
or, at the Company's option, the Company's common stock, at the rate of 6.5% per
annum, which increases to 12% under certain circumstances, and had preference
over the common stock in the event of liquidation. The Series C Preferred Stock
required TXCO and its subsidiaries to not exceed a maximum consolidated leverage
ratio of 3.65 to 1.00 (as defined in the amended SCA). See below for discussion
of the issuance of Series E Preferred Stock and the exchange of Series D
Preferred Stock for the Series C Preferred Stock in 2008. The Series C Preferred
Stock provided that the holders thereof had the right to request redemption of
such shares at a redemption price of, in general, an amount equal to the product
of (a) 115% and (b) the sum of such shares' stated value, accrued and unpaid
dividends, and any make-whole amounts related to preferred stock
dividends. However, our obligation to pay the redemption price of any
preferred stock requested to be redeemed is suspended until the earlier of (a)
October 31, 2012 or (b) the date that all of our obligations under the
senior indebtedness agreements have been satisfied.
2008 Issuances
- On
February 28, 2008, TXCO entered into an agreement related to the private
placement of an aggregate of $20 million of shares of the Company's Series E
Convertible Preferred Stock (the "Series E Preferred Stock") and the exchange of
the issued and outstanding shares of its Series C Preferred Stock for shares of
its Series D Convertible Preferred Stock (the "Series D Preferred Stock")
pursuant to the Securities Purchase Agreement among the Company and the buyers
listed therein. Closing and funding occurred in March 2008. The Series D
Preferred Stock has the same terms that were contained in the Series C Preferred
Stock.
The
Series E Preferred Stock has a stated value of $1,000 per share and a par value
of $0.01 per share, and is currently convertible into shares of the Company's
common stock at a conversion price of $17.36 per share, aggregating
approximately 1.2 million shares. Holders of the Series E Preferred Stock are
entitled to receive dividends, payable quarterly at the rate of 6% per annum,
which increases to 12% under certain circumstances, and have preference over the
common stock in the event of liquidation. The Series E Preferred Stock requires
TXCO and its subsidiaries to not exceed a maximum consolidated leverage ratio of
3.65 to 1.00 (as defined in the amended SCA). The Series E Preferred Stock
provides that the holders thereof have the right, upon the occurrence of certain
events, to request that the Company redeem such shares at a redemption price of,
in general, an amount equal to the product of (a) 115% and (b) the sum of such
shares' stated value, accrued and unpaid dividends, and any make-whole amounts
related to preferred stock dividends. However, the Company's
obligation to pay the redemption price of any preferred stock requested to be
redeemed is suspended until the earlier of (a) October 31, 2012 or (b) the date
that all of the Company's obligations under the senior indebtedness agreements
have been satisfied.
Additionally,
one of the purchasers of the Series D Preferred Stock exercised its right to
purchase additional shares of Series D Preferred Stock. The purchaser acquired
an additional 13,909 shares of Series D Preferred Stock in April 2008. All other
rights to acquire additional shares of Series D Preferred Stock expired
unexercised in late March 2008.
With each
issuance of Preferred Stock, TXCO concurrently entered into call spread options
related to the newly issued preferred shares that may offset the dilution to
common shares caused by a conversion of the Preferred Stock. Each call spread is
a combination of a bought and a sold call option. See the "Call Options" section
that follows for more information.
2008 Conversions
- In
October 2008, holders of 12,000 shares of TXCO Series D Preferred Stock, with an
aggregate stated value of $12.0 million and a conversion price of $14.48,
converted those shares into a total of approximately 829,000 shares of TXCO's
common stock. An additional 231,000 shares of TXCO common stock were issued for
the make-whole provision related to preferred dividends. The shares of common
stock to be issued upon conversion of TXCO's convertible preferred stock and
payment of related dividends in common stock were registered with the SEC in
August 2008.
Year End Status
- The
following table summarizes the outstanding convertible preferred stock at
December 31, 2008:
|
Series
|
Shares
Outstanding
|
Aggregate
Stated Value
|
Dividend
Rate
|
Conversion
Price
|
Underlying
Common Shares
*
|
|
D
|
56,909
|
$56,909,000
|
6.5%
|
$14.48
|
3,930,179
|
|
E
|
20,000
|
$20,000,000
|
6.0%
|
$17.36
|
1,152,074
|
*
This excludes potential make-whole provision shares. The number of make-whole
shares issuable is dependent on the remaining time from any conversion event to
the three year anniversary of issuance, and the price of our common stock in a
10-day period before conversion.
NOTE
G - STOCKHOLDERS' EQUITY AND REDEEMABLE PREFERRED STOCK - continued
At the
time of issuance all of our convertible preferred stock qualified as equity in
accordance with FASB 150 and related guidance. The Certificates of
Designations associated with each issuance provided for redemption rights in the
event of a default on the Company's bank credit facilities. As a result of the
default under those bank credit facilities, the convertible preferred stock
became redeemable and was reclassified to current liabilities on the
Consolidated Balance Sheet at December 31, 2008.
Payment of Preferred
Dividends
- The preferred stock dividends that were due on January 1,
2009, were paid effective December 31, 2008, with approximately 775,600 shares
of TXCO's common stock, as provided for in the Preferred Stock agreements.
Earlier preferred dividend payments were made using cash.
