UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
(Mark
One)
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x
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ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
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For the
Fiscal Year Ended December 31, 2008
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⃞
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TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
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Commission
File Number 001-16071
ABRAXAS
PETROLEUM CORPORATION
(Exact
name of Registrant as specified in its charter)
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Nevada
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74-2584033
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(State
or Other Jurisdiction of
Incorporation
or Organization)
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(I.R.S.
Employer Identification Number)
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18803
Meisner Drive
San
Antonio, TX 78258
(Address
of principal executive offices)
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(210)
490-4788
Registrant’s
telephone number, including area code
SECURITIES
REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
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Title
of each class:
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Name
of each exchange on which registered:
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Common
Stock, par value $.01 per share
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NASDAQ
Stock Market
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SECURITIES
REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
None
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act.Yes ⃞No ⊠
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Exchange Act.Yes ⊠No ⃞
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 xNo ⃞
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. Yes xNo ⃞
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or 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.
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Large
accelerated filer ⃞
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Accelerated
filer x
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Non-accelerated
filer ⃞ (Do
not mark if a smaller reporting company)
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Smaller
reporting company ⃞
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Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).Yes ⃞No x
As of
June 30, 2008, the aggregate market value of the common stock held by
non-affiliates of the registrant was $243,774,232 based on the closing sale
price as reported on the American Stock Exchange.
As of
February 20, 2009, there were 49,621,711 shares of common stock
outstanding.
Documents Incorporated by
Reference:
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Document
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Parts
Into Which Incorporated
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Portions
of the registrant’s Proxy Statement relating to the 2009 Annual Meeting of
Shareholders to be held on May 21, 2009.
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Part
III
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ABRAXAS
PETROLEUM CORPORATION
FORM
10-K
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Page
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Part I
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Business
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1
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Risk
Factors
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9
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Unresolved
Staff Comments
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21
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Properties
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22
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Legal
Proceedings
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29
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Submission
of Matters to a Vote of Security Holders
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29
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Part
II
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Market
for Registrant’s Common Equity, Related Stockholder Matters
and
Issuer
Purchases of Equity Securities
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30
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Selected
Financial Data
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31
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Management’s
Discussion And Analysis Of Financial Condition And Results
Of
Operations
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32
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Quantitative
and Qualitative Disclosure about Market Risk
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52
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Financial
Statements and Supplementary Data
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53
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Changes
in and Disagreements with Accountants on Accounting and
Financial
Disclosure
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53
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Controls
and Procedures
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53
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Other
Information
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54
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Part
III
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Directors,
Executive Officers and Corporate Governance
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55
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Executive
Compensation
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55
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Security
Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
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55
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Certain
Relationships and Related Transactions, and Director
Independence
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55
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Principal
Accountant Fees and Services
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55
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Part
IV
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Exhibits
and Financial Statement Schedules
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55
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Forward-Looking
Information
We make
forward-looking statements throughout this document. Whenever you read a
statement that is not simply a statement of historical fact (such as statements
including words like “believe”, “expect”, “anticipate”, “intend”, “plan”,
“seek”, “estimate”, “could”, “potentially” or similar expressions), you must
remember that these are forward-looking statements and that our expectations may
not be correct, even though we believe they are reasonable. The forward-looking
information contained in this document is generally located in the material set
forth under the heading “Management’s Discussion and Analysis of Financial
Condition and Results of Operations” but may be found in other locations as
well. These forward-looking statements generally relate to our plans and
objectives for future operations and are based upon our management’s reasonable
estimates of future results or trends. The factors that may affect our
expectations regarding our operations include, among others, the
following:
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our
success in development, exploitation and exploration
activities;
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our
ability to make planned capital
expenditures;
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declines
in our production of oil and gas;
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prices
for oil and gas;
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our
ability to raise equity capital or incur additional
indebtedness;
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·
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economic
and business conditions;
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political
and economic conditions in oil producing countries, especially those in
the Middle East;
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price
and availability of alternative
fuels;
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our
restrictive debt covenants;
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our
acquisition and divestiture
activities;
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results
of our hedging activities; and
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·
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other
factors discussed elsewhere in this
document.
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Part
I
Item 1.
Business
In
this report, PV-10 means estimated future net revenue discounted at a rate of
10% per annum, before income taxes and with no price or cost escalation or
de-escalation in accordance with guidelines promulgated by the Securities and
Exchange Commission. A Mcf is one thousand cubic feet of gas. MMcf is used to
designate one million cubic feet of gas and Bcf refers to one billion cubic feet
of gas. Mcfe means thousands of cubic feet of gas equivalents, using a
conversion ratio of one barrel of oil to six Mcf of gas. MMcfe means millions of
cubic feet of gas equivalents and Bcfe means billions of cubic feet of gas
equivalents. MMBtu means million British Thermal Units. The term Bbl means one
barrel of oil or natural gas liquids and MBbls is used to designate one thousand
barrels of oil or natural gas liquids.
Information
contained in this report represents the operations of Abraxas Petroleum
Corporation and Abraxas Energy Partners, L.P., which we refer to as the
Partnership or Abraxas Energy Partners, which are consolidated for financial
reporting purposes. The interest of the 52.7% owners of the
Partnership is presented as minority interest. Abraxas beneficially
owns the remaining 47.3% of the partnership interests. Abraxas has determined
that based on its control of the general partner of the Partnership, this 47.3%
owned entity should be consolidated for financial reporting purposes. The terms
“Abraxas” or “Abraxas Petroleum” refer only to Abraxas Petroleum Corporation and
the terms “we,” “us,” “our,” or the “Company,” refer to Abraxas Petroleum
Corporation, together with its consolidated subsidiaries including Abraxas
Energy Partners, L.P., unless the context otherwise requires.
General
We are an
independent energy company primarily engaged in the development and production
of oil and gas. Historically, we have grown through the acquisition and
subsequent development and exploration of producing properties, principally
through the redevelopment of old fields utilizing new technologies such as
modern log analysis and reservoir modeling techniques as well as 3-D seismic
surveys and horizontal drilling. As a result of these activities, we believe
that we have a number of development opportunities on our properties. In
addition, we intend to expand upon our development activities with complementary
exploration projects in our core areas of operation. Success in our development
and exploration activities is critical in the maintenance and growth of our
current production levels and associated reserves.
At
December 31, 2008, our properties were located in the Rocky Mountain,
Mid-Continent, Permian Basin and Gulf Coast regions of the
United States.
Our Rocky
Mountain properties consist of the following:
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Northern
Rockies—Our properties in the Northern Rockies are located in the
Williston Basin of North Dakota, South Dakota and Montana and consist of
wells that produce oil from Paleozoic-aged carbonate reservoirs from the
Madison formation at 8,000 feet down to the Red River formation at
12,000 feet, including the Bakken at 9,000
feet.
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Southern
Rockies—Our properties in the Southern Rockies are located in the Green
River, Powder River and Uinta Basins of Wyoming, Colorado and Utah and
consist of wells that produce oil from Cretaceous-aged fractured shales in
the Mowry and Niobrara formation and oil and gas from
Cretaceous-aged sandstones in the Turner, Muddy and Frontier
formations. Well depths range from 7,000 feet down to
10,000 feet.
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We
have 894 gross (110 net) producing wells in the Rocky Mountain
region.
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Our
Mid-Continent properties consist of the following:
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Arkoma
Basin—Our properties in the Arkoma Basin are located in Oklahoma and
Arkansas and consist of wells that mainly produce gas from Hartshorne
coals at 3,000 feet.
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Anadarko
Basin—Our properties in the Anadarko Basin are located in Oklahoma and the
Texas Panhandle and consist of wells that mainly produce gas from
Pennsylvanian-aged sandstones (Atoka/Morrow) from depths of up to
18,000 feet.
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ARK-LA-TEX—Our
properties in the ARK-LA-TEX region principally produce from the East
Texas/North Louisiana Basins and include wells that produce oil and gas
from various formations.
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We
have 602 gross (103 net) producing wells in the Mid-Continent
region.
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Our
Permian Basin properties consist of the following:
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ROC
Complex—Our properties in the ROC Complex are located in Pecos, Reeves and
Ward Counties and consist of wells that produce oil and gas from multiple
stacked formations from the Bell Canyon at 5,000 feet down to the
Ellenburger at 16,000 feet.
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Oates
SW—Our properties in the Oates SW area are located in Pecos County and
consist of wells that produce gas from the Devonian formation at a depth
of approximately 13,500 feet.
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Eastern
Shelf – Our properties in the Eastern Shelf are predominately located in
Coke, Scurry and Mitchell Counties and consist of wells that produce oil
and gas from the Strawn Reef formation at 5,000 to 6,000 feet and oil from
the shallower Clearfork formation at depths ranging from 2,300 to 3,300
feet.
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We
have 236 gross (160 net) producing wells in the Permian Basin
region.
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Our Gulf
Coast properties consist of the following:
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Edwards—
Our properties in the Edwards trend are located in DeWitt and Lavaca
Counties and consist of wells that produce gas from the Edwards formation
at a depth of 13,500 feet.
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Portilla—The
Portilla field – located in San Patricio County, was discovered in 1950 by
The Superior Oil Company, predecessor to Mobil Oil Corporation, and
consists of wells that produce oil and gas from the Frio sands and the
deeper Vicksburg from depths of approximately 7,000 to
9,000 feet.
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Wilcox
– Our properties in the Wilcox are located in Goliad, Bee and Karnes
Counties and consist of wells that produce gas from various sands in the
Wilcox formation at depths ranging from 8,000 to 11,000
feet.
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We
have 79 gross (55 net) producing wells in the Gulf Coast
region.
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Markets
and Customers
The
revenue generated by our operations is highly dependent upon the prices of oil
and gas. Historically, the markets for oil and gas have been volatile and are
likely to continue to be volatile in the future. The prices we receive for our
oil and gas production are subject to wide fluctuations and depend on numerous
factors beyond our control including seasonality, the condition of the United
States economy (particularly the manufacturing sector), foreign imports,
political conditions in other oil-producing and gas-producing countries, the
actions of the Organization of Petroleum Exporting Countries and domestic
regulation, legislation and policies. Decreases in the prices of oil and gas
have had, and could have in the future, an adverse effect on the carrying value
of our proved reserves and our revenue, profitability and cash flow from
operations. You should read the discussion under “Risk Factors – Risks Relating
to Our Industry — Market conditions for oil and gas, and particularly
volatility of prices for oil and gas, could adversely affect our revenue, cash
flows, profitability and growth” and “Management’s Discussion and Analysis of
Financial Condition and Results of Operations – Critical Accounting Policies”
for more information relating to the effects of decreases in oil and gas prices
on us. To help mitigate the impact of commodity price volatility, we hedge a
portion of our production through the use of fixed price swaps. See
“Management’s Discussion and Analysis of Financial Condition and Results of
Operations – General – Commodity Prices and Derivative Activities” and Note 14
of the notes to our consolidated financial statements for more information
regarding our derivative activities.
Substantially
all of our oil and gas is sold at current market prices under short-term
arrangements, as is customary in the industry. During the year ended December
31, 2008, two purchasers accounted for approximately 29% of our oil and gas
sales. We believe that there are numerous other customers available to purchase
our oil and gas and that the loss of one or more of these purchasers would not
materially affect our ability to sell oil and gas.
Regulation
of Oil and Gas Activities
The
exploration, production and transportation of all types of hydrocarbons are
subject to significant governmental regulations. Our operations are affected
from time to time in varying degrees by political developments and federal,
state and local laws and regulations. In particular, oil and gas production
operations and economics are, or in the past have been, affected by industry
specific price controls, taxes, conservation, safety, environmental, and other
laws relating to the petroleum industry, and by changes in such laws and by
constantly changing administrative regulations.
Price
Regulations
In the
past, maximum selling prices for certain categories of oil, gas and natural gas
liquids were subject to significant federal regulation. At the present time,
however, all sales of our oil and gas produced under private
contracts may be sold at market prices. Congress could, however, re-enact price
controls in the future. If controls that limit prices to below market rates are
instituted, our revenue could be adversely affected.
Gas
Regulation
Historically,
the gas industry as a whole has been more heavily regulated than the oil or
other liquid hydrocarbons markets. Most regulations focus on transportation
practices. Currently, the Federal Energy Regulatory Commission (“FERC”) requires
each interstate pipeline to, among other things, “unbundle” its traditional
bundled sales services and create and make available on an open and
nondiscriminatory basis numerous constituent services (such as storage services,
firm and interruptible transportation services, and standby sales and gas
balancing services), and to adopt a ratemaking methodology to determine
appropriate rates for those services. To the extent the pipeline company or its
sales affiliate markets gas as a merchant, it does so pursuant to private
contracts in direct competition with all of the sellers, such as us; however,
pipeline companies and their affiliates are not required to remain “merchants”
of gas, and most of the interstate pipeline companies have become “transporters
only”, although many have affiliated marketers.
Transportation
pipeline availability and shipping cost are major factors affecting the
production and sale of gas. Our physical sales of gas are affected by the actual
availability, terms and cost of pipeline transportation. The price and terms for
access into the pipeline transportation systems remain subject to extensive
Federal regulation. Although FERC does not directly regulate our production and
marketing activities, it does affect how buyers and sellers gain access to and
use of the necessary transportation facilities and how we and our competitors
sell gas in the marketplace. FERC continues to review and modify its regulations
regarding the transportation of gas. The 2005 Energy Policy Act recently
authorized FERC to allow gas companies subject to the FERC’s Natural Gas Act
jurisdiction to provide gas storage and storage-related services at market-based
rates for new storage capacity of a storage facility placed in service after the
date of the Act’s August 2005 passage, thereby enhancing competition in the
market for interstate gas storage service.
In recent
years FERC also has pursued a number of important policy initiatives which could
significantly affect the marketing of gas in the United States. Most of these
initiatives are intended to enhance competition in gas markets. FERC rules
encouraging “spin downs”, or the breakout of unregulated gathering activities
from regulated transportation services, may have the adverse effect of
increasing the cost of doing business on some in the industry, including us, as
a result of the geographic monopolization of certain facilities by their new,
unregulated owners. Note, however; that FERC is pursuing an inquiry into whether
it should revise its test for determining whether and under what circumstances
FERC may reassert jurisdiction over gas gathering companies that have been
“spun-down” from an affiliated interstate gas pipeline to prevent abusive
practices by the gatherer and its pipeline affiliate. Any action taken by FERC
in this proceeding will be intended by it to enhance competition in the gas
transportation sector. As to all FERC initiatives, the ongoing, or,
in some instances, preliminary and evolving nature of such matters makes it
impossible at this time to predict their ultimate impact on our business.
However, we do not believe that any FERC initiatives will affect us any
differently than other gas producers and marketers with which we
compete.
FERC
decisions involving onshore facilities are more liberal in their reliance upon
traditional tests for determining what facilities are “gathering” and therefore
are exempt from federal regulatory control. In many instances, what was in the
past classified as “transmission” may now be classified as
“gathering.” We ship certain of our gas through gathering facilities
owned by others. Although FERC decisions create the potential for increasing the
cost of shipping our gas on third party gathering facilities, our shipping
activities have not been materially affected by these decisions.
In
summary, all FERC activities related to the transportation of gas result in
improved opportunities to market our physical production to a variety of buyers
and market places, while at the same time increasing access to pipeline
transportation and delivery services. Additional proposals and proceedings that
might affect the gas industry in the United States are considered from time to
time by Congress, FERC, state regulatory bodies and the courts. We cannot
predict when or if any such proposals might become effective or their effect, if
any, on our operations. The oil and gas industry historically has been very
heavily regulated; thus there is no assurance that the less stringent regulatory
approach recently pursued by FERC and Congress will continue indefinitely into
the future.
State
and Other Regulation
All of
the jurisdictions in which we own producing oil and gas properties have
statutory provisions regulating the exploration for and production of oil and
gas. These include provisions requiring permits for the drilling of wells and
maintaining bonding requirements in order to drill or operate wells and
provisions
relating
to the location of wells, the method of drilling and casing wells, the surface
use and restoration of properties upon which wells are drilled and the plugging
and abandoning of wells. Our operations are also subject to various conservation
laws and regulations. These include the regulation of the size of drilling and
spacing units or proration units on an acreage basis and the density of wells
which may be drilled and the unitization or pooling of oil and gas properties.
In this regard, some states allow the forced pooling or integration of tracts to
facilitate exploration while other states rely on voluntary pooling of lands and
leases. In addition, state conservation laws establish maximum rates of
production from oil and gas wells generally prohibit the venting or flaring of
gas and impose certain requirements regarding the ratability of production. Some
states, such as Texas and Oklahoma, have, in recent years, reviewed and
substantially revised methods previously used to make monthly determinations of
allowable rates of production from fields and individual wells. The effect of
all of these conservation regulations has the potential to limit the speed,
timing and amounts of oil and gas we can produce from our wells, and to limit
the number of wells or the location at which we can drill.
State
regulation of gathering facilities generally includes various safety,
environmental, and in some circumstances, non-discriminatory take or service
requirements, but does not generally entail rate regulation. In the United
States, gas gathering has received greater regulatory scrutiny at both the state
and federal levels in the wake of the interstate pipeline restructuring under
FERC Order 636. For example, the Texas Railroad Commission enacted a Natural Gas
Transportation Standards and Code of Conduct to provide regulatory support for
the State’s more active review of rates, services and practices associated with
the gathering and transportation of gas by an entity that provides such services
to others for a fee, in order to prohibit such entities from unduly
discriminating in favor of their affiliates.
For those
operations on Federal or Indian oil and gas leases, such operations must comply
with numerous regulatory restrictions, including various non-discrimination
statutes, and certain of such operations must be conducted pursuant to certain
on-site security regulations and other permits issued by various federal
agencies. In addition, on Federal Lands in the United States, the Minerals
Management Service (“MMS”) prescribes or severely limits the types of post
production costs that are deductible costs for purposes of royalty
valuation of production sold off the lease. In particular, MMS prohibits
deduction of costs associated with marketer fees, cash out and other pipeline
imbalance penalties, and or long-term storage fees. Between 2003 and 2005, the
MMS promulgated new rules and procedures for determining the value of oil
produced from federal lands for purposes of calculating royalties owed to the
government. As a general matter the oil and gas industry as a whole has resisted
these rules under an assumption that royalty burdens will substantially
increase. At this time, we are unable to predict the ultimate cost and effects
of these new rules on our operations.