Subsequent Events
-
In January 2009, holders of 5,000 shares of TXCO Series D Preferred Stock (with
a conversion price of $14.48) and 5,000 shares of TXCO Series E Preferred Stock
(with a conversion price of $17.36), with an aggregate stated value of $10.0
million converted those shares into a total of approximately 633,300 shares of
TXCO's common stock. An additional 836,600 shares of TXCO common stock were
issued for the make-whole provision related to preferred dividends.
In
February 2009, it was determined that the Company had violated the Current Ratio
covenant under its bank credit facilities. As a result of this covenant
violation, holders of the convertible preferred stock have the right to request
that the Company redeem their shares; however, the Company's obligation to
redeem is suspended until the earlier of October 31, 2012 or satisfaction in
full of all of the Company's obligations under its senior indebtedness
agreements. As a result of this right, though it is specifically suspended until
the senior debt is paid, the stated value of the outstanding convertible
preferred stock has been reclassified to current liabilities in the Consolidated
Balance Sheet for December 31, 2008. Shares related to the January conversion of
convertible preferred stock, described above, were not reclassified since they
were retired without the use of current assets. Under the terms of the
Certificates of Designations, the Company is obligated to pay interest at a rate
of 1.5% per month in respect of each preferred share for which redemption has
been demanded until paid in full.
Call
Options
:
Concurrently with the issuance of each of the Preferred Series, the
Company entered into convertible preferred stock hedge transactions or "call
spread" transactions intended to reduce potential dilution upon conversion of
the Preferred Stock. Each call spread is a combination of a bought and a sold
call option. The bought call options were not exercised at the time of the
preferred stock conversions in October 2008 and January 2009, since the market
price for TXCO's common stock was lower than the exercise price for the
options.
The
following table summarizes the outstanding call options related to convertible
preferred stock at December 31, 2008:
|
Related
Preferred
Stock Series
|
|
Exercise
Price
|
|
Increase
(Decrease) in
Outstanding
Common Shares,
If Exercised
|
|
Bought call
options
:
|
|
|
|
|
|
D
|
|
$14.48
|
|
(4,758,900)
|
|
E
|
|
$17.36
|
|
(1,152,100)
|
|
Sold call
options
:
|
|
|
|
|
|
D
|
|
$18.10
|
|
4,758,900
|
|
E
|
|
$21.71
|
|
1,152,100
|
These
call options fall outside the scope of FAS 150, "Accounting for Convertible
Securities with Beneficial Conversion Features or Contingently Adjustable
Conversion Ratios" and qualify for equity treatment under the guidance of EITF
00-19, "Accounting for Derivative Financial Instruments Indexed to, and
Potentially Settled in, a Company's Own Stock." The net cost for these
transactions, approximately $3.7 million during 2007 and $2.3 million during
2008, was recorded as a reduction to additional paid-in capital.
Private
Placements - 2006:
In March 2006, TXCO closed on a private placement of
3.0 million shares of its common stock at a purchase price of $10.50 per share
for net proceeds of $29.9 million. Purchasers were private, U.S.-based
investment funds and individuals. Proceeds from the private placement were used
to expand the Company's capital expenditure program in the Maverick and Marfa
Basins.
Restricted Stock
-
2006:
The
Company issued 61,335 restricted common shares as partial payment for certain
overriding royalty interests.
NOTE
G - STOCKHOLDERS' EQUITY AND REDEEMABLE PREFERRED STOCK - continued
Stockholder
Rights Agreement:
On June 29, 2000, the Company adopted a Rights
Agreement (the "Rights Agreement") whereby a dividend of one preferred share
purchase right (a "Right") was paid for each outstanding share of TXCO common
stock. The Rights Agreement is designed to enhance the Board's ability to
prevent an acquirer from depriving stockholders of the long-term value of their
investment and to protect stockholders against attempts to acquire the Company
by means of unfair or abusive takeover tactics. The Rights will be exercisable
only if a person acquires beneficial ownership of 15% or more of TXCO common
stock (an "Acquiring Person"), or commences a tender offer which would result in
beneficial ownership of 15% or more of such stock. When they become exercisable,
each Right entitles the registered holder to purchase from TXCO .001 share of
Series A Preferred Stock, subject to adjustment under certain
circumstances.
Upon the
occurrence of certain events specified in the Rights Agreement, each holder of a
Right (other than an Acquiring Person) may purchase, at the Right's then current
exercise price, shares of TXCO common stock having a value of twice the Right's
exercise price. In addition, if, after a person becomes an Acquiring Person,
TXCO is involved in a merger or other business combination transaction with
another person in which TXCO is not the surviving corporation, or under certain
other circumstances, each Right will entitle its holder to purchase, at the
Right's then current exercise price, shares of common stock of the other person
having a value of twice the Right's exercise price. The Rights Agreement
generally may be amended by the Company without the approval of the holders of
the Rights prior to the public announcement by TXCO or an Acquiring Person that
a person has become an Acquiring Person.
Unless
redeemed by TXCO earlier, the Rights will expire on June 29, 2010. The Company
will generally be entitled to redeem the Rights in whole, but not in part, at
$0.01 per Right, subject to adjustment. No Rights were exercisable under the
Rights Agreement at December 31, 2008.
Dividend
Restriction:
The bank credit facilities and the Securities Purchase
Agreements for the convertible preferred stock prohibit the declaration, or
payment, of dividends to common stockholders.
Stock Based
Employee Compensation Plan:
The Company granted options to its officers,
directors, and key employees under its 1995 Flexible Incentive Plan (the "1995
Plan"), as amended, in prior years. The 1995 Plan was replaced during 2005 with
the 2005 Stock Incentive Plan, which was amended by a vote of the stockholders
in May 2008, (the "2005 Plan"). The 2005 Plan allows for the future award of a
maximum number of shares limited to 10% of the total number of then issued and
outstanding shares of common stock for issuance. These shares may be issued as
the result of exercise of options granted or as restricted stock to management,
directors, and key employees.
Under the
2005 Plan, the Company granted restricted stock to its officers, directors, and
key employees each year from 2006 through 2008, and options to its directors in
2008. At December 31, 2008, 3,275,410 shares were authorized for grant and
2,396,613 shares remained available for grant. All currently outstanding options
have 10-year terms that vest and become fully exercisable based on the specific
terms imposed at the date of grant.
At
December 31, 2008, TXCO had unrecognized stock-based compensation totaling $4.6
million for awards that vest over the next 2 years. Recognized compensation
expense for share-based payment arrangements is shown in the following
table:
|
|
2008
|
2007
|
2006
|
|
Compensation
expense recognized
|
$3,626,000
|
$1,798,000
|
$1,207,000
|
The
Black-Scholes option valuation model was developed for use in estimating the
fair value of traded options that have no vesting restrictions and are fully
transferable. In addition, option valuation models require the input of highly
subjective assumptions including the expected stock price volatility. The
Company's employee stock options have characteristics significantly different
from those of traded options, and changes in the subjective input assumptions
can materially affect the fair value estimate. In management's opinion, the
existing models do not necessarily provide a reliable single measure of the fair
value of its employee stock options.
The fair
value for options granted was estimated at the date of grant with the following
weighted-average assumptions for the year ended December 31:
|
|
2008
|
2007
|
2006
|
|
Risk-free
interest rate
|
1.88%
|
*
|
*
|
|
Expected
dividend yield
|
0%
|
*
|
*
|
|
Expected
volatility of common stock
|
64.3%
|
*
|
*
|
|
Expected
weighted-average life of option
|
6
years
|
*
|
*
|
* No
grants were awarded during 2006 or 2007
NOTE
G - STOCKHOLDERS' EQUITY AND REDEEMABLE PREFERRED STOCK - continued
A summary
of the Company's stock option activity and related information is as
follows:
|
|
Year
Ended December 31,
|
|
|
2008
|
2007
|
2006
|
|
Summary of Stock Option
Activity
(Shares
in thousands)
|
Shares
Under Options
|
Weighted
Average Exercise Price
|
Shares
Under Options
|
Weighted
Average Exercise Price
|
Shares
Under Options
|
Weighted
Average Exercise Price
|
Outstanding,
beginning of year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate
intrinsic value, end of year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate
intrinsic value, end of year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average fair value of options granted during the
year
|
|
|
|
|
|
|
* The
options outstanding at year-end 2008 had no intrinsic value since all were
priced above the market price at that date.
The
following table summarizes information about the options outstanding at December
31, 2008:
|
|
Options
Outstanding
|
|
Options
Exercisable
|
|
Exercise
Price
|
Number
Outstanding
(in
thousands)
|
Wt.-Avg.
Remaining
Contractual
Life
|
Wt.-Avg.
Exercise
Price
|
|
Number
Exercisable
(in
thousands)
|
Wt.-Avg.
Exercisable
Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds
to the Company from the exercise of stock options related to stock-based
compensation totaled $19,000 in 2008 and $92,000 in 2007, net of cashless
exercises.
Stock
Warrants
:
No
stock warrants remained outstanding at December 31, 2008. Most 2008 and all 2007
exercises of warrants were done on a cashless basis, resulting in the issuance
of 442,458 and 120,007 shares of TXCO common during 2008 and 2007, respectively.
TXCO also issued 3,300 shares of its common stock as the result of exercise of
$4.25 warrants for cash, resulting in proceeds of approximately $14,000 in
2008.
NOTE
G - STOCKHOLDERS' EQUITY AND REDEEMABLE PREFERRED STOCK - continued
Restricted Stock:
Since 2006, the Company granted restricted stock as compensation to
employees and non-employee directors under the 2005 Stock Incentive Plan. During
2008, shares with an aggregate fair value of $1.5 million were granted to
non-employee directors, net of forfeitures related to the Settlement Agreement
with Third Point, LLC and certain other parties. For additional details on the
Settlement Agreement, see the Form 8-K filed with the SEC on March 19, 2008. The
vesting term for continuing directors is one year, while shares awarded to new
directors vest over three years. Also as part of this Settlement Agreement, the
vesting of 41,666 shares held by two exiting directors was accelerated.
Additionally during 2008, shares with an aggregate fair value of $3.1 million
and a three-year vesting period were granted to employees ($1.0 million
aggregate fair value per year). The fair value is recognized as stock
compensation expense (included in general and administrative expense on the
Consolidated Statements of Operations) over the vesting periods.