Environmental
Matters
Our
operations are subject to numerous federal, state and local laws and regulations
controlling the generation, use, storage and discharge of materials into the
environment or otherwise relating to the protection of the environment. These
laws and regulations may require the acquisition of a permit or other
authorization before construction or drilling commences; restrict the types,
quantities, and concentrations of various substances that can be released into
the environment in connection with drilling, production, and gas processing
activities; suspend, limit or prohibit construction, drilling and other
activities in certain lands lying within wilderness, wetlands, and other
protected areas; require remedial measures to mitigate pollution from historical
and on-going operations such as use of pits and plugging of abandoned wells;
restrict injection of liquids into subsurface strata that may contaminate
groundwater; and impose substantial liabilities for pollution resulting from our
operations. Environmental permits required for our operations may be subject to
revocation, modification, and renewal by issuing authorities. Governmental
authorities have the power to enforce compliance with their regulations and
permits, and violations are subject to injunction, civil fines, and even
criminal penalties. Our management believes that we are in substantial
compliance with current environmental laws and regulations, and that we will not
be required to make material capital expenditures to comply with existing laws.
Nevertheless, changes in existing environmental laws and regulations or
interpretations thereof could have a significant impact on us as well as the oil
and gas industry in general, and thus we are unable to predict the ultimate cost
and effects of future changes in environmental laws and
regulations.
We are
not currently involved in any administrative, judicial or legal proceedings
arising under domestic or foreign federal, state, or local environmental
protection laws and regulations, or under federal or state common law, which
would have a material adverse effect on our financial position or results
of
operations.
Moreover, we maintain insurance against costs of clean-up operations, but we are
not fully insured against all such risks. A serious incident of pollution may
result in the suspension or cessation of operations in the affected
area.
Comprehensive
Environmental Response, Compensation and Liability Act. The
Comprehensive Environmental Response, Compensation and Liability Act, also known
as Superfund, and which we refer to as CERCLA, and comparable state statutes
impose strict, joint, and several liability, without regard to fault or legality
of conduct, on certain classes of persons who are considered to have contributed
to the release of a “hazardous substance” into the environment. These persons
include the owner or operator of a disposal site or sites where a release
occurred and companies that generated, disposed or arranged for the disposal of
the hazardous substances released at the site. Under CERCLA, such persons or
companies may be retroactively liable for the costs of cleaning up the hazardous
substances that have been released into the environment, for damages to natural
resources, and for the costs of certain health studies. CERCLA authorizes the
EPA and in some cases third parties, to take actions in response to threats to
the public health or the environment and to seek to recover from the responsible
classes of persons the costs they incur. In addition, it is not uncommon for
neighboring land owners and other third parties to file claims for personal
injury, property damage, and recovery of response costs allegedly caused by the
hazardous substances released into the environment.
In the
course of the ordinary operations of our properties, certain wastes may be
generated that may fall within CERCLA’s definition of a “hazardous substance.”
We may be jointly and severally liable under CERCLA or comparable state statutes
for all or part of the costs required to clean up sites at which these wastes
have been disposed. Although CERCLA currently contains a “petroleum exclusion”
from the definition of “hazardous substance,” state laws affecting our
operations impose cleanup liability relating to petroleum and petroleum related
products, including oil cleanups.
We
currently own or lease, and have in the past owned or leased, numerous
properties that for many years have been used for the exploration and production
of oil and gas. Although Abraxas Petroleum has utilized standard industry
operating and disposal practices at the time, hydrocarbons or other wastes may
have been disposed of or released on or under the properties we owned or leased
or on or under other locations where such wastes have been taken for disposal.
In addition, many of these properties have been operated by third parties whose
treatment and disposal or release of hydrocarbons or other wastes was not under
our control. These properties and the wastes disposed thereon may be subject to
CERCLA, RCRA (as defined below), and analogous state laws. Under these laws, we
could be required to remove or remediate previously disposed wastes, including
wastes disposed or released by prior owners or operators; to clean up
contaminated property, including contaminated groundwater; or to perform
remedial operations to prevent future contamination.
Oil Pollution Act
of 1990. United States federal
regulations also require certain owners and operators of facilities that store
or otherwise handle oil, such as us, to prepare and implement spill prevention,
control and countermeasure plans and spill response plans relating to possible
discharge of oil into surface waters. The federal Oil Pollution Act (“OPA”)
contains numerous requirements relating to prevention of, reporting of, and
response to oil spills into waters of the United States. For facilities that may
affect state waters, OPA requires an operator to demonstrate $10 million in
financial responsibility. State laws mandate oil cleanup programs with respect
to contaminated soil. A failure to comply with OPA’s requirements or inadequate
cooperation during a spill response action may subject a responsible party to
civil or criminal enforcement actions. We are not aware of any action or event
that would subject us to liability under OPA, and we believe that compliance
with OPA’s financial responsibility and other operating requirements will not
have a material adverse effect on us.
U.S.
Environmental Protection Agency. U.S. Environmental
Protection Agency regulations address the disposal of oil and gas operational
wastes under three federal acts more fully discussed in the paragraphs that
follow. The Resource Conservation and Recovery Act of 1976, as amended (“RCRA”),
provides a framework for the safe disposal of discarded materials and the
management of solid and hazardous wastes. The direct disposal of operational
wastes into offshore waters is also limited under the authority of the Clean
Water Act. When injected underground, oil and gas wastes are regulated by the
Underground Injection Control program under the Safe Drinking Water Act. If
wastes are classified as hazardous, they must be properly transported, using a
uniform hazardous waste manifest, documented, and disposed of at an approved
hazardous waste facility. We have coverage under the applicable Clean Water Act
permitting requirements for discharges associated with exploration and
development activities.
Resource
Conservation Recovery Act. RCRA is the principal
federal statute governing the treatment, storage and disposal of hazardous
wastes. RCRA imposes stringent operating requirements, and liability for failure
to meet such requirements, on a person who is either a “generator” or
“transporter” of hazardous waste or an “owner” or “operator” of a hazardous
waste treatment, storage or disposal facility. At present, RCRA includes a
statutory exemption that allows most oil and gas exploration and production
waste to be classified as nonhazardous waste. A similar exemption is contained
in many of the state counterparts to RCRA. As a result, we are not required to
comply with a substantial portion of RCRA’s requirements because our operations
generate minimal quantities of hazardous wastes. At various times in the past,
proposals have been made to amend RCRA to rescind the exemption that excludes
oil and gas exploration and production wastes from regulation as hazardous
waste. Repeal or modification of the exemption by administrative, legislative or
judicial process, or modification of similar exemptions in applicable state
statutes, would increase the volume of hazardous waste we are required to manage
and dispose of and would cause us to incur increased operating
expenses.
Clean Water
Act. The
Clean Water Act imposes restrictions and controls on the discharge of produced
waters and other wastes into navigable waters. Permits must be obtained to
discharge pollutants into state and federal waters and to conduct construction
activities in waters and wetlands. Certain state regulations and the general
permits issued under the Federal National Pollutant Discharge Elimination System
program prohibit the discharge of produced waters and sand, drilling fluids,
drill cuttings and certain other substances related to the oil and gas industry
into certain coastal and offshore waters. Further, the EPA has adopted
regulations requiring certain oil and gas exploration and production facilities
to obtain permits for storm water discharges. Costs may be associated with the
treatment of wastewater or developing and implementing storm water pollution
prevention plans. The Clean Water Act and comparable state statutes provide for
civil, criminal and administrative penalties for unauthorized discharges for oil
and other pollutants and impose liability on parties responsible for those
discharges for the costs of cleaning up any environmental damage caused by the
release and for natural resource damages resulting from the release. We believe
that our operations comply in all material respects with the requirements of the
Clean Water Act and state statutes enacted to control water
pollution.
Safe Drinking
Water Act.
Underground injection is the subsurface placement of fluid through a
well, such as the reinjection of brine produced and separated from oil and gas
production. The Safe Drinking Water Act of 1974, as amended establishes a
regulatory framework for underground injection, with the main goal being the
protection of usable aquifers. The primary objective of injection well operating
requirements is to ensure the mechanical integrity of the injection apparatus
and to prevent migration of fluids from the injection zone into underground
sources of drinking water. Hazardous-waste injection well operations are
strictly controlled, and certain wastes, absent an exemption, cannot be injected
into underground injection control wells. In Texas, no underground injection may
take place except as authorized by permit or rule. We currently own and operate
various underground injection wells. Failure to abide by our permits could
subject us to civil and/or criminal enforcement. We believe that we are in
compliance in all material respects with the requirements of applicable state
underground injection control programs and our permits.
Clean Air
Act. The Clean Air Act, which we refer to as the CAA, and
state air pollution laws and regulations provide a framework for national, state
and local efforts to protect air quality. The operations of our properties
utilize equipment that emits air pollutants which may be subject to federal and
state air pollution control laws. These laws require utilization of air
emissions abatement equipment to achieve prescribed emissions limitations and
ambient air quality standards, as well as operating permits for existing
equipment and construction permits for new and modified equipment.
Permits
and related compliance obligations under the CAA, as well as changes to state
implementation plans for controlling air emissions in regional non-attainment
areas, may require oil and gas exploration and production operators to incur
future capital expenditures in connection with the addition or modification of
existing air emission control equipment and strategies. In addition, some oil
and gas facilities may be included within the categories of hazardous air
pollutant sources, which are subject to increasing regulation under the CAA.
Failure to comply with these requirements could subject a regulated entity to
monetary penalties, injunctions, conditions or restrictions on operations and
enforcement actions. Oil and gas exploration and production facilities may be
required to incur certain capital expenditures in the future for air pollution
control equipment in connection with obtaining and maintaining operating permits
and approvals for air emissions. We believe that we are in compliance in all
material respects with the requirements of applicable federal and state air
pollution control laws.
The Kyoto
Protocol to the United Nations Framework Convention on Climate Change, or the
Protocol, became effective in February 2005. Under the Protocol, participating
nations are required to implement programs to reduce emissions of certain gases,
generally referred to as “greenhouse gases,” that are suspected of contributing
to global warming. The United States is not currently a participant in the
Protocol; however, Congress has recently considered proposed legislation
directed at reducing “greenhouse gas emissions,” and certain states have adopted
legislation, regulations and/or initiatives addressing greenhouse gas emissions
from various sources, primarily power plants. Additionally, on April 2,
2007, the U.S. Supreme Court ruled in Massachusetts v. EPA that the
EPA has authority under the CAA to regulate greenhouse gas emissions from mobile
sources (e.g., cars and
trucks). The Court also held that greenhouse gases fall within the CAA’s
definition of “air pollutant,” which could result in future regulation of
greenhouse gas emissions from stationary sources, including those used in oil
and gas exploration and production operations. The oil and gas industry is a
direct source of certain greenhouse gas emissions, namely carbon dioxide and
methane, and future restrictions on such emissions could impact our future
operations. Our properties are not adversely impacted by the current state and
local climate change initiatives and, at this time, it is not possible to
accurately estimate how potential future laws or regulations addressing
greenhouse gas emissions would impact our business.
Naturally
Occurring Radioactive Materials (“NORM”). NORM are materials not
covered by the Atomic Energy Act, whose radioactivity is enhanced by
technological processing such as mineral extraction or processing through
exploration and production conducted by the oil and gas industry. NORM wastes
are regulated under the RCRA framework, but primary responsibility for NORM
regulation has been a state function. Standards have been developed for worker
protection; treatment, storage and disposal of NORM waste; management of waste
piles, containers and tanks; and limitations upon the release of NORM
contaminated land for unrestricted use. We believe that our operations are in
material compliance with all applicable NORM standards established by the
various states in which we operate.
National
Environmental Policy Act. Oil and gas exploration and
production activities on federal lands are subject to the National Environmental
Policy Act, which we refer to as NEPA. NEPA requires federal agencies, including
the Department of Interior, to evaluate major agency actions having the
potential to significantly impact the environment. In the course of such
evaluations, an agency will prepare an Environmental Assessment that assesses
the potential direct, indirect and cumulative impacts of a proposed project and,
if necessary, will prepare a more detailed Environmental Impact Statement that
may be made available for public review and comment. If we were to conduct any
exploration and production activities on federal lands in the future, those
activities would need to obtain governmental permits that are subject to the
requirements of NEPA. This process has the potential to delay the development of
oil and gas projects.
Endangered
Species Act. The Endangered Species Act, which we refer to as
the ESA, restricts activities that may affect endangered or threatened species
or their habitats. While some of our facilities may be located in areas that may
be designated as habitat for endangered or threatened species, we believe that
we are in substantial compliance with the ESA. However, the discovery of
previously unidentified endangered or threatened species could cause us to incur
additional costs or become subject to operating restrictions or bans in the
affected areas.
Abandonment
Costs. All
of our oil and gas wells will require proper plugging and abandonment when they
are no longer producing. We post bonds with most regulatory agencies to ensure
compliance with our plugging responsibility. Plugging and abandonment operations
and associated reclamation of the surface production site are important
components of our environmental management system. We plan accordingly for the
ultimate disposition of properties that are no longer producing.
Title
to Properties
As is
customary in the oil and gas industry, we make only a cursory review of title to
undeveloped oil and gas leases at the time we acquire them. However,
before drilling commences, we require a thorough title search to be conducted,
and any material defects in title are remedied prior to the time actual drilling
of a well begins. To the extent title opinions or other investigations reflect
title defects, we, rather than the seller/lessor of the undeveloped property,
are typically obligated to cure any title defect at our expense. If we were
unable to remedy or cure any title defect of a nature such that it would not be
prudent to commence drilling operations on the property, we could suffer a loss
of our entire investment in the property. We believe that we have good title to
our oil and gas properties, some of which are subject to immaterial
encumbrances, easements and restrictions. The oil and gas properties we own are
also typically subject to royalty
and other similar non-cost bearing interests customary in the industry. We do
not believe that any of these encumbrances or burdens will materially affect our
ownership or use of our properties.
Competition
We
operate in a highly competitive environment. The principal resources necessary
for the exploration and production of oil and gas are leasehold prospects under
which oil and gas reserves may be discovered, drilling rigs and related
equipment to explore for such reserves and knowledgeable personnel to conduct
all phases of oil and gas operations. We must compete for such resources with
both major oil and gas companies and independent operators. Many of these
competitors have financial and other resources substantially greater than ours.
Although we believe our current operating and financial resources are adequate
to preclude any significant disruption of our operations in the immediate
future, we cannot assure you that such materials and resources will be available
to us. For more information, you should read “Risk Factors – Risks Related to
Our Industry – We operate in a highly competitive industry which may adversely
affect our operations.” and “– The unavailability or high cost of drilling rigs,
equipment, supplies, insurance, personnel and oil field services could adversely
affect our ability to execute our exploration and development plans on a timely
basis and within our budget.”
Employees
As of
February 13, 2009 we had 65 full-time employees. We retain independent
geological, land and engineering consultants from time to time on a limited
basis and expect to continue to do so in the future.
Available
Information
We file
annual, quarterly and current reports, proxy statements and other information
with the Securities and Exchange Commission. You may read and copy any document
we file with the SEC at the SEC’s public reference room at 100 F Street, NE,
Room 1580, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for
information on the public reference room. The SEC maintains an internet web site
that contains annual, quarterly and current reports, proxy statements and other
information that issuers (including Abraxas) file electronically with the SEC.
The SEC’s web site is www.sec.gov.
Our
Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on
Form 8-K and other reports and amendments filed with the Securities and Exchange
Commission are available free of charge on our web site at www.abraxaspetroleum.com
in the Investor Relations section as soon as practicable after such reports are
filed. Information on our website is not incorporated by reference
into this Form 10-K and should not be considered part of this report or any
other filing that we make with the SEC.
Item 1A. Risk Factors
Risks
Related to Our Business
We may not be able to fund the
substantial capital expenditures that will be required for us to increase
reserves and production.
We must
make substantial capital expenditures to develop our existing reserves and to
discover new reserves. Historically, we have financed our capital expenditures
primarily with cash flow from operations, borrowings under credit facilities,
sales of producing properties, and sales of debt and equity securities and we
expect to continue to do so in the future. Abraxas also anticipates receiving
distributions of available cash from the Partnership. We cannot assure you that
we will have sufficient capital resources in the future to finance all of our
capital expenditures.
Volatility
in oil and gas prices, the timing of both Abraxas’ and the
Partnership’s drilling programs and drilling results will affect both Abraxas’
and the Partnership’s cash flow from operations as well as distributions of
available cash by the Partnership to Abraxas. Lower prices and/or lower
production will also decrease revenues and cash flow, thus reducing the amount
of financial resources available to meet both Abraxas’ and the
Partnership’s capital requirements, including reducing the amount
available to pursue our drilling opportunities. If our cash flow from operations
does not increase as a result of planned capital expenditures,
a greater percentage of our cash flow from operations will be required for debt
service and operating expenses and our planned capital expenditures would, by
necessity, be decreased.
The
borrowing bases under Abraxas’ and the Partnership’s credit facilities are
determined from time to time by the lenders. Reductions in estimates of oil and
gas reserves could result in a reduction in the respective borrowing bases,
which would reduce the amount of financial resources available under these
facilities to meet our capital requirements. Such a reduction could be the
result of lower commodity prices or production, inability to drill or
unfavorable drilling results, changes in oil and gas reserve engineering, the
lenders’ inability to agree to an adequate borrowing base or adverse changes in
the lenders’ practices regarding estimation of reserves.
If cash
flow from operations or our borrowing bases decrease for any reason, both
Abraxas’ ability to undertake exploration and development activities, and the
Partnerships’ ability to undertake development activities could be adversely
affected. The Partnership’s ability to undertake exploration and development
activities will also be effected by the limitation set forth in the
Partnership’s Credit Facility limiting capital expenditures to $12.5 million
while the Partnership’s Subordinated Credit Agreement remains
outstanding. See “Management’s Discussion and Analysis of Financial
Condition and Results of Operations –Liquidity and Capital Resources – Long-Term
Indebtedness.” As a result, our ability to replace production may be
limited. In addition, if the borrowing bases under Abraxas’ and the
Partnership’s respective credit facilities are reduced, both Abraxas and the
Partnership would be required to reduce their borrowings under their respective
credit facilities so that such borrowings do not exceed such borrowing bases.
This could further reduce the cash available to us for capital spending and, if
either Abraxas or the Partnership did not have sufficient capital to reduce its
respective borrowing level, Abraxas and/or the Partnership may be in default
under their respective credit facilities.
Abraxas
has sold producing properties to provide it with liquidity and capital resources
in the past and both Abraxas and the Partnership may do so in the
future. After any such sale, we would expect to utilize the proceeds
to drill new wells on our remaining properties. If we cannot replace
the production lost from properties sold with production from the remaining
properties, both Abraxas’ and the Partnership’s cash flow from operations,
including distributions of available cash from the Partnership, will likely
decrease, which in turn, would decrease the amount of cash available for
additional capital spending.
We
may be unable to acquire or develop additional reserves, in which case our
results of operations and financial condition would be adversely
affected.
Our
future oil and gas production, and therefore our success, is highly dependent
upon our ability to find, acquire and develop additional reserves that are
profitable to produce. The rate of production from our oil and gas properties
and our proved reserves will decline as our reserves are
produced. Unless we acquire additional properties containing proved
reserves, conduct successful development and exploration activities or, through
engineering studies, identify additional behind-pipe zones or secondary recovery
reserves, we cannot assure you that our exploration and development activities
will result in increases in our proved reserves. Approximately 92% of the
Partnership’s and 85% of Abraxas’, or 92% of the estimated ultimate recovery of
our consolidated proved developed producing reserves as of December 31, 2008,
had been produced. Based on the reserve information set forth in our
reserve report of December 31, 2008, Abraxas’ average annual estimated
decline rate for its net proved developed producing reserves is 18% during the
first five years, 13% in the next five years, and approximately 7%
thereafter. Based on the reserve information set forth in our reserve
report of December 31, 2008, the Partnership’s average annual estimated decline
rate for its net proved developed producing reserves is 10% during the first
five years, 8% in the next five years and approximately 8%
thereafter. These rates of decline are estimates and actual
production declines could be materially higher. While Abraxas has had some
success in finding, acquiring and developing additional reserves, Abraxas has
not always been able to fully replace the production volumes lost from natural
field declines and prior property sales. For example, in 2006, Abraxas replaced
only 7% of the reserves it produced. As our proved reserves and
consequently our production decline, our cash flow from operations, the amount
of cash distributions Abraxas receives from the Partnership and the amount that
we are able to borrow under our credit facilities will also decline. In
addition, approximately 65% of Abraxas’ and 39% of the Partnership’s total
estimated proved reserves at December 31, 2008 were undeveloped. By their
nature, estimates of undeveloped reserves are less certain. Recovery of such
reserves will require significant capital expenditures and successful drilling
operations. Even if we are successful in our development efforts, it could take
several years for a significant portion of these undeveloped reserves to
generate positive cash flow.
We
may not find any commercially productive oil and gas
reservoirs.
We cannot
assure you that the new wells we drill will be productive or that we will
recover all or any portion of our capital investment. Drilling for oil and gas
may be unprofitable. Dry holes and wells that are productive but do not produce
sufficient net revenues after drilling, operating and other costs are
unprofitable. The inherent risk of not finding commercially productive
reservoirs will be compounded by the fact that 65% of Abraxas and 39% of the
Partnership’s, or 46% of our consolidated total estimated proved reserves at
December 31, 2008, were undeveloped. By their nature, estimates of undeveloped
reserves are less certain. Recovery of such reserves will require significant
capital expenditures and successful drilling operations. In addition, our
properties may be susceptible to drainage from production by other operations on
adjacent properties. If the volume of oil and gas we produce decreases, our cash
flow from operations and the amount of any distributions that Abraxas may
receive from the Partnership will decrease.
Our
drilling operations may be curtailed, delayed or cancelled as a result of a
variety of factors, including:
· unexpected
drilling conditions;
· facility
or equipment failure or accidents;
· shortages
or delays in the availability of drilling rigs, equipment and
crews;
· adverse
weather conditions;
· compliance
with environmental and governmental rules and regulations;
· title
problems;
· unusual
or unexpected geological formations;
· pipeline
ruptures;
· fires,
blowouts and explosions; and
· uncontrollable
flows of oil or gas or well fluids.
Restrictive debt covenants could
limit our growth and our ability to finance our operations, fund our capital
needs, respond to changing conditions and engage in other business activities
that may be in our best interests.
Abraxas’
credit facility and the Partnership’s credit facility contain a number of
significant covenants that, among other things, limit both Abraxas’ and the
Partnership’s ability to:
|
|
·
|
incur
or guarantee additional indebtedness and issue certain types of preferred
stock or redeemable stock;
|
· transfer
or sell assets;
· create
liens on assets;
|
|
·
|
pay
dividends or make other distributions on capital stock or make other
restricted payments, including repurchasing, redeeming or retiring capital
stock or subordinated debt or making certain investments or
acquisitions;
|
· engage
in transactions with affiliates;
· guarantee
other indebtedness;
· make
any change in the principal nature of our business;
· permit
a change of control; or
|
|
·
|
consolidate,
merge or transfer all or substantially all of the consolidated assets of
Abraxas and our restricted
subsidiaries.
|
In
addition, both Abraxas’ credit facility and the Partnership’s credit facility
require each of them to maintain compliance with specified financial ratios and
satisfy certain financial condition tests and the Partnership’s Credit Facility
limits the Partnership’s capital expenditures to $12.5 million while the
Partnership’s Subordinated Credit Agreement remains outstanding. Both
Abraxas’ and the Partnership’s ability to comply with these ratios and financial
condition tests may be adversely affected by events beyond our control, and we
cannot assure you that either Abraxas or the Partnership will meet these ratios
and financial condition tests. These financial ratio restrictions and
financial condition tests could limit both Abraxas’ and the Partnership’s
ability to obtain future financings, make needed capital expenditures, withstand
a future downturn in our business or the economy in general or otherwise conduct
necessary or desirable corporate activities.
A breach
of any of these covenants or either Abraxas’ or the Partnership’s inability to
comply with the required financial ratios or financial condition tests could
result in a default under Abraxas’ credit facility and/or the Partnership’s
credit facility. A default, if not cured or waived, could result in
all of our indebtedness becoming immediately due and payable. If that
should occur, we may not be able to pay all such debt or to borrow sufficient
funds to refinance it. Even if new financing were then available, it
may not be on terms that are acceptable or favorable to us.
The
marketability of our production depends largely upon the availability, proximity
and capacity of gas gathering systems, pipelines and processing
facilities.
The
marketability of our production depends in part upon processing and
transportation facilities. Transportation space on such gathering systems and
pipelines is occasionally limited and at times unavailable due to repairs or
improvements being made to such facilities or due to such space being utilized
by other companies with priority transportation agreements. Our access to
transportation options can also be affected by U.S. Federal and state regulation
of oil and gas production and transportation, general economic conditions and
changes in supply and demand. These factors and the availability of markets are
beyond our control. If market factors dramatically change, the financial impact
on us could be substantial and adversely affect our ability to produce and
market oil and gas.
An
increase in the differential between NYMEX and the reference or regional index
price used to price our oil and gas would reduce our cash flow from
operations.
Our oil
and gas is priced in the local markets where it is produced based on local or
regional supply and demand factors. The prices we receive for all of our oil and
gas are lower than the relevant benchmark prices, such as NYMEX. The difference
between the benchmark price and the price we receive is called a differential.
Numerous factors may influence local pricing, such as refinery capacity,
pipeline capacity and specifications, upsets in the midstream or downstream
sectors of the industry, trade restrictions and governmental regulations.
Additionally, insufficient pipeline capacity, lack of demand in any given
operating area or other factors may cause the differential to increase in a
particular area compared with other producing areas. For example, production
increases from competing Canadian and Rocky Mountain producers, combined with
limited refining and pipeline capacity in the Rocky Mountain area, have
gradually widened differentials in this area.
During
2008, differentials averaged $7.07 per Bbl of oil and $1.30 per Mcf of
gas. Approximately 39% of our production during 2008 was from our
Rocky Mountain and Mid-Continent properties. Historically, these
regions have experienced wider differentials than our Permian Basin and Gulf
Coast properties. As the percentage of our production from the Rocky
Mountain and Mid-Continent regions increases, we expect that our price
differentials will also increase. Increases in the differential
between the benchmark prices for oil and gas and the wellhead price we receive
could significantly reduce our revenues and our cash flow from
operations.
The
Partnership’s derivative contract activities could result in financial losses or
could reduce our cash flow.
To
achieve more predictable cash flow and reduce our exposure to adverse
fluctuations in the prices of oil and gas and to comply with the requirements
under the Partnership’s credit facility, we have and expect to continue to enter
into derivative contracts, which we sometimes refer to as hedging arrangements,
for a significant portion of our oil and gas production that could result in
both realized and unrealized derivative contract losses. The Partnership has
entered into NYMEX-based fixed price commodity swap
arrangements
on approximately 85% of its estimated oil and gas production from its estimated
net proved developed producing reserves through December 31, 2011. The extent of
our commodity price exposure is related largely to the effectiveness and scope
of our commodity price derivative contract activities. For example, the prices
utilized in our derivative instruments are NYMEX-based, which may differ
significantly from the actual prices we receive for oil and gas which are based
on the local markets where oil and gas are produced. The prices that we receive
for our oil and gas production are lower than the relevant benchmark prices that
are used for calculating commodity derivative positions. The difference between
the benchmark price and the price we receive is called a differential. As a
result, our cash flow could be affected if the basis differentials widen more
than we anticipate. For more information see ‘‘—An increase in the differential
between NYMEX and the reference or regional index price used to price our oil
and gas would reduce our cash flow from operations’’. We currently do not have
any basis differential hedging arrangements in place. Our cash flow could also
be affected based upon the levels of our production. If production is higher
than we estimate, we will have greater commodity price exposure than we
intended. If production is lower than the nominal amount that is subject to our
hedging arrangements, we may be forced to satisfy all or a portion of our
hedging arrangements without the benefit of the cash flow from our sale of the
underlying physical commodity, resulting in a substantial reduction in cash
flows.
If
the prices at which the Partnership has hedged its oil and gas production are
less than current market prices, its ability to maintain or increase cash
distributions could be adversely affected.
The
Partnership has entered into NYMEX-based fixed price commodity swap arrangements
on approximately 85% of its estimated oil and gas production from its estimated
net proved developed producing reserves through December 31, 2011. The volume
weighted average prices at which the Partnership has hedged this production are
$84.23 per barrel of oil and $8.27 per MMbtu of gas. The hedged prices of oil
and gas were greater than NYMEX future prices on December 31, 2008 of $44.60 per
barrel of oil and $5.62 per Mcf of gas. When the Partnership’s derivative
contract prices are at higher than market prices, the Partnership
will incur realized and unrealized gains on its derivative contracts and when
contract prices are lower than market prices, the Partnership will incur
realized and unrealized losses. For the year ended December 31, 2008 the
Partnership recognized a realized loss on oil and gas derivative contracts of
$9.3 million and an unrealized gain of $40.5 million. The realized loss resulted
in a decrease in cash flow from operations of the Partnership as well as
negatively impacting cash available for distribution by the Partnership. The
Partnership expects to continue to enter into similar hedging arrangements in
the future to reduce its cash flow volatility.
The
following table sets forth the Partnership’s oil and gas derivative contract
position at December 31, 2008:
|
Period
Covered
|
Product
|
Volume
(Production
per day)
|
Weighted
Average
Fixed
Price
|
|
Year
2009
|
Gas
|
10,595
Mmbtu
|
$ 8.45
|
|
Year
2009
|
Oil
|
1,000
Bbl
|
$ 83.80
|
|
Year
2010
|
Gas
|
9,130
Mmbtu
|
$ 8.22
|
|
Year
2010
|
Oil
|
895
Bbl
|
$ 83.26
|
|
Year
2011
|
Gas
|
8,010
Mmbtu
|
$ 8.10
|
|
Year
2011
|
Oil
|
810
Bbl
|
$ 86.45
|
We cannot
assure you that the derivative contracts that we have entered into, or will
enter into, will adequately protect us from financial loss in the future due to
circumstances such as:
· highly
volatile oil and gas prices;
· our
production being less than expected; or
· a
counterparty to one of our hedging transactions defaulting on its contractual
obligations.
Lower oil and gas
prices increase the risk of ceiling limitation write downs.
We use
the full cost method to account for our oil and gas operations. Accordingly, we
capitalize the cost to acquire, explore for and develop oil and gas properties.
Under full cost accounting rules, the net capitalized cost of oil and gas
properties may not exceed a “ceiling limit” which is based upon the
present
value of
estimated future net cash flows from proved reserves, discounted at 10%. If net
capitalized costs of oil and gas properties exceed the ceiling limit, we must
charge the amount of the excess to earnings. This is called a “ceiling
limitation write-down.” This charge does not impact cash flow from
operating activities, but does reduce our stockholders’ equity and earnings. The
risk that we will be required to write-down the carrying value of oil and gas
properties increases when oil and gas prices are low. In addition, write-downs
may occur if we experience substantial downward adjustments to our estimated
proved reserves. An expense recorded in one period may not be reversed in a
subsequent period even though higher oil and gas prices may have increased the
ceiling applicable to the subsequent period.
At
December 31, 2008, our net capitalized costs of oil and gas properties exceeded
the present value of our estimated proved reserves by $116.4 million resulting
in a write-down of $116.4 million. We cannot assure you that we will
not experience additional ceiling limitation writedowns in the
future.
Use of our net
operating loss carryforwards may be limited.
At
December 31, 2008, we had, subject to the limitation discussed below, $194.4
million of net operating loss carryforwards for U.S. tax purposes. These loss
carryforwards will expire through 2028 if not utilized. In addition, as to a
portion of the U.S. net operating loss carryforwards, the amount of such
carryforwards that we can use annually is limited under U.S. tax law. Moreover,
uncertainties exist as to the future utilization of the operating loss
carryforwards under the criteria set forth under FASB Statement No. 109.
Therefore, we have established a valuation allowance of $66.9 million for
deferred tax assets at December 31, 2006, $47.2 million at December 31, 2007 and
$60.8 million at December 31, 2008.
We
depend on our Chairman, President and CEO and the loss of his services could
have an adverse effect on our operations.
We depend
to a large extent on Robert L. G. Watson, our Chairman of the Board, President
and Chief Executive Officer, for our management and business and financial
contacts. Mr. Watson may terminate his employment agreement with us at any
time on 30 days notice, but, if he terminates without cause, he would not be
entitled to the severance benefits provided under the terms of that agreement.
Mr. Watson is not precluded from working for, with or on behalf of a
competitor upon termination of his employment with us. If Mr. Watson were
no longer able or willing to act as our Chairman, the loss of his services could
have an adverse effect on our operations. In addition, in connection with the
initial public offering by our previously wholly-owned subsidiary, Grey Wolf
Exploration Inc., we, Grey Wolf and Mr. Watson agreed that Mr. Watson
would continue to serve as our Chief Executive Officer and President and as the
Chief Executive Officer for Grey Wolf, with Mr. Watson devoting two-thirds
of his time to his positions and duties with us and one-third of his time to his
position and duties with Grey Wolf. In consideration for receiving
Mr. Watson’s services, Grey Wolf makes an annual payment to Abraxas of
US$100,000 and reimburses Abraxas for Mr. Watson’s expenses incurred in
connection with providing such services.
Risks
Related to Abraxas’ Ownership of General Partner Units and Common Units of the
Partnership
The
Partnership’s inability to refinance its obligations under the Subordinated
Credit Agreement would have a material adverse impact on the liquidity,
financial position and capital resources of Abraxas and the
Partnership.
The
Partnership’s subordinated credit agreement matures on July 1,
2009. The Partnership intends to refinance this obligation
prior to its scheduled maturity; however there can be no assurance that the
Partnership will be successful in this effort. In addition, under the
Partnership’s subordinated credit agreement, an event of default would occur if
the Partnership fails to receive $20.0 million of proceeds from an equity
issuance on or before April 30, 2009. Abraxas
Energy is currently in discussions with Société Générale to amend the existing
Senior Secured Credit Facility and/or the Subordinated Credit Agreement in the
event the IPO is not completed by April 30, 2009. The Partnership has
also entered into discussions with other lending institutions to re-finance the
$40 million currently outstanding on the Subordinated Credit
Agreement. While the Company believes that there are options to this
short term maturity requirement, there are no guarantees that any of these
options will be successfully implemented. If additional funds are obtained by
issuing equity securities, the Partnership’s existing unitholders, including
Abraxas, would be diluted and the distributions Abraxas receives from the
Partnership could decrease. To the extent that the Partnership is
unable to refinance theindebtedness under the subordinated credit agreement,
consummate an issuance of additional equity securities or obtain additional
financing,
the Partnership may be required to sell assets and reduce capital expenditures,
including distributions to Abraxas in order to avoid an event of
default. We cannot assure you that the Partnership will be able
to refinance the indebtedness under the Subordinated Credit Agreement, sell
assets, or obtain additional financing on terms acceptable to it, if at all. If
an event of default were to occur under the Subordinated Credit Agreement, an
event of default would also occur under the Partnership’s Credit
Facility. Upon an event of default, the Partnership’s lenders could
foreclose on the Partnership’s assets and exercise other customary remedies, all
of which would leave a material adverse effect on the Partnership and
Abraxas. See “Management’s Discussion and Analysis of Financial
Condition and Results of Operations – Long-Term Indebtedness Critical Accounting
Policies – Amended and Restated Partnership Credit Facility.”
The
Partnership may not have sufficient cash flow from operations to pay the
quarterly distributions on the general partner units and common units following
establishment of cash reserves and payment of fees and expenses.
Under the
terms of the Partnership’s partnership agreement, the amount of cash otherwise
available for distribution will be reduced by the Partnership’s operating
expenses and the amount of any cash reserve amounts that its general partner
establishes to provide for future operations, future capital expenditures,
future debt service requirements and future cash distributions to its
unitholders, including Abraxas. The Partnership has informed Abraxas
that the Partnership intends to reserve a substantial portion of its cash
generated from operations to develop its oil and gas properties and to acquire
additional oil and gas properties in order to maintain and grow the
Partnership’s level of oil and gas reserves.
The
amount of cash the Partnership actually generates will depend upon numerous
factors related to its business that may be beyond its control, including among
other things:
· the
amount of oil and gas it produces;
· price
of oil and gas;
· continued
drilling and development of oil and gas wells;
|
|
·
|
the
level of the Partnership’s operating costs, including reimbursement of
expenses to its general partner;
|
· prevailing
economic conditions; and
· government
regulation and taxation.
In addition, the actual
amount of cash that the Partnership will have available for distribution will
depend on other factors, including:
|
|
·
|
the
level of its capital expenditures;
|
|
|
·
|
its
ability to make borrowings under its credit facility to pay
distributions;
|
|
|
·
|
sources
of cash used to fund acquisitions;
|
|
|
·
|
debt
service requirements and restrictions on distributions contained in its
credit facility or future debt
agreements;
|
|
|
·
|
fluctuations
in its working capital needs;
|
|
|
·
|
general
and administrative expenses;
|
|
|
·
|
cash
settlement of hedging positions;
|
|
|
·
|
timing
and collectability of receivables;
and
|
|
|
·
|
the
amount of cash reserves, which the Partnership expects to be substantial,
established by its general partner for the proper conduct of its
business.
|
The
Partnership is unlikely to be able to sustain its expected level of
distributions without making accretive acquisitions or capital expenditures that
maintain or grow its asset base. If the Partnership does not set
aside sufficient cash reserves or make sufficient cash expenditures to maintain
its asset base, it will
be unable to pay distributions at the expected level from cash generated from
operations and would likely reduce distributions.