Summary
of activity in Non-vested Shares:
|
|
|
|
|
|
|
Outstanding
at December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding
at December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding
at December 31, 2008
|
|
|
NOTE H - RELATED PARTY TRANSACTIONS
During
the fourth quarter of 2008, the Company entered into a joint exploration
agreement ("JEA") with Millenium E&P Resource Fund I, LLC ("Millenium"). The
agreement calls for Millenium to provide $825,000 in initial funds for the
drilling and completion of a well to test the Georgetown formation in the Burr
"C" project. The JEA also provides the options for Millenium to participate in
up to two additional wells. In each well, Millenium will fund 100% of the cost
of drilling and completion and will earn a 50% working interest in the well.
TXCO will serve as operator on the wells covered by the JEA. An outside director
of the Company serves as chief executive officer ("CEO") of Millenium and will
receive a 1.1875% working interest following payout of any successful well
drilled under the JEA.
In 1994,
TXCO's CEO agreed to reduce his annual base salary. In recognition of this
forfeiture, the Company granted the CEO a 1% overriding royalty interest
("ORRI") in certain oil and natural gas leases of the Company. In 1996, this
grant was amended to include all oil and natural gas leases acquired or to be
acquired by the Company. The ORRI was determined to have little or no value at
the time of grant, and royalties related to the ORRI were almost non-existent.
The Company has pursued the possible acquisition of the ORRI; however, such an
agreement was never reached and the ORRI remains in place as originally granted.
Royalty earnings by the CEO related to the ORRI totaled approximately,
$1,880,000 in 2008, $1,172,000 in 2007 and $982,000 in 2006. Included in
undistributed revenue is $523,000 at December 31, 2008, and $175,000 at December
31, 2007, due the CEO for this ORRI.
NOTE I - EARNINGS PER SHARE
The
following is a reconciliation of the numerator and denominator of the earnings
per share ("EPS") computation for both basic and diluted EPS:
|
|
Year
Ended December 31,
|
|
|
(in
thousands)
|
2008
|
2007
|
2006
|
|
|
|
|
|
|
|
|
|
|
Less:
Preferred dividends
|
|
|
|
|
|
|
|
(Loss)
/ income - basic earnings per share calculation
|
|
|
|
|
|
|
|
Add:
Income impact of assumed conversions, if any
|
|
|
|
|
|
|
|
(Loss)
/ income - diluted earnings per share calculation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average
number of common shares:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect
of dilutive securities:
|
|
|
|
|
|
|
|
Stock
options and warrants
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Convertible
preferred stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss)
/ earnings per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the
year ended December 31, 2008, the calculation of weighted-average number of
common shares for diluted EPS does not include potential common shares of
4,363,655 and 966,357 derived from convertible preferred stock, Series D and
Series E, and 5,481,722 derived from sold call options, 298,823 derived from
stock options and 642,905 derived from nonvested stock, respectively, because
their effect would have been anti-dilutive. For the year ended December 31,
2007, the calculation of weighted-average number of common shares for diluted
EPS does not include 3,798,343 of potential common shares derived from
convertible preferred stock, Series D, and 3,798,342 potential common shares
derived from sold call options, respectively, because their effect would have
been anti-dilutive. None of our outstanding stock options or warrants were
anti-dilutive based on exercise price during the three-year period presented,
until the fourth-quarter of 2008.
NOTE J - INCOME TAXES
The
components of the Company's income taxes were as follows as of and for the years
ended December 31:
|
(in
thousands)
|
|
2008
|
|
2007
|
|
2006
|
|
Current
federal tax (benefit) expense
|
|
|
|
|
|
|
|
Deferred
federal tax expense (benefit)
|
|
|
|
|
|
|
|
Income
tax expense (benefit)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax
net operating loss carryforwards
|
|
|
|
|
|
Impairment
of oil and natural gas properties
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
deferred tax assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
tax liabilities:
|
|
|
|
|
|
Intangible
drilling costs and depreciation
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
deferred tax liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
deferred tax (liability) / asset
|
|
|
|
|
|
The
differences between the expected federal income taxes and the Company's actual
taxes are as follows:
|
(in
thousands)
|
|
2008
|
|
2007
|
|
2006
|
|
Expected
federal tax expense
|
|
|
|
|
|
|
|
Statutory
tax depletion and similar items
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
tax expense (benefit)
|
|
|
|
|
|
|
|
The
Company's tax net operating loss carryforward of approximately $173.7 million
expires in stages beginning in 2027.
NOTE K - MAJOR CUSTOMERS
Sales to
unrelated entities which individually comprised greater than 10% of total
revenues are as follows:
|
|
A
|
B
|
C
|
D
|
E
|
Year
ended December 31, 2008
|
|
|
|
|
|
Year
ended December 31, 2007
|
|
|
|
|
|
Year
ended December 31, 2006
|
|
|
|
|
|
NOTE
L - DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY
Commodity Price
Risk
-
Related Hedging
Activities:
Due to the volatility of oil and natural gas prices and
requirements under TXCO's bank credit facility, the Company periodically enters
into price-risk management transactions (e.g., swaps, collars and floors) for a
portion of its oil and natural gas production. This allows it to achieve a more
predictable cash flow, as well as to reduce exposure from price fluctuations.
These arrangements apply to only a portion of the Company's production, provide
only partial price protection against declines in oil and natural gas prices,
and limit the Company's potential gains from future increases in prices. None of
these instruments are used for trading purposes. On a quarterly basis, the
Company's management sets all of the Company's price-risk management policies,
including volumes, types of instruments and counterparties.