The
Partnership is unlikely to be able to sustain its expected level of
distributions without making accretive acquisitions or capital expenditures that
maintain or grow its asset base. The Partnership will need to make
capital expenditures to maintain and grow its asset base, which will reduce cash
available for distributions. Because the timing and amount of these
capital expenditures fluctuate each quarter, the Partnership expects to reserve
substantial amounts of cash each quarter to finance these expenditures over
time. The Partnership may use the reserved cash to reduce
indebtedness until it makes the capital expenditures. Over a longer
period of time, if the Partnership does not set aside sufficient cash reserves
or make sufficient expenditures to maintain its asset base, it may be unable to
pay distributions at the expected level from cash generated from operations and
would therefore expect to reduce cash distributions. Under the
terms of the Partnership Credit Agreement, the Partnership capital expenditures
are limited to $12.5 million until the Subordinated Credit Agreement has been
terminated. If the Partnership does not make sufficient growth
capital expenditures, it may be unable to sustain its business operations and
therefore will be unable to maintain its proposed or current level of
distributions and its business, financial condition and results of operations
would be adversely affected.
To fund its capital expenditures, the
Partnership will be required to use cash generated from operations, additional
borrowings or the issuance of additional partnership interests, or some
combination thereof.
Use of
cash generated from operations by the Partnership will reduce cash available for
distribution to Abraxas as a unitholder. The Partnership’s ability to
borrow from its credit facility or to obtain additional bank financing or to
access the capital markets for future equity or debt offerings may be limited by
its financial condition at the time of any such borrowing, financing or offering
and the covenants in its then-existing debt agreements, as well as by adverse
market conditions resulting from, among other things, general economic
conditions, operations and contingencies and uncertainties that are beyond the
Partnership’s control. The Partnership’s failure to obtain the funds
for necessary future capital expenditures could have a material adverse effect
on its business, results of operations, financial condition and ability to pay
distributions. Even if the Partnership is successful in obtaining the
necessary funds, the terms of such financings could limit its ability to pay
distributions to unitholders, including Abraxas. In addition,
incurring additional debt may significantly increase the Partnership’s interest
expense and financial leverage, and issuing additional partnership interests may
result in significant unitholder dilution thereby increasing the aggregate
amount of cash required to maintain the then-current distribution rate, which
could have a material adverse effect on the Partnership’s ability to pay
distributions at the then-current distribution rate.
Part of
the Partnership’s business strategy is to make accretive acquisitions of oil and
gas properties. Any future acquisition will require an assessment of recoverable
reserves, title, future commodity prices, operating costs, potential
environmental hazards, potential tax and ERISA liabilities, and other
liabilities and similar factors. Ordinarily, review efforts are focused on the
higher-valued properties and are inherently incomplete because it generally is
not feasible to review in depth every individual property involved in each
acquisition. Even a detailed due diligence review may not necessarily reveal
existing or potential problems, nor will it permit us to become sufficiently
familiar with the properties to fully assess their deficiencies and potential.
Inspections may not always be performed on every well, and potential problems,
such as ground water contamination and other environmental conditions and
deficiencies in the mechanical integrity of equipment are not necessarily
observable even when an inspection is undertaken. Any unidentified problems
could result in material liabilities and costs that negatively impact our
financial condition and results of operations and the Partnership’s ability to
make cash distributions to its unitholders, including Abraxas.
Additional
potential risks related to acquisitions include, among other
things:
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|
·
|
incorrect
assumptions regarding the future prices of oil and gas or the future
operating or development costs of properties
acquired;
|
· incorrect
estimates of the oil and gas reserves attributable to a property
acquired;
· unpredictable
production profiles and decline rates of properties acquired;
· an
inability to integrate successfully the properties acquired;
· the
assumption of liabilities;
· limitations
on rights to be indemnified by the seller;
· the
diversion of management's attention from other business concerns;
and
· losses
of key operational employees at the acquired properties.
The
Partnership’s ability to use hedging arrangements to protect it from future oil
and gas price declines will be dependent upon oil and gas prices at the time it
enters into these hedging arrangements and its future levels of hedging, and as
a result of its future net cash flow may be more sensitive to commodity price
changes.
The
Partnership has currently hedged a significant portion of its estimated oil and
gas production from its net proved developed producing reserves with NYMEX-based
fixed price commodity swaps. As the Partnership’s derivative
contracts expire, more of its future production will be sold at market prices
unless it enters into further hedging arrangements. The Partnership’s
commodity price hedging strategy and future hedging transactions will be
determined at the discretion of its general partner, which is not under any
future obligation to hedge a specific portion of its production. The
prices at which the Partnership hedges its production in the future will be
dependent upon commodity prices at the time it enters into these arrangements,
which may be substantially higher or lower than current oil and gas
prices. Accordingly, the Partnership’s commodity price hedging
strategy may not protect it from significant declines in oil and gas prices
received for its future production. Conversely, the Partnership’s
commodity price hedging strategy has limited and may in the future limit its
ability to realize increased cash flow from commodity price
increases. It is also possible that a substantially larger percentage
of the Partnership’s future production will not be hedged in the next few years,
which would result in its oil and gas revenues becoming more sensitive to
commodity price changes.
There
may be conflicts of interest between Abraxas and the Partnership which could be
detrimental to Abraxas.
Abraxas
owns and controls the general partner of the Partnership and some of Abraxas’
directors and officers are directors and executive officers of the
Partnership. Conflicts of interest exist and may arise between
Abraxas and the Partnership. For example, the Partnership could
acquire, develop or dispose of producing properties without any obligation to
offer Abraxas the opportunity to purchase or develop any of the
assets. In addition, it is currently anticipated that the executive
officers of the general partner, who are officers of Abraxas, will devote
between 30% and 60% of their time to the Partnership’s business.
The
general partner of the Partnership, which is wholly- owned by Abraxas, may be
removed as general partner with the consent of unitholders owning at
least 662/3% of the common units,
including units beneficially owned by Abraxas.
Holders
of the common units of the Partnership are currently unable to remove the
general partner without its consent because Abraxas beneficially owns sufficient
units to be able to prevent the removal of the general partner. The vote of the
holders of at least 66 2/3% of all outstanding common units voting together as a
single class is required to remove the general partner. If Abraxas’ beneficial
ownership decreases below 33 1/3%, its subsidiary could be removed as the
general partner which would result in Abraxas no longer controlling the business
of the Partnership.
Risks
Related to Our Industry
Market
conditions for oil and gas, and particularly volatility of prices for oil and
gas, could adversely affect our revenue, cash flows, profitability and
growth.
Our
revenue, cash flows, profitability and future rate of growth depend
substantially upon prevailing prices for oil and gas. Gas prices affect us more
than oil prices because 65% of our production and 72% of reserves were gas at
December 31, 2008. Prices also affect the amount of cash flow available
for
capital
expenditures and our ability to borrow money or raise additional capital. Lower
prices may also make it uneconomical for us to increase or even continue current
production levels of oil and gas.
Prices
for oil and gas are subject to large fluctuations in response to relatively
minor changes in the supply and demand for oil and gas, market uncertainty and a
variety of other factors beyond our control, including:
|
|
changes
in foreign and domestic supply and demand for oil and
gas;
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|
|
·
|
political
stability and economic conditions in oil producing countries, particularly
in the Middle East;
|
|
|
·
|
general
economic conditions;
|
|
|
·
|
domestic
and foreign governmental regulation;
and
|
|
|
·
|
the
price and availability of alternative fuel
sources.
|
The
current global recession has had a significant impact on commodity prices and
our operations. If commodity prices remain depressed our revenues, profitability
and cash flow from operations may decrease which could cause us to alter our
business plans, including reducing our drilling activities.
Estimates
of our proved reserves and future net revenue are inherently
imprecise.
The
process of estimating oil and gas reserves is complex involving decisions and
assumptions in evaluating the available geological, geophysical, engineering and
economic data. Accordingly, these estimates are imprecise. Actual future
production, oil and gas prices, revenues, taxes, development expenditures,
operating expenses and quantities of recoverable oil and gas reserves most
likely will vary from those estimated. Any significant variance could materially
affect the estimated quantities and present value of reserves set forth in this
report. In addition, we may adjust estimates of proved reserves to reflect
production history, results of exploration and development, prevailing oil and
gas prices and other factors, many of which are beyond our control.
The
estimates of our reserves are based upon various assumptions about future
production levels, prices and costs that may not prove to be correct over time.
In particular, estimates of oil and gas reserves, future net revenue from proved
reserves and the PV-10 thereof for our oil and gas properties are based on the
assumption that future oil and gas prices remain the same as oil and gas prices
at December 31, 2008. The sales prices as of such date used for purposes of such
estimates were $4.77 per Mcf of gas and $41.84 per Bbl of oil. This compares
with $6.33 per Mcf of gas and $87.30 per Bbl of oil as of December 31, 2007.
These estimates also assume that Abraxas and the Partnership will make future
capital expenditures of approximately $134.1 million in the aggregate primarily
from 2009 through 2014, which are necessary to develop and realize the value of
proved undeveloped reserves on our properties. In addition, approximately 46% of
our total estimated proved reserves as of December 31, 2008 were
undeveloped. By their nature, estimates of undeveloped reserves are less certain
than proved developed reserves. Any significant variance in actual results from
these assumptions could also materially affect the estimated quantity and value
of reserves set forth in this report.
The
present value of future net cash flows from our proved reserves is not
necessarily the same as the current market value of our estimated reserves. Any
material inaccuracies in our reserve estimates or underlying assumptions will
materially affect the quantities and present value of our reserves, which could
adversely affect our business, results of operations and financial
condition.
As
required by SEC regulations, we base the estimated discounted future net cash
flows from our proved reserves on prices and costs in effect on the day of the
estimate. However, actual future net cash flows from our properties will be
affected by factors such as:
· supply
of and demand for oil and gas;
· actual
prices we receive for oil and gas;
· our
actual operating costs;
· the
amount and timing of our capital expenditures;
· the
amount and timing of actual production; and
· changes
in governmental regulations or taxation.
The
timing of both our production and our incurrence of expenses in connection with
the development and production of our properties will affect the timing of
actual future net cash flows from proved reserves, and thus their actual present
value. In addition, the 10% discount factor we use when calculating discounted
future net cash flow, which is required by the SEC, may not be the most
appropriate discount factor based on interest rates in effect from time to time
and risks associated with us or the oil and gas industry in general. Any
material inaccuracies in our reserve estimates or underlying assumptions will
materially affect the quantities and present value of our reserves, which could adversely affect our business, results of
operations and financial condition.
Our
operations are subject to the numerous risks of oil and gas drilling and
production activities.
Our oil
and gas drilling and production activities are subject to numerous risks, many
of which are beyond our control. These risks include the risk of fire,
explosions, blow-outs, pipe failure, abnormally pressured formations and
environmental hazards. Environmental hazards include oil spills, gas leaks,
ruptures and discharges of toxic gases. In addition, title problems, weather
conditions and mechanical difficulties or shortages or delays in delivery of
drilling rigs and other equipment could negatively affect our operations. If any
of these or other similar industry operating risks occur, we could have
substantial losses. Substantial losses also may result from injury or loss of
life, severe damage to or destruction of property, clean-up responsibilities,
regulatory investigation and penalties and suspension of operations. In
accordance with industry practice, we maintain insurance against some, but not
all, of the risks described above. We cannot assure you that our insurance will
be adequate to cover losses or liabilities. Also, we cannot predict the
continued availability of insurance at premium levels that justify its
purchase.
We operate in a
highly competitive industry which may adversely affect our operations.
We
operate in a highly competitive environment. The principal resources necessary
for the exploration and production of oil and gas are leasehold prospects under
which oil and gas reserves may be discovered, drilling rigs and related
equipment to explore for such reserves and knowledgeable personnel to conduct
all phases of oil and gas operations. We must compete for such resources with
both major oil and gas companies and independent operators. Many of these
competitors have financial and other resources substantially greater than ours.
Although we believe our current operating and financial resources are adequate
to preclude any significant disruption of our operations in the immediate
future, we cannot assure you that such materials and resources will be available
to us.
The
unavailability or high cost of drilling rigs, equipment, supplies, insurance,
personnel and oil field services could adversely affect our ability to execute
our exploration and development plans on a timely basis and within our
budget.
Our
industry is cyclical and, from time to time, there is a shortage of drilling
rigs, equipment, supplies, insurance or qualified personnel. During these
periods, the costs and delivery times of rigs, equipment and supplies are
substantially greater. In addition, the demand for, and wage rates of, qualified
drilling rig crews rise as the number of active rigs in service increases. As a
result of increasing levels of exploration and production in response to strong
prices of oil and gas, the demand for oilfield services has risen and the costs
of these services are increasing.
Our
oil and gas operations are subject to various Federal, state and local
regulations that materially affect our operations.
Matters
regulated include permits for drilling operations, drilling and abandonment
bonds, reports concerning operations, the spacing of wells and unitization and
pooling of properties and taxation. At various times, regulatory agencies have
imposed price controls and limitations on production. In order to conserve
supplies of oil and gas, these agencies have restricted the rates of flow of oil
and gas wells below actual production capacity. Federal, state and local laws
regulate production, handling, storage, transportation and disposal of oil and
gas, by-products from oil and gas and other substances and materials produced or
used in connection with oil and gas operations. To date, our expenditures
related to complying with these laws and for remediation of existing
environmental contamination have not been significant. We believe that we are in
substantial compliance with all applicable laws and regulations. However,
the
requirements
of such laws and regulations are frequently changed. We cannot predict the
ultimate cost of compliance with these requirements or their effect on our
operations.
Risks
Related to the Common Stock
Future
issuance of additional shares of common stock could cause dilution of ownership
interests and adversely affect the stock price.
Abraxas
is currently authorized to issue 200,000,000 shares of common stock with such
rights as determined by our board of directors. Abraxas may in the future issue
its previously authorized and unissued securities, resulting in the dilution of
the ownership interests of current stockholders. In addition, under the terms of
the Exchange and Registration Rights Agreement entered into in connection with
the transactions completed in May 2007 and amended in October 2008, Abraxas may
be required to issue additional shares of common stock. Under the terms of this
amended agreement, in the event that the Partnership has not consummated its
initial public offering by April 30, 2009, which we refer to as the Trigger
Date, the investors will have the right to convert their common units obtained
in the private placement offering into shares of common stock. Each
common unit will be convertible into a number of shares of common stock equal to
$16.66 divided by the volume weighted average price of the common stock for the
ten (10) business day period immediately prior to the first business day
following the Trigger Date times 0.9. If stockholder approval
is required for such issuance, Abraxas has agreed to call a special meeting of
the stockholders within 60 days of April 30, 2009, which we refer to as the
Exchange Filing Date, and the executive officers and directors of Abraxas have
agreed to vote the shares of common stock then held by them in favor of such
issuance. Under this agreement, Abraxas also agreed within 30 days of
the Trigger Date, to prepare and file with the Securities and Exchange
Commission a registration statement, which we refer to as the Exchange
Registration Statement, to enable the resale of the common stock, which we refer
to as the Exchange Shares, by the investors or their transferees from time to
time over any national stock exchange on which the common stock is then traded,
or in privately-negotiated transactions. If the Exchange Registration
Statement is not declared effective by the 120th day following the Trigger Date
(which period would be extended to the 180th day following the Trigger Date
under certain circumstances), then in addition to any other rights the investors
may have under the Exchange and Registration Rights Agreement or under
applicable law, Abraxas is required to pay an amount in cash as liquidated
damages and not as a penalty, equal to 1.0% of the product of $3.83 times the
number of Exchange Shares then held by such investor for each 30-day period
until the Exchange Registration Statement is declared effective. The potential
issuance of such additional shares of common stock may create downward pressure
on the trading price of the common stock. Abraxas may also issue additional
shares of common stock or other securities that are convertible into or
exercisable for common stock for capital raising or other business purposes.
Future sales of substantial amounts of common stock, or the perception that
sales could occur, could have a material adverse effect on the price of the
common stock.
Abraxas does not pay dividends on
common stock.
Abraxas
has never paid a cash dividend on its common stock and the terms of Abraxas’
credit facility prohibit its ability to pay dividends on Abraxas’ common
stock.
Shares
eligible for future sale may depress our stock price.
At
February 13, 2009, Abraxas had 49,621,711 shares of common stock outstanding of
which 4,334,568 shares were held by affiliates and, in addition, 2,398,778
shares of common stock were subject to outstanding options granted under certain
stock option plans (of which 1,965,987 shares were vested at February 13,
2009).
All of
the shares of common stock held by affiliates are restricted or controlled
securities under Rule 144 promulgated under the Securities Act of 1933, as
amended (the “Securities Act”). The shares of the common stock issuable upon
exercise of the stock options have been registered under the Securities Act.
Sales of shares of common stock under Rule 144 or another exemption under the
Securities Act or pursuant to a registration statement could have a material
adverse effect on the price of the common stock and could impair our ability to
raise additional capital through the sale of equity securities.
The price of
Abraxas common stock has been volatile and could continue to fluctuate
substantially.
The
Abraxas common stock is traded on the NASDAQ Stock Market. The market price of
the common stock has been volatile and could fluctuate substantially based on a
variety of factors, including the following:
· fluctuations
in commodity prices;
· variations
in results of operations;
· legislative
or regulatory changes;
· general
trends in the industry;
· market
conditions; and
· analysts’
estimates and other events in the oil and gas oil industry.
Abraxas
may issue shares of preferred stock with greater rights than the common
stock.
Subject
to the rules of the NASDAQ Stock Market, Abraxas’ articles of incorporation
authorize its 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 holders of the common stock. Any preferred stock that is issued may rank
ahead of the common stock in terms of dividends, priority and liquidation
premiums and may have greater voting rights than the common stock.
Anti takeover
provisions could make a third party acquisition of Abraxas
difficult.
Abraxas’
articles of incorporation and bylaws provide for a classified board of
directors, with each member serving a three-year term, and eliminate the ability
of stockholders to call special meetings or take action by written consent. Each
of the provisions in the articles of incorporation and bylaws could make it more
difficult for a third party to acquire Abraxas without the approval of its
board. In addition, the Nevada corporate statute also contains certain
provisions that could make an acquisition by a third party more
difficult.
An
active market may not continue for the common stock.
The
Abraxas common stock is quoted on the NASDAQ Stock Market. While there are
currently three market makers in the common stock, these market makers are not
obligated to continue to make a market in the common stock. In this event, the
liquidity of the common stock could be adversely impacted and a stockholder
could have difficulty obtaining accurate stock quotes.
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Item 1B. Unresolved Staff
Comments
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None.
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|
Item 2.