All of
these price-risk management transactions are considered derivative instruments
and accounted for in accordance with SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." These derivative instruments are
intended to hedge the Company's price risk and may be considered hedges for
economic purposes, but certain of these transactions may or may not qualify for
cash flow hedge accounting. All derivative instrument contracts are recorded on
the Consolidated Balance Sheets at fair value. In prior years, the Company
elected to account for certain of its derivative contracts as investments as set
out under SFAS No. 133. Therefore, the changes in fair value in those contracts
were recorded immediately as unrealized gains or losses on the Consolidated
Statements of Operations. The change in fair value for the effective portion of
contracts designated as cash flow hedges is recognized in Other Comprehensive
Income (Loss) in the Stockholders' Equity section of the Consolidated Balance
Sheets. The gain or loss in Other Comprehensive Income is reported on the
Consolidated Statements of Operations as the hedged transactions occur. The
hedges are highly effective, and therefore, no hedge ineffectiveness has been
recorded.
The
Company had cash flow hedges in place during January through April of 2007,
which have since expired. New derivative agreements were entered into during
2007 and 2008, in accordance with the terms of our term loan and revolving
credit facilities.
The
following table reflects the realized gains and losses from commodity
derivatives included in revenue on the Consolidated Statements of
Operations:
|
(in thousands)
|
|
2008
|
|
2007
|
|
2006
|
|
|
Crude
oil derivative realized settlements
|
|
$(5,725
|
)
|
$(1,596
|
)
|
$(105
|
)
|
|
Natural
gas derivative realized settlements
|
|
(303
|
)
|
(1,372
|
)
|
(806
|
)
|
|
Loss
on commodity derivatives
|
|
$(6,028
|
)
|
$(2,968
|
)
|
$(911
|
)
|
The fair
value of outstanding derivative contracts reflected on the balance sheet was as
follows:
|
Trans-
|
Trans-
|
|
|
Average
Floor or
Fixed
|
|
Average
Ceiling
|
|
Volumes
|
|
Fair Value of
Outstanding
Derivative
Contracts
(1)
as of
|
|
|
action
|
action
|
|
|
Price
|
|
Price
|
|
Per
|
|
Dec.
31,
|
|
Dec.
31,
|
|
|
Date
|
Type
|
Beginning
|
Ending
|
Per
Unit
|
|
Per
Unit
|
|
Month
|
|
2008
|
|
2007
|
|
|
Crude
Oil
-
Bbl (2)
:
|
|
|
08/07-12/07
|
Collars
|
01/01/2008
|
12/31/2008
|
$67.31
|
|
$81.05
|
|
26,000
|
|
$-
|
|
$(4,758
|
)
|
|
08/07-08/08
|
Collars
|
01/01/2009
|
12/31/2009
|
$71.40
|
|
$87.41
|
|
20,700
|
|
4,608
|
|
(2,845
|
)
|
|
08/07-08/08
|
Collars
|
01/01/2010
|
06/30/2010
|
$68.33
|
|
$80.77
|
|
15,000
|
|
816
|
|
(990
|
)
|
|
12/07-04/08
|
Collars
|
07/01/2010
|
12/31/2010
|
$75.80
|
|
$100.35
|
|
13,200
|
|
1,175
|
|
5
|
|
|
04/08
|
Collars
|
01/01/2011
|
06/30/2011
|
$90.00
|
|
$122.80
|
|
11,500
|
|
1,718
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
-
mmBtu
(3)
:
|
|
|
08/07-12/07
|
Collars
|
01/01/2008
|
12/31/2008
|
$6.50
|
|
$10.22
|
|
97,000
|
|
-
|
|
33
|
|
|
08/07-08/08
|
Collars
|
01/01/2009
|
12/31/2009
|
$6.60
|
|
$11.64
|
|
86,500
|
|
1,308
|
|
(57
|
)
|
|
08/07-04/08
|
Collars
|
01/01/2010
|
06/30/2010
|
$6.58
|
|
$11.62
|
|
74,000
|
|
360
|
|
(43
|
)
|
|
12/07-04/08
|
Collars
|
07/01/2010
|
12/31/2010
|
$6.55
|
|
$11.08
|
|
69,500
|
|
255
|
|
(63
|
)
|
|
04/08
|
Collars
|
01/01/2011
|
06/30/2011
|
$8.00
|
|
$9.85
|
|
62,000
|
|
458
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
$10,698
|
|
$(8,718
|
)
|
See the next page for the footnotes to
this table.
NOTE
L - COMMODITY HEDGING CONTRACTS AND ACTIVITY - continued
(1)
The
fair value of the Company's outstanding transactions is presented on the balance
sheet by counterparty. Amounts in parentheses indicate liabilities. All were
designated as cash flow hedges.
(2)
These
crude oil hedges were entered into on a per barrel delivered price basis, using
the West Texas Intermediate Index, with settlement for each calendar month
occurring following the expiration date, as determined by the
contracts.
(3)
These
natural gas hedges were entered into on an mmBtu delivered price basis, using
the Houston Ship Channel Index, with settlement for each calendar month
occurring following the expiration date, as determined by the
contracts.