Properties
|
Primary Operating
Areas
The
following table sets forth certain information relating to our properties as of
December 31, 2008.
|
Producing
Wells
|
Average
Working
Interest
|
Estimated
Net Proved Reserves
(MMBOE)
|
Year
ended
December
31,
2008
Net
Production
(MBOE)
|
|
|
Rocky
Mountain
|
894
|
12.4%
|
4,935.7
|
404.2
|
|
Mid-Continent
|
602
|
17.1%
|
3,050.4
|
435.8
|
|
Permian
Basin
|
236
|
68.0%
|
10,413.6
|
545.0
|
|
Gulf
Coast
|
79
|
69.2%
|
6,716.0
|
222.0
|
|
Total
|
1,811
|
23.7%
|
25,115.7
|
1,607.0
|
Rocky
Mountain
Our Rocky
Mountain properties consist of the following:
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•
|
Northern
Rockies—Our properties in the Northern Rockies are located in the
Williston Basin of North Dakota, South Dakota and Montana and consist of
wells that produce oil from Paleozoic-aged carbonate reservoirs from the
Madison formation at 8,000 feet down to the Red River formation at
12,000 feet, including the Bakken at 9,000
feet.
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|
|
•
|
Southern
Rockies—Our properties in the Southern Rockies are located in the Green
River, Powder River and Uinta Basins of Wyoming, Colorado and Utah and
consist of wells that produce oil from Cretaceous-aged fractured shales in
the Mowry and Niobrara formation and oil and gas from Cretaceous-aged
sandstones in the Turner, Muddy and Frontier formations. Well depths range
from 7,000 feet down to
10,000 feet.
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Mid-Continent
Our
Mid-Continent properties consist of the following:
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•
|
Arkoma
Basin—Our properties in the Arkoma Basin are located in Oklahoma and
Arkansas and consist of wells that mainly produce gas from Hartshorne
coals at 3,000 feet.
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|
|
•
|
Anadarko
Basin—Our properties in the Anadarko Basin are located in Oklahoma and the
Texas Panhandle and consist of wells that mainly produce gas from
Pennsylvanian-aged sandstones (Atoka/Morrow) from depths of up to
18,000 feet.
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|
|
•
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ARK-LA-TEX—Our
properties in the ARK-LA-TEX region principally produce from the East
Texas/North Louisiana Basins and includes wells that produce oil and gas
from various formations.
|
Permian
Basin
Our
Permian Basin properties consist of the following:
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|
•
|
ROC
Complex—Our properties in the ROC Complex are located in Pecos, Reeves and
Ward Counties and consist of wells that produce oil and gas from multiple
stacked formations from the Bell Canyon at 5,000 feet down to the
Ellenburger at 16,000 feet.
|
|
|
•
|
Oates
SW—Our properties in the Oates SW area are located in Pecos County and
consist of wells that produce gas from the Devonian formation at a depth
of approximately 13,500 feet.
|
|
|
•
|
Eastern
Shelf – Our properties in the Eastern Shelf are predominately located in
Coke, Scurry and Mitchell Counties and consist of wells that produce oil
and gas from the Strawn Reef formation at 5,000 to 6,000 feet and oil from
the shallower Clearfork formation at depths ranging from 2,300 to 3,300
feet Wilcox – Our properties in the Wilcox are located in Goliad, Bee and
Karnes Counties and
|
consist
of wells that produce gas from various sands in the Wilcox formation at depths
ranging from8,000to 11,000 feet.
Gulf
Coast
Our Gulf
Coast properties consist of the following:
|
|
•
|
Edwards—Our
properties fields in the Edwards trend are located in Dewitt and Lavaca
counties and consist of wells which produce gas from the Edwards formation
at a depth of approximately
13,500 feet.
|
|
|
•
|
Portilla—The
Portilla field – located in San Patricio County, was discovered in 1950 by
The Superior Oil Company, predecessor to Mobil Oil Corporation, and
consists of wells that produce oil and gas from the Frio sands and the
deeper Vicksburg from depths of approximately 7,000 to
9,000 feet.
|
|
|
•
|
Wilcox
– Our properties in the Wilcox are located in Goliad, Bee and Karnes
Counties and consist of wells that produce gas from various sands in the
Wilcox formation at depths ranging from 8,000 to 11,000
feet.
|
Exploratory
and Developmental Acreage
Our
principal oil and gas properties consist of producing and
non-producing oil and gas leases, including reserves of oil and gas in place.
The following table indicates our interest in developed and undeveloped acreage
and fee mineral acreage as of December 31, 2008
|
Developed
Acreage
(1)
|
Undeveloped
Acreage(2)
|
Fee
Mineral
Acreage
(3)
|
Total
Net
Acres
(6)
|
|||||||
|
Gross
Acres(4)
|
Net
Acres
(5)
|
Gross
Acres(4)
|
Net
Acres
(5)
|
Gross
Acres(4)
|
Net
Acres
(5)
|
|||||
|
Rocky
Mountain (7)
|
63,225
|
32,903
|
92,317
|
64,376
|
-
|
-
|
97,279
|
|||
|
Mid-Continent
(8)
|
85,812
|
21,949
|
1,957
|
988
|
-
|
-
|
22,937
|
|||
|
Permian
Basin (9)
|
24,574
|
17,197
|
10,882
|
8,768
|
12,007
|
5,272
|
31,237
|
|||
|
Gulf
Coast (10)
|
11,699
|
6,675
|
4,837
|
2,013
|
-
|
-
|
8,688
|
|||
|
Total
|
185,310
|
78,724
|
109,993
|
76,145
|
12,007
|
5,272
|
160,141
|
|||
|
|
_______________
|
|
(1)
|
Developed
acreage consists of leased acres spaced or assignable to productive
wells.
|
|
(2)
|
Undeveloped
acreage is considered to be those leased acres on which wells have not
been drilled or completed to a point that would permit the production of
commercial quantities of oil and gas, regardless of whether or not such
acreage contains proved reserves.
|
|
(3)
|
Fee
mineral acreage represents fee simple absolute ownership of the mineral
estate or fraction thereof.
|
|
(4)
|
Gross
acres refers to the number of acres in which we own a working
interest.
|
|
(5)
|
Net
acres represents the number of acres attributable to an owner’s
proportionate working interest (e.g., a 50% working interest in
a lease covering 320 gross acres is equivalent to 160 net
acres).
|
(6) Includes
3,981 acres that are included in developed and undeveloped gross
acres.
|
(7)
|
The
following shows the amount of acreage owned by each of Abraxas and the
Partnership in Rocky Mountain region as of December 31,
2008:
|
|
Developed
Acreage
|
Undeveloped
Acreage
|
||||||||
|
Gross
Acres
|
Net
Acres
|
Gross
Acres
|
Net
Acres
|
Total
Net
Acres
|
|||||
|
Abraxas
|
6,814
|
5,401
|
31,977
|
28,598
|
33,999
|
||||
|
Partnership
|
56,411
|
27,502
|
60,340
|
35,778
|
63,280
|
||||
|
Total
|
63,225
|
32,903
|
92,317
|
64,376
|
97,279
|
||||
|
(8)
|
The
following shows the amount of acreage owned by each of Abraxas and the
Partnership in Mid-Continent region as of December 31,
2008:
|
|
Developed
Acreage
|
Undeveloped
Acreage
|
||||||||
|
Gross
Acres
|
Net
Acres
|
Gross
Acres
|
Net
Acres
|
Total
Net
Acres
|
|||||
|
Abraxas
|
679
|
16
|
-
|
-
|
16
|
||||
|
Partnership
|
85,133
|
21,933
|
1,957
|
988
|
22,921
|
||||
|
Total
|
85,812
|
21,949
|
1,957
|
988
|
22,937
|
||||
|
(9)
|
The
following shows the amount of acreage owned by each of Abraxas and the
Partnership in Permian Basin region as of December 31,
2008:
|
|
Developed
Acreage
|
Undeveloped
Acreage
|
Fee
Mineral
Acreage
|
|||||||||||
|
Gross
Acres
|
Net
Acres
|
Gross
Acres
|
Net
Acres
|
Gross
Acres(6)
|
Net
Acres
|
Total
Net
Acres
|
|||||||
|
Abraxas
|
14,793
|
11,323
|
9,456
|
7,981
|
12,007
|
5,272
|
24,575
|
||||||
|
Partnership
|
12,425
|
8,388
|
1,766
|
1,127
|
-
|
-
|
9,515
|
||||||
|
Total
(a)
|
28,218
|
19,711
|
11,222
|
9,108
|
12,007
|
5,272
|
34,090
|
||||||
|
|
(a)
|
Abraxas
and the Partnership have common ownership in certain developed and
undeveloped acreage with each having rights at varying
depths.
|
|
(10)
|
The
following shows the amount of acreage owned by each of Abraxas and the
Partnership in Gulf Coast region as of December 31,
2008:
|
|
Developed
Acreage
|
Undeveloped
Acreage
|
||||||||
|
Gross
Acres
|
Net
Acres
|
Gross
Acres
|
Net
Acres
|
Total
Net
Acres
|
|||||
|
Abraxas
|
4,969
|
2,757
|
4,008
|
1,828
|
4,585
|
||||
|
Partnership
|
6,730
|
3,917
|
829
|
185
|
4,103
|
||||
|
Total
|
11,699
|
6,675
|
4,837
|
2,013
|
8,688
|
||||
Productive
Wells
The
following table sets forth our total gross and net productive wells expressed
separately for oil and gas, as of December 31, 2008:
|
Productive
Wells (1)
|
||||
|
As
of December 31, 2008
|
||||
|
Oil
|
Gas
|
|||
|
Gross
(2)
|
Net
(3)
|
Gross
(2)
|
Net
(3)
|
|
|
Rocky
Mountain (4)
|
384.0
|
92.9
|
510.0
|
17.5
|
|
Mid-Continent
(5)
|
126.0
|
15.3
|
476.0
|
87.8
|
|
Permian
Basin (6)
|
171.0
|
131.7
|
65.0
|
28.8
|
|
Gulf
Coast (7)
|
34.5
|
26.7
|
44.5
|
27.9
|
|
Total
|
715.5
|
266.6
|
1,095.5
|
162.0
|
____________
|
(1)
|
Productive
wells are producing wells and wells capable of
production.
|
|
(2)
|
A
gross well is a well in which we own an
interest.
|
|
(3)
|
A
net well is deemed to exist when the sum of fractional ownership working
interests in gross wells equals
one.
|
|
(4)
|
The
following table sets forth the productive wells owned by Abraxas and the
Partnership in the Rocky Mountain region as of December 31,
2008:
|
|
Productive
Wells
|
|||||||||
|
As
of December 31, 2008
|
|||||||||
|
Oil
|
Gas
|
||||||||
|
Gross
|
Net
|
Gross
|
Net
|
||||||
|
Abraxas
|
21.0
|
18.3
|
12.0
|
1.3
|
|||||
|
Partnership
|
363.0
|
74.6
|
498.0
|
16.2
|
|||||
|
Total
|
384.0
|
92.9
|
510.0
|
17.5
|
|||||
|
(5)
|
The
following table sets forth the productive wells owned by Abraxas and the
Partnership in the Mid-Continent region as of December 31,
2008:
|
|
Productive
Wells
|
|||||||||
|
As
of December 31, 2008
|
|||||||||
|
Oil
|
Gas
|
||||||||
|
Gross
|
Net
|
Gross
|
Net
|
||||||
|
Abraxas
|
1.0
|
0.1
|
1.0
|
-
|
|||||
|
Partnership
|
125.0
|
15.2
|
475.0
|
87.8
|
|||||
|
Total
|
126.0
|
15.3
|
476.0
|
87.8
|
|||||
|
(6)
|
The
following table sets forth the productive wells owned by Abraxas and the
Partnership in the Permian Basin region as of December 31,
2008:
|
|
Productive
Wells
|
|||||||||
|
As
of December 31, 2008
|
|||||||||
|
Oil
|
Gas
|
||||||||
|
Gross
|
Net
|
Gross
|
Net
|
||||||
|
Abraxas
|
104.0
|
99.1
|
18.0
|
9.6
|
|||||
|
Partnership
|
67.0
|
32.6
|
47.0
|
19.2
|
|||||
|
Total
|
171.0
|
131.7
|
65.0
|
28.8
|
|||||
|
(7)
|
The
following table sets forth the productive wells owned by Abraxas and the
Partnership in the Gulf Coast region as of December 31,
2008:
|
|
Productive
Wells
|
|||||||||
|
As
of December 31, 2008
|
|||||||||
|
Oil
|
Gas
|
||||||||
|
Gross
|
Net
|
Gross
|
Net
|
||||||
|
Abraxas
|
3.0
|
.5
|
12.0
|
7.0
|
|||||
|
Partnership
|
31.5
|
26.2
|
32.5
|
20.9
|
|||||
|
Total
|
34.5
|
26.7
|
44.5
|
27.9
|
|||||
Reserves
Information
Oil and
gas reserves have been estimated as of December 31, 2006 and December 31, 2007
for all of our properties on those dates by DeGolyer and MacNaughton, of Dallas,
Texas. DeGolyer and MacNaughton estimated reserves for properties comprising
approximately 92% of the PV-10 of our oil and gas reserves as of December 31,
2008, and reserves for the remaining 8% of our properties were estimated by
Abraxas Petroleum personnel because we determined that it was not practical for
DeGolyer and MacNaughton to prepare reserve estimates for all of our properties
because we own a large number of properties with relatively low
values. DeGolyer and MacNaughton’s reserve report included a total of
412 properties, which comprised approximately 92% of the PV-10 of all our
properties and a total of 889 properties were included in the reserve estimates
prepared by Abraxas Petroleum personnel which comprised approximately 8% of our
PV-10 at December 31, 2008. Oil and gas reserves, and the estimates of the
present value of future net revenues there-from, were determined based on then
current prices and costs. Reserve calculations involve the estimate of future
net recoverable reserves of oil and gas and the timing and amount of future net
revenues to be received therefrom. Such estimates are not precise and are based
on assumptions regarding a variety of factors, many of which are variable and
uncertain. Proved
oil and gas reserves are the estimated quantities of oil and gas that 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 gas reserves are those expected to be
recovered through existing wells with existing equipment and operating methods.
All of the Company’s proved reserves are located in the continental United
States. Proved reserves were estimated in accordance with guidelines established
by the Securities and Exchange Commission and the FASB, which require that
reserve estimates e prepared under existing economic and operating conditions
with no provision for price and cost escalations except by contractual
arrangements; therefore, year-end prices and costs were used in estimating net
cash flows.
The
following table sets forth certain information regarding estimates of our oil,
gas liquids and gas reserves as of December 31, 2006, December 31, 2007 and
December 31, 2008.
|
Estimated
Proved Reserves
|
|||||||
|
Proved
Developed
|
Proved
Undeveloped
|
Total
Proved
|
|||||
|
As
of December 31, 2006
|
|||||||
|
Oil
(MBbls)
|
1,708
|
1,048
|
2,756
|
||||
|
Gas
(MMcf)
|
37,333
|
33,000
|
70,333
|
||||
|
As
of December 31, 2007
|
|||||||
|
Abraxas
|
|||||||
|
Oil
(MBbls)
|
1,017
|
908
|
1,925
|
||||
|
Gas
(MMcf)
|
4,574
|
17,969
|
22,543
|
||||
|
Partnership
|
|||||||
|
Oil
(MBbls)
|
1,167
|
39
|
1,206
|
||||
|
Gas
(MMcf)
|
29,334
|
36,126
|
65,460
|
||||
|
Total
|
|||||||
|
Oil
(MBbls)
|
2,184
|
947
|
3,131
|
||||
|
Gas
(MMcf)
|
33,908
|
54,095
|
88,003
|
||||
|
As
of December 31, 2008
|
|||||||
|
Abraxas
|
|||||||
|
Oil
(MBbls)
|
1,147
|
1,420
|
2,567
|
||||
|
Gas
(MMcf)
|
7,179
|
17,831
|
25,010
|
||||
|
Partnership
|
|||||||
|
Oil
(MBbls)
|
4,416
|
62
|
4,478
|
||||
|
Gas
(MMcf)
|
41,030
|
42,376
|
83,406
|
||||
|
Total
|
|||||||
|
Oil
(MBbls)
|
5,563
|
1,482
|
7,045
|
||||
|
Gas
(MMcf)
|
48,209
|
60,207
|
108,416
|
||||
The
process of estimating oil and gas reserves is complex and involves decisions and
assumptions in the evaluation of available geological, geophysical, engineering
and economic data. Therefore, these estimates are imprecise.
Actual
future production, oil and gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil and gas
reserves most likely will vary from those estimated. Any significant variance
could materially affect the estimated quantities and present value of reserves
set forth in this annual report. In addition, we may adjust estimates of proved
reserves to reflect production history, results of exploration and development,
prevailing oil and gas prices and other factors, many of which are beyond our
control.
You
should not assume that the present value of future net revenues referred to in
this Annual Report on Form 10-K statement is the current market value of our
estimated oil and gas reserves. In accordance with SEC requirements, the
estimated discounted future net cash flows from proved reserves are generally
based on prices and costs as of the end of the year of the estimate, or
alternatively, if prices subsequent to that date have increased, a price near
the periodic filing date of the Company’s consolidated financial statements may
be used. Because we use the full cost method to account for our oil and gas
operations, we are susceptible to significant non-cash charges during times of
volatile commodity prices because the full cost pool may be impaired when prices
are low. This is known as a “ceiling limitation write-down.” This charge does
not impact cash flow from operating activities but does reduce our stockholders’
equity and reported earnings. We have experienced ceiling limitation write-downs
in the past and we cannot assure you that we will not experience additional
ceiling limitation write-downs in the future. As of December 31, 2008, the
Company’s net capitalized costs of oil and gas properties exceeded the present
value
of its
estimated proved reserves by $116.4 million ($19.2 million on Abraxas Petroleum
properties and $97.1 million on the Partnership properties). These
amounts were calculated considering 2008 year-end prices of $44.60 per Bbl for
oil and $5.62 per Mcf for gas as adjusted to reflect the expected realized
prices for our proved oil and gas reserves compared to each of the full cost
pools.
For more
information regarding the full cost method of accounting, you should read the
information under “Management’s Discussion and Analysis of Financial Condition
and Results of Operations – Critical Accounting Policies.”
Actual
future prices and costs may be materially higher or lower than the prices and
costs as of the end of the year of the estimate. Any changes in consumption by
gas purchasers or in governmental regulations or taxation will also affect
actual future net cash flows. The timing of both the production and the expenses
from the development and production of oil and gas properties will affect the
timing of actual future net cash flows from proved reserves and their present
value. In addition, the 10% discount factor, which is required by the SEC to be
used in calculating discounted future net cash flows for reporting purposes, is
not necessarily the most accurate discount factor. The effective interest rate
at various times and the risks associated with us or the oil and gas industry in
general will affect the accuracy of the 10% discount factor.
The
estimates of our reserves are based upon various assumptions about future
production levels, prices and costs that may not prove to be correct over time.
In particular, estimates of oil and gas reserves, future net revenue from proved
reserves and the PV-10 thereof for the oil and gas properties described in this
report are based on the assumption that future oil and gas prices remain the
same as oil and gas prices at December 31, 2008. The average sales prices as of
such date used for purposes of such estimates were $41.74 per Bbl of oil and
$4.77 per Mcf of gas. It is also assumed that we will make future capital
expenditures of approximately $134.1 million in the aggregate primarily in the
years 2009 through 2014, which are necessary to develop and realize the value of
proved undeveloped reserves on our properties. Any significant variance in
actual results from these assumptions could also materially affect the estimated
quantity and value of reserves set forth herein.
We file
reports of our estimated oil and gas reserves with the Department of Energy. The
reserves reported to this agency are required to be reported on a gross operated
basis and therefore are not comparable to the reserve data reported
herein.
Oil,
Gas Liquids, and Gas Production and Sales Prices
The
following table presents our net oil and gas production, the average sales price
per Bbl of oil and per Mcf of gas produced and the average cost of production
per Boe of production sold, for the three years ended December 31,
2008:
|
2006
|
2007
|
2008
|
||||||||
|
Oil
production (Bbls)
|
200,436
|
196,944
|
549,887
|
|||||||
|
Gas
production (Mcf)
|
6,515,055
|
5,567,668
|
6,342,934
|
|||||||
|
Total
production (MBOE) (1) (2)
|
1,286
|
1,125
|
1,607
|
|||||||
|
Average
sales price per Bbl of oil (3)
|
$
|
62.10
|
$
|
65.30
|
$
|
81.35
|
||||
|
Average
sales price per Mcf of gas (3)
|
$
|
5.77
|
$
|
6.46
|
$
|
7.11
|
||||
|
Average
sales price per BOE (3)
|
$
|
38.44
|
$
|
41.70
|
$
|
61.66
|
||||
|
Average
cost of production per BOE produced (1)
|
$
|
9.12
|
$
|
10.02
|
$
|
16.57
|
||||
__________________
|
(1)
|
Oil
and gas were combined by converting gas to a BOE equivalent on the basis 6
Mcf of gas to 1 Bbl of oil. Production costs include direct
operating costs, ad valorem taxes and gross production
taxes.
|
|
(2)
|
The
following sets forth the production for Abraxas and the Partnership in
2007 and 2008:
|
|
(3)
|
Average
sales prices include the impact of hedging
activity.
|
|
2007
|
2008
|
|
|
Abraxas
:
|
||
|
Oil
production (Bbls)
|
119,188
|
97,729
|
|
Gas
production (Mcf)
|
2,815,045
|
838,193
|
|
Total
production (BOE)
|
588,362
|
237,428
|
|
Partnership
:
|
||
|
Oil
production (Bbls)
|
77,756
|
452,158
|
|
Gas
production (Mcf)
|
2,752,623
|
5,504,741
|
|
Total
production (BOE)
|
536,527
|
1,369,615
|
Drilling
Activities
The
following table sets forth our gross and net working interests in exploratory
and development wells drilled during the three years ended December 31,
2008:
|
2006
|
2007
|
2008
(7)
|
|||||||||
|
Gross(1)
|
Net(2)
|
Gross(1)
|
Net(2)
|
Gross(1)
|
Net(2)
|
||||||
|
Exploratory(3)
|
|||||||||||
|
Productive(4)
|
|||||||||||
|
Oil
|
-
|
-
|
-
|
-
|
-
|
||||||
|
Gas
|
1.0
|
1.0
|
1.0
|
0.6
|
1.0
|
0.6
|
|||||
|
Dry
holes(5)
|
1.0
|
1.0
|
1.0
|
1.0
|
-
|
-
|
|||||
|
Total
|
2.0
|
2.0
|
2.0
|
1.6
|
1.0
|
0.6
|
|||||
|
Development(6)
|
|||||||||||
|
Productive
(4)
|
|||||||||||
|
Oil
|
2.0
|
1.2
|
3.0
|
2.6
|
14.0
|
7.2
|
|||||
|
Gas
|
1.0
|
1.0
|
1.0
|
1.0
|
35.0
|
2.2
|
|||||
|
Dry
holes (5)
|
-
|
-
|
-
|
-
|
|||||||
|
Total
|
3.0
|
2.2
|
4.0
|
3.6
|
49.0
|
9.4
|
|||||
__________________
|
(1)
|
A
gross well is a well in which we own an
interest.
|
|
(2)
|
The
number of net wells represents the total percentage of working interests
held in all wells (e.g., total working interest of 50% is equivalent to
0.5 net well. A total working interest of 100% is equivalent to 1.0 net
well).
|
|
(3)
|
An
exploratory well is a well drilled to find and produce oil or gas in an
unproved area, to find a new reservoir in a field previously found to be
producing oil or gas in another reservoir, or to extend a known
reservoir.
|
|
(4)
|
A
productive well is an exploratory or a development well that is not a dry
hole.
|
|
(5)
|
A
dry hole is an exploratory or development well found to be incapable of
producing either oil or gas in sufficient quantities to justify completion
as an oil or gas well.
|
|
(6)
|
A
development well is a well drilled within the proved area of an oil or gas
reservoir to the depth of stratigraphic horizon (rock layer or formation)
noted to be productive for the purpose of extracting proved oil or gas
reserves.
|
|
(7)
|
The
following sets forth drilling activity for Abraxas and the Partnership for
2008:
|
|
Gross
|
Net
|
|||
|
Exploratory:
|
||||
|
Gas:
|
||||
|
Abraxas
|
1.0
|
0.6
|
||
|
Partnership
|
-
|
-
|
||
|
Total
exploratory
|
1.0
|
0.6
|
||
|
Development:
|
||||
|
Oil:
|
||||
|
Abraxas
|
7.0
|
6.9
|
||
|
Partnership
|
7.0
|
0.3
|
||
|
Gas:
|
||||
|
Abraxas
|
2.0
|
0.9
|
||
|
Partnership
|
33.0
|
1.3
|
||
|
Total
development
|
49.0
|
9.4
|
As of
February 13, 2009, we had no operated wells but several non-operated wells in
process of drilling and/or completing.
Office
Facilities
Our
executive and administrative offices are located at 18803 Meisner Drive, San
Antonio, Texas 78258, consisting of approximately 21,000 square feet. The
building is owned by Abraxas, and is subject to a real estate lien note. The
note bears interest at a fixed rate of 6.375%, and is payable in monthly
installments of principal and interest of $39,754 based on a twenty year
amortization. The note matures in May 2015 at which time the outstanding balance
becomes due. The note is secured by a first lien deed of trust on the property
and improvements. As of December 31, 2008, $5.4 million was outstanding on the
note.
Other
Properties
We own 10
acres of land, an office building, workshop, warehouse and house in Sinton,
Texas,, 603 acres of land and an office building in Scurry County,
Texas, 50 acres of land in Lavaca County, Texas, 160 acres of land in
Coke County, Texas and 11,537 acres of land in Pecos County, Texas. We also own
22 vehicles which are used in the field by employees. We own two workover rigs,
which are used for servicing our wells.
|
Item 3. Legal Proceedings
|
From time
to time, we are involved in litigation relating to claims arising out of our
operations in the normal course of business. At December 31, 2008, we were not
engaged in any legal proceedings that are expected, individually or in the
aggregate, to have a material adverse effect on our financial
condition.
|
|
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 the
fiscal year ended December 31, 2008.
Part
II
|
|
Item 5. Market for Registrant’s Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity
Securities
|
Market
Information
Abraxas
common stock began trading on the American Stock Exchange on August 18, 2000,
under the symbol “ABP.” On July 25, 2008, Abraxas common stock began trading
on The NASDAQ Stock Market under
the symbol "AXAS". The following table sets forth certain information as
to the high and low sales price quoted for Abraxas’ common stock on the American
Stock Exchange and NASDAQ.
|
Period
|
High
|
Low
|
|||||||
|
2007
|
|||||||||
|
First
Quarter
|
$
|
3.47
|
$
|
2.72
|
|||||
|
Second
Quarter
|
4.68
|
2.95
|
|||||||
|
Third
Quarter
|
4.73
|
3.25
|
|||||||
|
Fourth
Quarter
|
4.85
|
3.19
|
|||||||
|
2008
|
|||||||||
|
First
Quarter
|
$
|
4.35
|
$
|
3.11
|
|||||
|
Second
Quarter
|
5.41
|
3.25
|
|||||||
|
Third
Quarter
|
5.31
|
2.15
|
|||||||
|
Fourth
Quarter
|
2.48
|
0.65
|
|||||||
|
2009
|
First
Quarter (Through February 20, 2009)
|
$
|
1.48
|
$
|
0.75
|
||||
Holders
As of
February 13, 2009, Abraxas had 49,621,711 shares of common stock outstanding and
had approximately 1,178 stockholders of record.
Dividends
Abraxas
has not paid any cash dividends on its common stock and it is not presently
determinable when, if ever, Abraxas will pay cash dividends in the future. In
addition, our credit facility prohibits the payment of cash dividends on the
common stock. The Partnership pays distributions of available cash on
a quarterly basis. During 2008, the Partnership paid distributions of
$1.65 per unit. The Partnership’s credit agreement permits the
payment of distributions under certain conditions. You should read the
discussion under “Management’s Discussion and Analysis of Financial Condition
and Results of Operations - Liquidity and Capital Resources” for more
information regarding the restrictions on Abraxas’ ability to pay dividends and
on the Partnership’s ability to pay distributions.
Performance
Graph
Set forth
below is a performance graph comparing yearly cumulative total stockholder
return on the Abraxas common stock with (a) the monthly index of stocks included
in the Standard and Poor’s 500 Index and (b) the Energy Capital Solutions Index
(the “ECS Index”) of stocks of oil and gas exploration and production companies
with a market capitalization of less than $800 million (the “Comparable
Companies”). The Comparable Companies are: Brigham Exploration Co., Callon
Petroleum Company, Prime Energy Corp., Gasco Energy Inc., Double Eagle Petroleum
Company, Edge Petroleum Corporation, Houston American Energy Corp., CREDO
Petroleum Corporation, TXCO Resources, Inc., NGAS Resources Inc., Parallel
Petroleum Corporation and Toreador Resources Corp.
All of
these cumulative total returns are computed assuming the value of the investment
in Abraxas common stock and each index as $100.00 on December 31, 2003, and the
reinvestment of dividends at the frequency
with which dividends were paid during the applicable years. The years compared
are 2004, 2005, 2006, 2007 and 2008.
|
Dec.
31,
2003
|
Dec.
31,
2004
|
Dec.
31,
2005
|
Dec.
31,
2006
|
Dec.
31,
2007
|
Dec.
31,
2008
|
||||||||||||||
|
ECS
Index
|
$
|
100.00
|
$
|
141.99
|
$
|
245.31
|
$
|
260.86
|
$
|
213.03
|
$
|
129.35
|
|||||||
|
S&P
500
|
$
|
100.00
|
$
|
108.99
|
$
|
112.26
|
$
|
127.55
|
$
|
132.06
|
$
|
81.23
|
|||||||
|
ABP
|
$
|
100.00
|
$
|
188.62
|
$
|
429.27
|
$
|
251.22
|
$
|
313.82
|
$
|
58.54
|
|||||||
The
information contained above under the caption “Performance Graph” is being
“furnished” to the Securities and Exchange Commission and shall not be deemed to
be “soliciting material” or to be “filed” with the Securities and Exchange
Commission, nor shall such information be incorporated by reference into any
future filing under the Securities Act of 1933, as amended, or the Securities
Exchange Act of 1934, as amended, except to the extent that we specifically
incorporate it by reference into such filing.
|
|
Item 6. Selected Financial Data
|
The
following selected financial data as of and for the years ended is derived from
our Consolidated Financial Statements. The data should be read in conjunction
with our Consolidated Financial Statements and Notes thereto, and other
financial information included herein. See “Financial Statements” in Item
8.
Discontinued
operations in 2004 and 2005 represent the results of operations of Grey Wolf
Exploration, Inc. which was a wholly-owned Canadian subsidiary of Abraxas until
February 2005. In February 2005, Grey Wolf closed on an initial public offering
resulting in the substantial divestiture of Abraxas’ investment in Grey
Wolf.
|
Year
Ended December 31,
|
||||||||||||||||
|
2004
|
2005
|
2006
|
2007
|
2008
|
||||||||||||
|
(Dollars
in thousands except per share data)
|
||||||||||||||||
|
Total
revenue - continuing operations
|
$
|
33,854
|
$
|
49,216
|
$
|
51,077
|
$
|
48,309
|
$
|
100,310
|
||||||
|
Net
income (loss)
|
$
|
12,360
|
(2)
|
$
|
19,117
|
(1)
|
$
|
700
|
$
|
56,702
|
(3)
|
$
|
(52,403
|
)(4)
|
||
|
Net
income - discontinued operations
|
$
|
3,323
|
$
|
12,846
|
(1)
|
$
|
—
|
$
|
—
|
$
|
—
|
|||||
|
Net
income (loss) - continuing operations
|
$
|
9,037
|
$
|
6,271
|
$
|
700
|
$
|
56,702
|
$
|
(52,403
|
)
|
|||||
|
Net
income per common share – diluted
|
$
|
0.32
|
$
|
0.46
|
$
|
0.02
|
$
|
1.19
|
$
|
(1.07
|
)
|
|||||
|
Weighted
average shares outstanding – diluted (in thousands)
|
38,895
|
41,164
|
43,862
|
47,593
|
49,005
|
|||||||||||
|
Total
assets
|
$
|
152,685
|
$
|
121,866
|
$
|
116,940
|
$
|
147,119
|
$
|
211,839
|
||||||
|
Long-term
debt, excluding current maturities
|
$
|
126,425
|
$
|
129,527
|
$
|
127,614
|
$
|
45,900
|
$
|
130,835
|
||||||
|
Total
stockholders’ equity (deficit)
|
$
|
(53,464
|
)
|
$
|
(23,701
|
)
|
$
|
(22,165
|
)
|
$
|
55,847
|
$
|
4,658
|
|||
|
(1)
|
Includes
gain on the sale of foreign subsidiary of $17.3 million net of non-cash
tax of $6.1 million.
|
|
(2)
|
Includes
gain on debt extinguishment of $12.6 million and a deferred tax benefit of
$6.1 million.
|
|
(3)
|
Includes
a gain on sale of assets of $59.4
million.
|
|
(4)
|
Includes
proved property impairment of $116.4
million.
|
|
|
Item 7. Management’s Discussion And Analysis Of Financial Condition
And Results Of Operations
|
The
following is a discussion of our consolidated financial condition, results of
continuing operations, liquidity and capital resources. This discussion should
be read in conjunction with our Consolidated Financial Statements and the Notes
thereto. See “Financial Statements” in Item 8.
General
We are an
independent energy company primarily engaged in the development and production
of oil and gas. Historically, we have grown through the acquisition and
subsequent development and exploration of producing properties, principally
through the redevelopment of old fields utilizing new technologies such as
modern log analysis and reservoir modeling techniques as well as 3-D seismic
surveys and horizontal drilling. As a result of these activities, we believe
that we have a number of development opportunities on our properties. In
addition, we intend to expand upon our development activities with complementary
exploration projects in our core areas of operation. Success in our development
and exploration activities is critical in the maintenance and growth of our
current production levels and associated reserves.
While we
have attained positive net income from continuing operations in four of the last
five years, there can be no assurance that operating income and net earnings
will be achieved in future periods. Our financial results depend upon many
factors which significantly affect our results of operations including the
following:
|
|
·
|
the
sales prices of oil and gas;
|
|
|
·
|
the
level of total sales volumes of oil and
gas;
|
|
|
·
|
the
availability of, and our ability to raise additional capital resources and
provide liquidity to meet, cash flow
needs;
|
|
|
·
|
the
level of and interest rates on borrowings;
and
|
|
|
·
|
the
level and success of exploration and development
activity.
|
Commodity Prices
and Hedging Activities.
The results of our operations are highly dependent upon the prices
received for our oil and gas production. The prices we receive for our
production are dependent upon spot market prices, price differentials and the
effectiveness of our derivative contracts, which we sometimes refer to as
hedging arrangements. Substantially all of our sales of oil and gas are made in
the spot market, or pursuant to contracts based on spot market prices, and not
pursuant to long-term, fixed-price contracts. Accordingly, the prices received
for our oil and gas production are dependent upon numerous factors beyond our
control. Significant declines in prices for oil and gas could have a material
adverse effect on our financial condition, results of operations, cash flows and
quantities of reserves recoverable on an economic basis.
Recently,
the prices of oil and gas have been volatile. During the first half of 2006,
prices for oil and gas were sustained at record or near-record levels. Supply
and geopolitical uncertainties resulted in significant price volatility during
the remainder of 2006 with both oil and gas prices weakening. During 2007, oil
prices remained strong while gas prices began 2007 strong but weakened during
the course of the year. During the first half of 2008, prices for oil and gas
were sustained at record or near-record levels, however during the second half
of 2008, and subsequently, there has been a significant drop in prices. New York
Mercantile Exchange (NYMEX) futures price for West Texas Intermediate (WTI) oil
averaged $99.73 per barrel for 2008. WTI oil ended 2008 at $44.60 per
barrel. NYMEX Henry Hub futures price for gas averaged $8.85 per million British
thermal units (MMBtu) during 2008 and ended the year at $5.62. Subsequent to the
end of the 2008 prices for oil and gas have continued to decline. As of February
11, 2009 the (NYMEX) futures price for West Texas Intermediate (WTI) oil was
$36.22 per barrel and NYMEX Henry Hub futures price for gas was $4.57 per
million British thermal units (MMBtu). If commodity prices continue to decline,
our revenue and cash flow from operations could also decline. In
addition, lower commodity prices could also reduce the amount of oil and gas
that we can produce economically. The current global recession has had a
significant impact on commodity prices and our operations. If commodity prices
remain depressed our revenues, profitability and cash flow from operations may
decrease which could cause us to alter our business plans, including reducing
our drilling activities.
The
decline in commodity prices has also resulted in downward adjustments to our
estimated proved reserves at December 31, 2008. For 2008 we incurred a “ceiling
limitation write-down” under applicable accounting rules. Under these
rules, if the net capitalized cost of oil and gas properties exceed the PV-10 of
our reserves, we must charge the amount of the excess to earnings. As of
December 31, 2008, the Company’s net capitalized costs of oil and gas properties
exceeded the present value of its estimated proved reserves by $116.4 million
($19.2 million for Abraxas Petroleum properties and $97.1 million for the
Partnership properties). These amounts were calculated considering
2008 year-end prices of $44.60 per Bbl for oil and $5.62 per Mcf for gas as
adjusted to reflect the expected realized prices for each of our oil and gas
reserves compared to each of the full cost pools. This charge
does not impact cash flow from operating activities, but does reduce our
stockholder’s equity and earnings. The risk that we will be required
to write-down the carrying value of oil and gas properties increases when oil
and gas prices are low. In addition, write-downs may occur if we experience
substantial downward adjustments to our estimated proved reserves. An
expense recorded in one period may not be reversed in a subsequent period even
though higher gas and oil prices may have increased the ceiling applicable to
the subsequent period.