(4)
A portion of our 2010 and 2011
commodity collars were closed for cash during January 2009 and replaced with new
hedges. After the closing of those positions, the averages on our remaining
collars are as follows
:
|
|
Crude
Oil
-
Bbl
:
|
|
|
|
|
08/07-08/08
|
Collars
|
01/01/2010
|
06/30/2010
|
$68.33
|
|
$79.95
|
|
9,000
|
|
|
|
12/07-04/08
|
Collars
|
07/01/2010
|
12/31/2010
|
$90.00
|
|
$124.50
|
|
700
|
|
|
|
04/08
|
Collars
|
01/01/2011
|
06/30/2011
|
$90.00
|
|
$122.80
|
|
11,500
|
|
|
|
Natural Gas
-
mmBtu
:
|
|
|
|
|
08/07-04/08
|
Collars
|
01/01/2010
|
06/30/2010
|
$6.93
|
|
$11.56
|
|
14,000
|
|
The new
hedges placed in January 2009 are 50% participation swaps, which allow a floor
price on the full notional volume and a cap at the same price on one-half of the
notional volume. The floor price and notional amounts are shown
below:
|
|
Crude
Oil
-
Bbl
:
|
|
|
|
|
01/09
|
Swaps
|
01/01/2010
|
06/30/2010
|
$49.75
|
|
|
|
8,000
|
|
|
|
01/09
|
Swaps
|
07/01/2010
|
12/31/2010
|
$51.40
|
|
|
|
14,000
|
|
|
|
01/09
|
Swaps
|
01/01/2011
|
06/30/2011
|
$52.25
|
|
|
|
2,000
|
|
|
|
01/09
|
Swaps
|
07/01/2011
|
12/31/2011
|
$53.50
|
|
|
|
12,000
|
|
|
|
Natural Gas
-
mmBtu
:
|
|
|
|
|
01/09
|
Swaps
|
01/01/2010
|
06/30/2010
|
$5.51
|
|
|
|
53,000
|
|
Interest Rate
Risks
-
Related Hedging
Activities:
At December 31, 2008, a fixed-rate swap was in place on $100
million of borrowings under TXCO's Term Loan Agreement (See
Note
D
for more information on this agreement) which locks the LIBOR portion of
the interest rate at 3.305% until June 30, 2010. This equates to a total rate of
7.805% per annum on this debt. The fair market value of this derivative
instrument was a liability of $3.5 million at December 31, 2008. The swap is
designated as a cash flow hedge. No comparable derivative instrument was in
place during 2007 or 2006. An immaterial amount of ineffectiveness is expected
on this derivative contract due to a difference in the rounding conventions for
the LIBOR rate between the two documents.
The
following table reflects the realized losses from derivatives included in
"Interest expense" on the Consolidated Statements of Operations:
|
(in thousands)
|
|
2008
|
|
2007
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
Interest
rate swap realized settlement losses
|
|
$402
|
|
$-
|
|
$-
|
|
|
Interest
rate swap ineffectiveness
|
|
13
|
|
-
|
|
-
|
|
|
Loss
on interest rate swap contracts
|
|
$415
|
|
$-
|
|
$-
|
|
NOTE M - ACQUISITIONS AND SALES OF OIL AND NATURAL GAS
PROPERTIES
Output
Acquisition:
On April 2, 2007, TXCO's acquisition of Output Exploration,
LLC, a Delaware limited liability company ("Output"), was closed and became
effective. Accordingly, the results of operations of Output are consolidated in
the financial statements since that date. In connection with the Merger,
TXCO paid to the holders of Output equity interests an aggregate of
approximately $95.6 million, consisting of $91.6 million in cash and
approximately 339,000 shares of TXCO common stock.
BMO
Capital Markets served as financial advisor to TXCO. The Merger was funded
through borrowings under the new Senior Credit Agreement and Term Loan Agreement
described in Item 1.01 of the Current Report on Form 8-K, that was filed with
the SEC on April 5, 2007, and summarized in
Note D
above.
The
following table summarizes the final purchase price allocation to the acquired
assets and liabilities based on their relative fair values:
|
Allocation of Purchase Price
(in
thousands)
|
|
|
|
Proved
properties
|
$91,096
|
|
|
Unproved
properties
|
24,164
|
|
|
Pipeline
equipment
|
13
|
|
|
Other
assets
|
6,632
|
|
|
Liabilities
assumed
|
(26,305
|
)
|
|
|
$95,600
|
|
The
following unaudited pro forma data includes the results of operations as if the
Output acquisition had been consummated on January 1, 2007. The unaudited pro
forma results do not purport to represent what our results of operations
actually would have been if this acquisition had been completed on such date or
to project our results of operations for any future date or period.
|
|
|
For
the Year Ended December 31,
|
|
|
Pro Forma Income Statement
Data
(in
thousands)
|
|
2008
|
|
|
2007
|
|
|
Revenues
|
|
$143,736
|
|
|
$99,867
|
|
|
Income
/ (loss) from continuing operations, after pro
forma
provision for income taxes
|
|
5,882
|
|
|
$(422
|
)
|
|
(Loss)
/ income from continuing operations available to common
stockholders
|
|
(473
|
)
|
|
$(819
|
)
|
|
(Loss)
from continuing operations available to common stockholders, per
share:
|
|
|
|
|
|
|
|
Basic
|
|
$(0.01
|
)
|
|
$(0.02
|
)
|
|
Diluted
|
|
$(0.01
|
)
|
|
$(0.02
|
)
|
NOTE
N - OIL AND NATURAL GAS PRODUCING ACTIVITIES AND
PROPERTIES
Capitalized
Costs and Costs Incurred Relating to Oil and Natural Gas Activities
The
Company's investment in oil and natural gas properties is as follows at December
31:
|
(in
thousands)
|
|
2008
|
|
2007
|
|
|
|
|
|
|
|
|
Less
accumulated depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and natural gas leasehold acreage
|
|
|
|
|
|
Total
unproved properties
|
|
|
|
|
|
Less
reserve for impairment
|
|
|
|
|
|
Less
reserve for impairment on oil sands project
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs
incurred, capitalized, and expensed in oil and natural gas producing activities
for the years ended December 31:
|
(in
thousands, except per equivalent mcf data)
|
|
2008
|
|
2007
|
|
2006
|
|
Property
acquisition costs, unproved
|
|
|
|
|
|
|
|
Property
development and exploration costs:
|
|
|
|
|
|
|
|
Conventional
oil and natural gas properties
|
|
|
|
|
|
|
|
Coalbed
methane properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
|
|
|
|
|
Depletion
per equivalent mcf of production
|
|
|
|
|
|
|
|
Oil
and Natural Gas Reserves (Unaudited)
The
estimates of the Company's proved reserves and related future net cash flows
that are presented in the following tables are based upon estimates made by
independent petroleum engineering consultants. The Company's reserve information
was prepared as of each respective year-end. There are many inherent
uncertainties in estimating proved reserve quantities, projecting future
production rates, and timing of development expenditures. Accordingly, these
estimates are likely to change, as future information becomes available. Proved
developed reserves are the estimated quantities of crude oil, condensate,
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.
Changes
in estimated net quantities of conventional oil and natural gas reserves, all of
which are located within the United States, are as follows for the years ended
December 31:
|
(in
thousands)
|
|
2008
|
|
2007
|
|
2006
|
|
Proved
developed and undeveloped reserves
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Extensions
and discoveries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions
of previous engineering estimates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note: T
he t
able continues on the next
page.
NOTE
N - OIL AND NATURAL GAS PRODUCING ACTIVITIES AND PROPERTIES -
continued
|
(in
thousands)
|
|
2008
|
|
2007
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Extensions
and discoveries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions
of previous engineering estimates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
developed reserves
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
following table sets forth a standardized measure of the estimated discounted
future net cash flows attributable to the Company's proved developed and
undeveloped oil and natural gas reserves. Prices used to determine future cash
inflows were based on the respective year-end posted prices, as adjusted for
quality, fees and price differentials, as utilized for the Company's proved
developed reserves. The prices were $5.245, $6.445 and $5.40 per mcf of natural
gas and $41.25, $92.75 and $57.75 per barrel of oil as of December 31, 2008,
2007 and 2006. Prices for hedges that are in place for a portion of our 2009
through 2011 projected sales were used to adjust price expectations for those
years. The future production and development costs represent the estimated
future expenditures to be incurred in developing and producing the proved
reserves, assuming continuation of existing economic conditions. Future income
tax expense was computed by applying statutory income tax rates to the
difference between pretax net cash flows relating to the Company's reserves and
the tax basis of proved oil and natural gas properties and available operating
losses and temporary differences.
|
(in
thousands)
|
|
2008
|
|
2007
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
Future
production and development costs
|
|
|
|
|
|
|
|
Future
income tax benefit (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10%
annual discount to reflect timing of net cash flows
|
|
|
|
|
|
|
|
Standardized
measure of discounted future
net
cash flows relating to proved reserves
|
|
|
|
|
|
|
|
The
principal factors comprising the changes in the standardized measure of
discounted future net cash flows are as follows for the years ended December
31:
|
(in
thousands)
|
|
2008
|
|
2007
|
|
2006
|
|
Standardized
measure, beginning of year
|
|
|
|
|
|
|
|
Extensions
and discoveries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
and transfers, net of production costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions
in quantity and price estimates
|
|
|
|
|
|
|
|
Net
change in income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized
measure, end of year
|
|
|
|
|
|
|
|
NOTE O - Fair Value Measurements
Effective
January 1, 2008, the Company adopted SFAS No. 157, "Fair Value
Measurements," which defines fair value, establishes a framework for using fair
value to measure assets and liabilities, and expands disclosures about fair
value measurements. The Statement establishes a hierarchy for inputs used in
measuring fair value that maximizes the use of observable inputs and minimizes
the use of unobservable inputs by requiring that the most observable inputs be
used when available. Observable inputs are inputs that market participants would
use in pricing the asset or liability developed based on market data obtained
from sources independent of the Company. Unobservable inputs are inputs that
reflect the Company's assumptions of what market participants would use in
pricing the asset or liability developed based on the best information available
in the circumstances. The hierarchy is broken down into three levels based on
the reliability of the inputs as follows:
|
Level
1:
|
Quoted
prices are available in active markets for identical assets or
liabilities;
|
|
Level
2:
|
Quoted
prices in active markets for similar assets and liabilities that are
observable for the asset or liability; or
|
|
Level
3:
|
Unobservable
pricing inputs that are generally less observable from objective sources,
such as discounted cash flow models or
valuations.
|
SFAS
No. 157 requires financial assets and liabilities to be classified based on
the lowest level of input that is significant to the fair value measurement. The
Company's assessment of the significance of a particular input to the fair value
measurement requires judgment, and may affect the valuation of the fair value of
assets and liabilities and their placement within the fair value hierarchy
levels. The following table presents TXCO's financial assets and liabilities
that were accounted for at fair value on a recurring basis as of December 31,
2008, by level within the fair value hierarchy:
|
|
|
Fair
Value Measurements Using
|
|
(in
thousands)
|
|
Level
1
|
|
Level
2
|
|
Level
3
|
|
Assets
- Derivative instruments
|
|
$ -
|
|
$ -
|
|
$10,698
|
|
Liabilities
- Derivative instruments
|
|
$ -
|
|
$ -
|
|
$3,487
|
TXCO's
derivative financial instruments are comprised of costless collar agreements.