The
realized prices that we receive for our production differ from NYMEX futures and
spot market prices, principally due to:
|
|
·
|
basis
differentials which are dependent on actual delivery
location,
|
|
|
·
|
adjustments
for BTU content; and
|
|
|
·
|
gathering,
processing and transportation
costs.
|
During
2008, differentials averaged $7.07 per barrel of oil and $1.30 per Mcf of gas
compared to $3.10 per barrel of oil and $1.00 per Mcf of gas in 2007. We
experienced greater differentials during 2008 compared to prior years because of
the increased percentage of our production from the Rocky Mountain and
Mid-Continent regions which experience higher differentials than our Texas
properties. Approximately 39% of our production during 2008 was from
our Rocky Mountain and Mid-Continent properties. Historically, these
regions have experienced wider differentials than our Permian Basin and Gulf
Coast properties. As the percentage of our production from the Rocky
Mountain and Mid-Continent regions
increases,
we expect that our consolidated price differentials will also
increase. Increases in the differential between the benchmark prices
for oil and gas and the wellhead price we receive could significantly reduce our
revenues and our cash flow from operations.
Under the
terms of the Partnership’s credit facility, Abraxas Energy Partners was required
to enter into derivative contracts for specified volumes, which equated to
approximately 85% of the estimated oil and gas production through December 31,
2011 from its estimated net proved developed producing reserves. At
December 31, 2008 and continuing through December 2011, the Partnership has
NYMEX-based fixed price commodity swaps covering approximately 85% of its
estimated oil and gas production from its estimated net proved developed
producing reserves at volume weighted average prices of $84.23 per barrel of oil
and $8.27 per Mmbtu of gas. The Partnership intends to enter into
derivative contracts in the future to reduce the impact of price volatility on
its cash flow. By removing a significant portion of price volatility
on its future oil and gas production, the Partnership believes it will mitigate,
but not eliminate, the potential effects of changing commodity prices on its
cash flow from operations for those periods. However, when prevailing
market prices are higher than our contract prices, we will not realize increased
cash flow on the portion of the production that has been hedged. We
have sustained and in the future will sustain realized and unrealized losses on
our derivative contracts if market prices are higher than our contract prices.
Conversely, when prevailing market prices are lower than our contract prices, we
will sustain realized and unrealized gains on our derivative
contracts. For example, in 2007, the Partnership sustained an
unrealized loss of $6.3 million and a realized gain of $1.9
million. In 2008, the Partnership incurred a realized loss of $9.3
million and an unrealized gain of $40.5 million. We have not designated any of
these derivative contracts as a hedge as prescribed by applicable accounting
rules.
The
following table sets forth our derivative position at December 31,
2008:
|
Period
Covered
|
Product
|
Volume
(Production
per day)
|
Fixed
Price
|
|
Year
2009
|
Gas
|
10,595 Mmbtu
|
$ 8.45
|
|
Year
2009
|
Oil
|
1,000 Bbl
|
$ 83.80
|
|
Year
2010
|
Gas
|
9,130 Mmbtu
|
$ 8.22
|
|
Year
2010
|
Oil
|
895 Bbl
|
$ 83.26
|
|
Year
2011
|
Gas
|
8,010 Mmbtu
|
$ 8.10
|
|
Year
2011
|
Oil
|
810 Bbl
|
$ 86.45
|
At
December 31, 2008, the aggregate fair market value of our oil and gas derivative
contracts was an asset of approximately $39.2 million.
Production
Volumes. Because our proved reserves will decline as oil and gas are
produced, unless we find, acquire or develop additional properties containing
proved reserves or conduct successful exploration and development activities,
our reserves and production will decrease. Approximately 85% of the
estimated ultimate recovery of Abraxas’ and 92% of the Partnership’s, or 92% of
our consolidated proved developed producing reserves as of December 31, 2008 had
been produced. Based on the reserve information set forth in our
reserve estimates as of December 31, 2008, Abraxas’ average annual
estimated decline rate for its net proved developed producing reserves is 18%
during the first five years, 13% in the next five years, and approximately 7%
thereafter. Based on the reserve information set forth in our reserve
estimates as of December 31, 2008, the Partnership’s average annual estimated
decline rate for its net proved developed producing reserves is 10% during the
first five years, 8% in the next five years and approximately 8%
thereafter. These rates of decline are estimates and actual
production declines could be materially higher. While Abraxas has had
some success in finding, acquiring and developing additional revenues, Abraxas
has not always able to fully replace the production volumes lost from natural
field declines and prior property sales. For example, in 2006, Abraxas replaced
only 7% of the reserves it produced. In 2007, however, we replaced 219% of the
reserves we produced and in 2008, we replaced 555% of the reserves we produced
primarily as a result of the St. Mary property acquisition in January 2008. Our
ability to acquire or find additional reserves in the near future will be
dependent, in part, upon the amount of available funds for acquisition,
exploration and development projects. Please see “–Results of
Operations–Selected Operation Data” for a presentation of our production levels
for the three years.
We had
capital expenditures during 2008 of $183.6 million including $123.6 million for
the St. Mary property acquisition that closed in January, 2008. Capital
expenditures in 2008 also included approximately $5.6 million for the
acquisition of our corporate headquarters building. We have a capital budget for
2009 of approximately $32.0 million, of which $20.0 million is applicable to
Abraxas and $12.0 million applicable to the Partnership. Under the terms of the
Partnership credit facility, the Partnership’s capital expenditures may not
exceed $12.5 million prior to the termination of the Partnership’s subordinated
credit agreement. For more information, see “– Liquidity and Capital
Resources – Long-Term Indebtedness– Subordinated Credit
Agreement.” The final amount of our capital expenditures for
2009 will depend on our success rate, production levels, the availability of
capital and commodity prices.
The
following table presents historical net production volumes for the years ended
December 31, 2006, 2007 and 2008:
|
Year
Ended December 31,
|
|||
|
2006
|
2007
|
2008
|
|
|
Total
production (MMcfe)
|
7,718
|
6,749
|
9,642
|
|
Average
daily production (Mcfepd)
|
21,144
|
18,492
|
26,346
|
Availability of
Capital. As described more
fully under “Liquidity and Capital Resources” below, Abraxas’ sources of capital
going forward will primarily be cash from operating activities, funding under
the Credit Facility, cash on hand, distributions from the Partnership and if an
appropriate opportunity presents itself, proceeds from the sale of
properties. Abraxas Energy Partners’ principal sources of capital
will be cash from operating activities, borrowings under the Partnership Credit
Facility, and sales of debt or equity securities if available to
it. At December 31, 2008, Abraxas had approximately $6.5 million of
availability under the Credit Facility and the Partnership had approximately
$14.4 million of availability under the Partnership Credit
Facility.
Additionally
the Partnership’s Subordinated Credit Agreement matures on July 1,
2009. The Partnership has intended to repay its indebtedness under
the Subordinated Credit Agreement with proceeds from its initial public
offering. However, the equity capital markets have been negatively
affected in recent months. As a result, we cannot assure you that the
Partnership will be successful in completing the IPO prior to the maturity of
the Subordinated Credit Agreement. Abraxas
Energy is currently in discussions with Société Générale to amend the existing
Senior Secured Credit Facility and/or the Subordinated Credit Agreement in the
event the IPO is not completed by April 30, 2009. The Partnership has
also entered into discussions with other lending institutions to re-finance the
$40 million currently outstanding on the Subordinated Credit
Agreement. While the Company believes that there are options
to this short term maturity requirement, there are no guarantees that any of
these options will be successfully implemented.
Exploration and
Development Activity. We believe that our high quality asset base, high
degree of operational control and inventory of drilling projects position us for
future growth. Our properties are concentrated in locations that facilitate
substantial economies of scale in drilling and production operations and more
efficient reservoir management practices. At December 31, 2008, we operated
properties accounting for approximately 83% of our PV-10, giving us substantial
control over the timing and incurrence of operating and capital expenditures. We
have identified 234 additional drilling locations (of which 109 were classified
as proved undeveloped at December 31, 2008) on our existing properties, the
successful development of which we believe could significantly increase our
production and proved reserves. Over the five years ended December 31, 2008, we
drilled or participated in drilling 77 gross (34.8 net) wells of which 94.8%
resulted in commercially productive wells.
Our
future oil and gas production, and therefore our success, is highly dependent
upon our ability to find, acquire and develop additional reserves that are
profitable to produce. The rate of production from our oil and gas properties
and our proved reserves will decline as our reserves are produced unless we
acquire additional properties containing proved reserves, conduct successful
development and exploration activities or, through engineering studies, identify
additional behind-pipe zones or secondary recovery reserves. We cannot assure
you that our exploration and development activities will result in increases in
our proved reserves. In 2006, for example, Abraxas replaced only 7% of the
reserves it produced. In 2007, however, we replaced 219% of our reserves, and in
2008, we replaced 555% of our reserves, primarily as the result of the St. Mary
property acquisition in January 2008. If our proved reserves decline in the
future, our production may also decline and, consequently, our cash flow from
operations, distributions of available cash from the
Partnership
to Abraxas and the amount that Abraxas is able to borrow under its credit
facility and that the Partnership will be able to borrow under its credit
facility will also decline. In addition, approximately 65% of Abraxas’ and 39%
of the Partnership’s estimated proved reserves at December 31, 2008 were
undeveloped. By their nature, estimates of undeveloped reserves are less
certain. Recovery of such reserves will require significant capital expenditures
and successful drilling operations. We may be unable to acquire or develop
additional reserves, in which case our results of operations and financial
condition could be adversely affected.
Borrowings and
Interest. Abraxas Energy
Partners had indebtedness of approximately $125.6 under the Partnership Credit
Facility and $40 million under its Subordinated Credit Agreement as of December
31, 2008. At December 31, 2008 the Partnership had $14.4 million
available under its Partnership Credit Facility. At December 31, 2008, Abraxas
had availability of $6.5 million under its Credit Facility. As of December 31,
2008, there was no outstanding balance under this facility. If interest expense
increases as a result of higher interest rates or increased borrowings, more
cash flow from operations would be used to meet debt service
requirements. As a result, we would need to increase our cash flow
from operations in order to fund the development of our numerous drilling
opportunities which, in turn, will be dependent upon the level of our production
volumes and commodity prices. In order to mitigate its interest rate exposure,
the Partnership entered into an interest rate swap, effective August 12, 2008,
to fix its floating LIBOR-based debt. The Partnership’s two-year
interest rate swap arrangement for $100 million at a fixed rate of 3.367%
expires on August 12, 2010. This interest rate swap was amended in
February 2009 lowering the Partnership’s fixed rate to 2.95%.
Results
of Operations
Selected
Operating Data. The following table sets forth certain of our operating
data for the periods presented. Average prices reflect realized
prices including the impact of hedging activities.
|
Years
Ended December 31,
|
||||||||||
|
(dollars
in thousands, except per unit data.)
|
||||||||||
|
2006
|
2007
|
2008
|
||||||||
|
Operating
revenue(1):
|
||||||||||
|
Oil
sales
|
$
|
12,446
|
$
|
13,633
|
$
|
50,954
|
||||
|
Gas
sales
|
37,002
|
33,273
|
48,130
|
|||||||
|
Rig
and other
|
1,629
|
1,403
|
1,226
|
|||||||
|
Total
operating revenues
|
$
|
51,077
|
$
|
48,309
|
$
|
100,310
|
||||
|
Operating
income (loss) (2)
|
$
|
18,383
|
$
|
15,524
|
$
|
(74,017
|
)
|
|||
|
Oil
production (MBbls)
|
200.4
|
196.9
|
549.9
|
|||||||
|
Gas
production (MMcf)
|
6,515.0
|
5,567.7
|
6,342.9
|
|||||||
|
Average
oil sales price (per Bbl)
|
$
|
62.10
|
$
|
65.30
|
$
|
81.35
|
||||
|
Average
gas sales price (per Mcf)
|
$
|
5.77
|
$
|
6.46
|
$
|
7.11
|
||||
___________________
|
(1)
|
Revenue
is after the impact of hedging
activities.
|
|
(2)
|
Operating
loss in 2008 includes $116.4 million proved property
impairment.
|
Comparison
of Year Ended December 31, 2008 to Year Ended December 31, 2007
Operating Revenue. During the
year ended December 31, 2008, operating revenue from oil and gas sales increased
by $52.2 million from $46.9 million in 2007 to $99.1 million in 2008. The
increase in revenue was due to increased production volumes in 2008 as compared
to 2007 as well as higher oil and gas prices realized in 2008 as compared to
2007. The increase in production volumes contributed $29.1 million
to
revenue while increased commodity prices contributed $23.1 million to oil and
gas production revenue.
Oil
production volumes increased from 196.9 MBbls for the year ended December 31,
2007 to 549.9 MBbls for the same period of 2008. The increase in oil
sales volumes was primarily due to production from properties acquired in the
St. Mary acquisition that closed on January 31, 2008. Production for the year
ended December 31, 2008 from these properties added 313.4 MBbls of oil. Gas
production volumes increased from 5,568 MMcf for the year ended December 31,
2007 to 6,343 MMcf for the same period of 2008. The properties acquired in the
St. Mary acquisition contributed 1,566 MMcf of gas production during the year,
which was partially offset by natural field declines.
Average
sales prices in 2008, before realized gain (loss) on derivative contracts
were:
|
|
·
|
$92.66
per Bbl of oil, and
|
|
|
·
|
$ 7.59 per
Mcf of gas.
|
Average
sales prices in 2007, before realized gain (loss) on derivative
contracts were:
|
|
·
|
$69.22
per Bbl of oil, and
|
|
|
·
|
$ 5.98
per Mcf of gas.
|
Lease Operating Expense and
Production Taxes. Lease operating expense, or LOE, increased from $11.3
million in 2007 to $26.6 million in 2008. The increase in LOE was primarily due
to the properties acquired from St. Mary in January of 2008 as well as an
increase in ad valorem and severance taxes. Severance and ad valorem
taxes increased from $3.8 million in 2007 to $9.1 million in 2008. LOE related
to the properties acquired in the St. Mary property acquisition added $13.1
million to LOE during 2008. LOE on a per BOE basis for the year ended December
31, 2008 was $16.57 per BOE compared to $10.02 for the same period of 2007. The
increase in per BOE cost was attributable to the increase in the number of oil
wells as a result of the St. Mary acquisition, which are generally more
expensive to operate than gas wells, as well as the overall increase in
costs.
G&A Expense. General and
administrative, or G&A expense, excluding stock based
compensation increased from $5.4 million in 2007 to $5.7
million in 2008. The increase in G&A was primarily due to higher personnel
expenses associated with additional staff added to manage the properties
acquired from St. Mary. G&A expense on a per BOE basis was $3.56 for 2008
compared to $4.84 for the same period of 2007. The per BOE decrease was
attributable to the higher G&A expense being offset by higher production
volumes during 2008 as compared to 2007.
Stock-based
Compensation. We
currently utilize a standard option pricing model (i.e., Black-Scholes) to
measure the fair value of stock options granted to employees and
directors. Options granted to employees and directors are valued at
the date of grant and expense is recognized over the options vesting period. For
the year ended December 31, 2007 and 2008, stock based compensation was
approximately $996,000 and $1.4 million respectively.
DD&A Expense.
Depreciation, depletion and amortization, or DD&A, expense increased
from $14.3 million in 2007 to $23.3 million in 2008. The increase in DD&A
was primarily the result of increased production as well as an increase in the
depletion base as a result of the St. Mary acquisition. Our DD&A expense on
a per BOE basis for 2007 was $12.71 per BOE as compared to $14.53 per BOE in
2008. The increase in the per BOE basis was due to the increased production
volumes in 2008 as compared to 2007.
Interest Expense. Interest
expense increased to $10.5 million in 2008 compared to $8.4 million for in 2007.
The increase in interest expense was primarily due to the increase in long term
debt incurred by the Partnership as a result of the St. Mary
acquisition. The Partnerships’ debt as of December 31, 2008 was
$165.6 million compared to $45.9 million as of December 31, 2007.
Income
taxes. No current or deferred income tax expense or benefit
has been recognized due to losses or loss carryforwards and valuation allowance,
which has been recorded against such benefits.
Income (loss) from derivative
contracts. We account for derivative contract gains and losses based
on
realized
and unrealized amounts. The realized derivative gains or losses are determined
by actual derivative settlements during the period. Unrealized gains and losses
are based on the periodic mark to market valuation of derivative contracts in
place. Our derivative contract transactions do not qualify for hedge accounting
as prescribed by SFAS 133; therefore, fluctuations in the market value of the
derivative contracts are recognized in earnings during the current period.
Abraxas Energy Partners has entered into a series of NYMEX–based fixed price
commodity swaps, the estimated unearned value of which was an asset of
approximately $39.2 million as of December 31, 2008. For the year ended December
31, 2008, the Partnership realized a loss of $9.3 million related to these oil
and gas derivatives, and an unrealized gain of $40.5 million. This compares to
an unrealized loss of $6.3 million and a realized gain of $1.9 million in
2007.
Other
Expense. For the year
ended December 31, 2008 as the result of the exchange and registration rights
agreement whereby Partnership unitholders, under certain circumstances can
convert their Partnership units into Abraxas Common Stock, the Company has
recognized an expense of $7.4 million, including approximately $293,000 relating
to shares converted during the fourth quarter and $7.1 million representing the
fair value of potential conversions. This expense is included in other expense
on the accompanying Consolidated Statement of Operations for the year ended
December 31, 2008. See footnote 3 to the Consolidated Financial Statements for a
further description of the exchange and registration rights
agreement.
In August
of 2008, the Partnership entered into an interest rate swap, effective August
12, 2008, to fix its floating LIBOR based debt. The Partnership’s
two-year interest rate swap arrangement is for $100 million at a fixed rate of
3.367%. The arrangement expires on August 12, 2010. For the year
ended December 31, 2008, the Partnership realized a loss of approximately
$260,000 related to this derivative and an unrealized loss of $2.7 million. The
estimated unearned value of this agreement was a liability of $3.0 million as of
December 31, 2008. This interest rate swap was amended in February 2009 lowering
the Partnership’s fixed rate to 2.95%.
Ceiling Limitation Write-down.