The fair values of these agreements are determined based on both observable and
unobservable pricing inputs and therefore, the data sources utilized in these
valuation models are considered level 3 inputs in the fair value
hierarchy.
The
following table sets forth a reconciliation of changes in the fair value of
financial liabilities classified as level 3 in the fair value
hierarchy:
|
(in
thousands)
|
|
Derivatives
|
|
Total
|
|
|
Balance
as of January 1, 2008
|
|
|
$(8,718
|
)
|
|
|
$(8,718
|
)
|
|
Total
losses (realized or unrealized):
|
|
|
|
|
|
|
|
|
|
Included
in earnings *
|
|
|
(6,443
|
)
|
|
|
(6,443
|
)
|
|
Included
in other comprehensive income *
|
|
|
22,372
|
|
|
|
22,372
|
|
|
Purchases,
issuances and settlements
|
|
|
-
|
|
|
|
-
|
|
|
Transfers
in and out of level 3
|
|
|
-
|
|
|
|
-
|
|
|
Balance
as of December 31, 2008
|
|
|
$7,211
|
|
|
|
$7,211
|
|
|
Change
in unrealized gains or losses included in earnings (or changes
in
|
|
|
|
|
|
|
|
|
|
net
assets) relating to derivatives still held as of December 31,
2008
|
|
|
$15,929
|
|
|
|
$15,929
|
|
* On the
Consolidated Income Statements, realized gains or losses from commodity
derivatives are included as adjustments to the "Oil and Natural Gas Sales"
revenues, while those from interest rate hedges are included in "Interest
Expense." Unrealized losses or gains are included in "Other Comprehensive
Income" in "Stockholders' Equity" on the Consolidated Balance Sheets, since
these derivatives have been designated as cash flow hedges.
NOTE P - Selected Quarterly Financial Information
(Unaudited)
|
(In
thousands, except earnings per share data)
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(loss) from operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(loss)available to common stockholders
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(loss) from operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(loss)available to common stockholders
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Quarterly
earnings per share are based on the weighted average number of shares
outstanding during the quarter. Because of the increase in the number of shares
outstanding during the quarters due to exercises of warrants and stock options,
as well as newly issued shares, the sum of quarterly earnings per share may not
equal earnings per share for the year.
NOTE Q - SUBSEQUENT EVENTS
In
February 2009, TXCO retained Goldman, Sachs & Co. as a financial advisor for
a strategic alternatives review designed to enhance stockholder value. All
options are under consideration, including the potential sale of leasehold
interests or other assets, a merger or sale of the Company. No formal decisions
have been made and no agreements have been reached at this time. There can be no
assurance that any particular alternative will be pursued or that any
transaction will occur, or on what terms. TXCO does not expect to disclose
developments from this review unless its board of directors approves a
definitive transaction.
In order
to enhance liquidity, TXCO sold all interests in its pipeline system to Clear
Springs Energy Company LLC, a Texas limited liability company, effective
February 1, 2009. The Company's net basis in its pipeline was approximately $4.9
million. TXCO expects to continue to utilize this pipeline system to
transport much of its natural gas production.
On March
9, 2009, a holder of preferred stock demanded redemption of 34,409 shares of
Series D Convertible Preferred Stock and 15,000 shares of Series E Convertible
Preferred Stock. Generally, holders of the preferred stock are entitled to
receive dividends, payable quarterly, at the rate of 6.5% and 6.0% per annum for
Series D and Series E, respectively. In connection with the Company's breach of
the current ratio in our bank credit facilities, the dividend rate is increased
to 12% per annum for both the Series D and Series E Preferred Stock until such
time as the breach of the current ratio covenant is cured.
TXCO
Resources Inc.
Schedule II - Valuation and Qualifying Reserves
|
(in
thousands)
|
|
Balance
Beginning
of
Period
|
|
Charged
to
Costs
and
Expense
|
|
Deductions
|
|
Balance
End
of
Period
|
|
Year Ended December 31,
2008
|
|
|
|
|
|
|
|
|
|
Allowance
for doubtful accounts,
|
|
|
|
|
|
|
|
|
|
Impairment
of oil and natural gas properties
|
|
|
|
|
|
|
|
|
|
Impairment
of oil sands project
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
2007
|
|
|
|
|
|
|
|
|
|
Allowance
for doubtful accounts,
|
|
|
|
|
|
|
|
|
|
Impairment
of oil and natural gas properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
2006
|
|
|
|
|
|
|
|
|
|
Allowance
for doubtful accounts,
|
|
|
|
|
|
|
|
|
|
Impairment
of oil and natural gas properties
|
|
|
|
|
|
|
|
|
|
Txco Resources (MM) (NASDAQ:TXCO)
過去 株価チャート
から 5 2024 まで 6 2024
Txco Resources (MM) (NASDAQ:TXCO)
過去 株価チャート
から 6 2023 まで 6 2024