We record the carrying value of our oil and gas properties using the full
cost method of accounting for oil and gas properties. Under this method, we
capitalize the cost to acquire, explore for and develop oil and gas
properties. Under the full cost accounting rules, the net capitalized
cost of oil and gas properties less related deferred taxes, are limited by
country, to the lower of the unamortized cost or the cost ceiling, defined as
the sum of the present value of estimated unescalated future net revenues from
proved reserves, discounted at 10%, plus the cost of properties not being
amortized, if any, plus the lower of cost or estimated fair value of unproved
properties included in the costs being amortized, if any, less related income
taxes. If the net capitalized cost of oil and gas properties exceeds
the ceiling limit, we are subject to a ceiling limitation write-down to the
extent of such excess. A ceiling limitation write-down is a charge to earnings
which does not impact cash flow from operating activities. However, such
write-downs do impact the amount of our stockholders' equity. The
cost ceiling represents the present value (discounted at 10%) of net cash flows
from sales of future production, using commodity prices on the last day of the
quarter, or alternatively, if prices subsequent to that date have increased, a
price near the periodic filing date of the our financial
statements. As of December 31, 2008, our net capitalized costs of oil
and gas properties exceeded the present value of our estimated proved reserves
by $116.4 million ($19.2 million on Abraxas Petroleum properties and $97.1
million on the Partnership properties). These amounts were calculated
considering 2008 year-end prices of $44.60 per Bbl for oil and $5.62 per Mcf for
gas as adjusted to reflect the expected realized prices for our oil and gas
reserves as compared to each of the full cost pools.
The risk
that we will be required to write-down the carrying value of our oil and gas
assets increases when oil and gas prices are depressed or
volatile. In addition, write-downs may occur if we have substantial
downward revisions in our estimated proved reserves or if purchasers or
governmental action cause an abrogation of, or if we voluntarily cancel,
long-term contracts for our gas. We cannot assure you that we will not
experience additional write-downs in the future. If commodity prices decline or
if any of our proved reserves are revised downward, a further write-down of the
carrying value of our oil and gas properties may be required.
Minority
interest. Minority interest
represents the share of the net income (loss) of Abraxas Energy Partners for the
period owned by the partners other than Abraxas Petroleum. Additionally,
in accordance with generally accepted accounting principles, when cumulative
losses applicable to the minority interest exceed the minority interest equity
capital in the entity, such excess and any further losses applicable to
the
minority interest are
charged to the earnings of the majority interest. If future earnings are
recognized by the minority interest, such earnings will then be credited to the
majority interest (Abraxas) to the extent of such losses previously absorbed and
any excess earnings will increase the recorded value. For the year ended
December 31, 2008, primarily as a result of the ceiling test impairment of the
Partnership’s oil and gas properties, losses applicable to the minority interest
exceeded the minority interest equity capital by $9.3 million and, as a result,
$9.3 million of the minority interest loss in excess of equity was charged to
earnings and was reflected as a reduction of the loss applicable to the minority
interest.
Comparison
of Year Ended December 31, 2007 to Year Ended December 31, 2006
Operating Revenue. During the
year ended December 31, 2007, operating revenue from oil and gas sales decreased
by $2.5 million from $49.4 million in 2006 to $46.9 million in 2007. The
decrease in revenue was primarily due to decreased production volumes in 2007 as
compared to 2006 offset by higher oil and gas prices realized in 2007 as
compared to 2006. Lower production volumes had a negative impact of $5.6 million
which was partially offset by higher realized prices, excluding derivative
activities, which contributed $3.1 million to oil and gas revenue for the year
ended December 31, 2007.
Oil sales
volumes decreased from 200.4 MBbls in 2006 to 196.9 MBbls during 2007. The
decrease in oil production was primarily due to natural field declines. Gas
sales volumes decreased from 6.5 Bcf in 2006 to 5.6 Bcf in 2007. This decrease
was primarily due to the sale of properties in Live Oak County, Texas effective
August 1, 2006, as well as natural field declines. Properties sold in 2006
contributed 182.3 MMcfe during 2006 prior to their sale. Production from a
Permian Basin well drilled and brought onto production in August 2005 produced
2.2 Bcf in 2006 as compared to 1.4 Bcf in 2007. The Permian Basin well, the La
Escalera 1AH well, provided approximately 20% of our Mcfe production for the
year ended December 31, 2007.
Average
sales prices in 2007, before realized loss on derivative contracts
were:
|
|
·
|
$69.22
per Bbl of oil, and
|
|
|
·
|
$ 5.98
per Mcf of gas.
|
Average
sales prices in 2006, before realized loss on derivative contracts
were:
|
|
·
|
$62.10
per Bbl of oil, and
|
|
|
·
|
$ 5.68
per Mcf of gas.
|
Lease Operating Expense and
Production Taxes. Lease operating expense, or LOE, decreased from $11.8
million in 2006 to $11.3 million in 2007. The decrease in LOE was primarily due
to a decrease in ad valorem and severance taxes. Severance and
ad valorem taxes decreased from $4.5 million in 2006 to $3.8 million in
2007. The decrease was due to revisions of values of some properties resulting
in a lower ad valorem tax assessment. Excluding taxes, LOE increased from
$7.3 million in 2006 to $7.4 million in 2007. This increase was due to a general
increase in the cost of field services. Our LOE on a per BOE for the year ended
December 31, 2007 was $10.00 per BOE compared to $9.16 per BOE in 2006. The
increase on a per BOE basis was primarily due to a decrease in production
volumes in 2007 as compared to 2006.
G&A Expense. General and
administrative, or G&A expense, excluding stock based
compensation increased from $4.2 million in 2006 to $5.4
million in 2007. The increase in G&A expense in 2007 was primarily due to
new, incremental G&A costs incurred by Abraxas Energy Partners and to higher
performance bonuses in 2007 as compared to 2006. Performance bonuses amounted to
$162,000 in 2006, as compared to $1.1 million in 2007. Our G&A expense on a
per BOE basis increased from $3.24 in 2006 to $4.84 in 2007. The increase in the
per BOE cost was due to increased G&A expense in 2007 as compared to 2006 as
well as decreased production volumes in 2007 as compared to 2006.
Stock-based
Compensation. We
currently utilize a standard option pricing model (i.e., Black-Scholes) to
measure the fair value of stock options granted to employees and
directors. Options granted to employees and directors are valued at
the date of grant and expense is recognized over the options vesting period. For
the year ended December 31, 2006 and 2007, stock based compensation was
approximately $998,000 and $996,000 respectively.
DD&A Expense.
Depreciation, depletion and amortization, or DD&A, expense decreased
from $14.9 million in 2006 to $14.3 million in 2007. The decrease in DD&A
was primarily due to increased reserves as of December 31, 2007 as compared to
December 31, 2006, as well as a decrease in production volumes in 2007 as
compared to 2006. Our DD&A expense on a per BOE basis for 2007 was $12.71
per BOE as compared to $11.30 per BOE in 2006. The increase in the per BOE basis
was due to the decreased production volumes in 2007 as compared to
2006.
Interest Expense. Interest
expense decreased to $8.4 million in 2007 compared to $16.8 million for 2006.
The decrease in interest expense was due to the redemption of our outstanding
senior secured notes and refinancing and repayment of our credit facility with
Wells Fargo Foothill in May 2007.
Loss on debt
extinguishments. The loss
on debt extinguishment consists primarily of the call premium and interest that
was paid in connection with the refinancing and redemption of our senior secured
notes in May 2007.
Income taxes. Federal income
tax and state of Texas margin tax have been recognized for the year ended
December 31, 2007 as a result of the gain on the sale of assets during the
period. No deferred income tax expense or benefit has been recognized due to
losses or loss carryforwards and valuation allowance, which has been recorded
against such benefits.
Gain on sale of assets. As a
result of the transactions related to the formation of Abraxas Energy Partners,
we recognized a gain of $59.4 million. This gain was calculated based on the
requirements of Staff Accounting Bulletin 51, (Topic 5H) based on the fact that
we elected gain treatment as a policy and the transaction met the following
criteria: (1) there were no additional broad corporate
reorganizations contemplated; (2) there was not a reason to believe that the
gain would not be realized, since there is no additional capital raising
transaction anticipated nor was there a significant concern about the new
entity’s ability to continue in existence; (3) the share price of capital raised
in the private placement was objectively determined; (4) no repurchases of the
new subsidiary’s units are planned; and (5) we acknowledge that we
will consistently apply the policy, and any future transactions that might
result in a loss must be recorded as a loss in the income
statement.
Income (loss) from derivative
contracts. We account for derivative contract gains and losses based on
realized and unrealized amounts. The realized derivative gains or losses are
determined by actual derivative settlements during the period. Unrealized gains
and losses are based on the periodic mark to market valuation of derivative
contracts in place. Our derivative contract transactions do not qualify for
hedge accounting as prescribed by SFAS 133; therefore, fluctuations in the
market value of the derivative contracts are recognized in earnings during the
current period. Abraxas Energy Partners has entered into a series of NYMEX–based
fixed price commodity swaps, the estimated unearned value of which was
approximately $(9.1) million as of December 31, 2007. For the year ended
December 31, 2007, we realized a gain on these derivative contracts of $1.9
million. As of December 31, 2007 we incurred unrealized losses on derivative
contracts of $6.3 million.
Minority interest. Minority
interest represents the share of the net income (loss) of Abraxas Energy
Partners for the period owned by the partners other than Abraxas Petroleum. For
the year ended December 31, 2007, the minority interest in the net loss of the
Partnership was approximately $1.8 million.
Liquidity
and Capital Resources
General.
The oil and gas industry is a highly capital intensive and cyclical business.
Our capital requirements are driven principally by our obligations to service
debt and to fund the following costs:
|
|
·
|
the
development of existing properties, including drilling and completion
costs of wells;
|
|
|
·
|
acquisition
of interests in additional oil and gas properties;
and
|
|
|
·
|
production
and transportation facilities.
|
The
amount of capital expenditures we are able to make has a direct impact on our
ability to increase cash flow from operations and, thereby, will directly affect
our ability to service our debt
obligations
and to continue to grow the business through the development of existing
properties and the acquisition of new properties.
Abraxas’
sources of capital going forward will primarily be cash from operating
activities, funding under its credit facility, distributions from the
Partnership and if an appropriate opportunity presents itself, proceeds from the
sale of properties. We may also seek equity capital although we may not be able
to complete any equity financings on terms acceptable to us, if at all. The
Partnership’s principal sources of capital will be cash from operating
activities, borrowings under the Partnership Credit Facility, and sales of debt
or equity securities if available to it.
Working Capital
(Deficit). At December 31, 2008 our current liabilities of $59.3 million
exceeded our current assets of $33.3 million resulting in working capital
deficit of $26.0 million. This compares to working capital of $11.3 million as
of December 31, 2007. Significant components of current liabilities as of
December 31, 2008 consisted of trade payables of $10.7 million, revenues due
third parties of $3.2 million, other accrued liabilities of $2.3 million,
current derivative liabilities of $3.0 million and current maturities of
long-term debt of $40.1 million, primarily related to the Partnership’s
Subordinated Credit Agreement. The Partnership has intended to repay
its indebtedness under the Subordinated Credit Agreement with proceedsfrom its
initial public offering. However, the equity capital markets have
been negatively affected in recent months. As a result, we cannot
assure you that the Partnership will be successful in completing the IPO prior
to the maturity of the Subordinated Credit Agreement. The Partnership
has entered into discussions with the lending institutions to either extend or
refinance the $40.0 million in debt under its Subordinated Credit Agreement, due
July 1, 2009. There can be no assurance that the Partnership will be
successful in such negotiations.
Capital
Expenditures. Capital expenditures related to our continuing operations
in 2006, 2007 and 2008 were $26.3 million, $26.9 million and $183.6 million,
respectively. The table below sets forth the components of these capital
expenditures for the three years ended December 31,
2008.
|
Year
Ended December 31,
|
||||||||||
|
2006
|
2007
|
2008
|
||||||||
|
(dollars
in thousands)
|
||||||||||
|
Expenditure
category:
|
||||||||||
|
Exploration/Development
|
$
|
26,117
|
$
|
16,793
|
$
|
49,610
|
||||
|
Acquisition
|
-
|
10,000
|
127,671
|
|||||||
|
Facilities
and other
|
229
|
115
|
6,351
|
|||||||
|
Total
|
$
|
26,346
|
$
|
26,908
|
$
|
183,632
|
||||
During
2006 and 2007, capital expenditures were primarily for the development of
existing properties and a deposit for the St. Mary property acquisition that
closed in January 2008. During 2008 capital expenditures included $127.7 million
for the acquisition of the St. Mary properties and other smaller acquisitions,
as well as the development of our properties. We anticipate making capital
expenditures for 2009 of $20.0 million. These anticipated expenditures are
subject to adequate cash flow from operations and availability under our
revolving credit facility. The Partnership anticipates making capital
expenditures for 2009 of $12.0 million which will be used primarily for the
development of its current properties. Additionally, while the Subordinated
Credit Agreement is outstanding, the Partnership’s capital expenditures are
limited to $12.5 million. These anticipated expenditures are subject
to adequate cash flow from operations, availability under Abraxas’ and the
Partnership’s Credit Facilities and, in Abraxas’ case, distributions of
available cash from the Partnership. If these sources of funding do not prove to
be sufficient, we may also issue additional shares of equity securities although
we may not be able to complete equity financings on terms acceptable to us, if
at all. Our ability to make all of our budgeted capital expenditures will also
be subject to availability of drilling rigs and other field equipment and
services. Our capital expenditures could also include expenditures for the
acquisition of producing properties if such opportunities
arise. Additionally, the level of capital expenditures will vary
during future periods depending on market conditions and other related economic
factors. There has been a significant decline in oil and gas prices since the
second quarter of 2008. Should the prices of oil and gas continue to decline and
if our costs of operations continue to increase as a result of the scarcity of
drilling rigs or if our production volumes
decrease,
our cash flows will decrease which may result in a reduction of the capital
expenditures budget. If we decrease our capital expenditures budget, we may not
be able to offset oil and gas production volumes decreases caused by natural
field declines and sales of producing properties, if any.
Sources of
Capital. The net funds provided by and/or used in each of the operating,
investing and financing activities, related to continuing operations, are
summarized in the following table and discussed in further detail
below:
|
Year
Ended December 31,
|
||||||||||
|
2006
|
2007
|
2008
|
||||||||
|
(dollars
in thousands)
|
||||||||||
|
Net
cash provided by operating activities
|
$
|
15,561
|
$
|
18,332
|
$
|
43,387
|
||||
|
Net
cash used in investing activities
|
(14,102
|
)
|
(26,908
|
)
|
(173,944
|
)
|
||||
|
Net
cash (used in) provided by financing activities
|
(1,458
|
)
|
27,469
|
113,545
|
||||||
|
Total
|
$
|
1
|
$
|
18,893
|
$
|
(17,012)
|
||||
Operating
activities for the year ended December 31, 2008 provided $43.4 million in cash
compared to providing $18.3 million in 2007. Net income plus non-cash expense
items and net changes in operating assets and liabilities accounted for most of
these funds, including the non–cash proved property impairment of $116.4
million. Financing activities provided $113.5 million for the year ended
December 31, 2008 as compared to providing $27.5 million in 2007. Most of the
funds provided in 2008 were the proceeds of long-term borrowing in connection
with the acquisition of the St. Mary properties in January 2008. Investing
activities used $173.9 million in 2008 including $127.7 million for the
acquisition of oil and gas properties as well as the development of our current
properties.
Operating
activities for the year ended December 31, 2007 provided $18.3 million in cash
compared to providing $15.6 million in the same period in 2006. Net income plus
non-cash expense items and net changes in operating assets and liabilities
accounted for most of these funds. Financing activities provided $27.5 million
for the year ended December 31, 2007 compared to using $1.5 million for the same
period of 2006. Most of the funds provided in 2007 were proceeds from the
issuance of common stock, proceeds from the sale of common units of the
Partnership and proceeds from the Partnership’s and Abraxas’ credit facilities.
In 2006, most of the funds used were for net reductions in long-term borrowings
from our revolving line of credit. Investing activities used $26.9 million
during the year ended December 31, 2007 compared to using $14.1 million for the
same period of 2006. Investing activities in 2007 included $16.9 million for the
development of our existing properties and $10 million for the St. Mary property
acquisition that was completed in January 2008.
Operating
activities for the year ended December 31, 2006 provided us with $15.6 million
of cash. Expenditures in 2006 of approximately $26.3 primarily for the
development of oil and gas properties offset by proceeds from the sale of oil
and gas properties of $12.2 million. Financing activities used $1.5 million
during 2006, of which $20.4 million was provided from long-term borrowing offset
by $22.4 million of payments on long-term debt.
Future Capital
Resources. Abraxas’ sources of capital going forward will primarily be
cash from operating activities, funding under the Credit Facility, cash on hand,
distributions from the Partnership and if an appropriate opportunity presents
itself, proceeds from the sale of properties. Abraxas Energy Partners’ principal
sources of capital will be cash from operating activities, borrowings under the
Partnership Credit Facility, and sales of debt or equity securities, if
available to it. The credit markets are undergoing significant volatility and
capacity constraints. Many financial institutions have liquidity
concerns, prompting government intervention to mitigate pressure on the credit
market. Our exposure to the current credit market crisis includes our
Credit Facility, the Partnership Credit Facility and the Subordinated Credit
Agreement and counterparty performance risk.
Our
Credit Facility and the Partnership Credit Facility are each subject to a
borrowing base. Our Credit Facility matures on June 27, 2011 and the
Partnership Credit Facility matures on January 31, 2013. Should
current credit market volatility be prolonged for several years, future
extensions of credit may contain terms that are less favorable than those in our
Credit Facility and the Partnership Credit Facility. The Subordinated
Credit Agreement matures on July 1, 2009. The Partnership has
intended to re-pay the
amounts
due under this agreement with the proceeds of the initial public
offering. However, the equity capital markets have been negatively
affected in recent months. As a result, we cannot assure you that the
Partnership will be successful in completing the IPO prior to the maturity of
the Subordinated Credit Agreement. In addition, the Partnership’s failure to
receive $20.0 million of proceeds from an equity issuance on or prior to April
30, 2009 would be an event of default under the Subordinated Credit
Agreement.
Current
market conditions also elevate concern over counterparty risks related to our
commodity derivative instruments. The Partnership has all of its
commodity derivative instruments with one major financial
institution. Should this financial counterparty not perform, we may
not realize the benefit of some of our hedges under lower commodity
prices. Although these derivative instruments as well as our Credit
Facility and the Partnership Credit Facility expose us to credit risk, we
monitor the creditworthiness of our counterparty, and we are not currently aware
of any inability on the part of our counterparty to perform under our
contracts. However, we are not able to predict sudden changes in the
credit worthiness of our counterparty.
Oil and
gas prices are also volatile and have declined significantly during the second
half of 2008 and have continued to decline since the end of the
year. Further, the decline in commodity prices has not been
accompanied by a relative decline in the prices of goods and services that we
use to drill, complete and operate our wells. The decline in
commodity prices has reduced our cash flow from operations from what it would
have otherwise been. To mitigate the impact of lower commodity prices
on our cash flows, we have entered into commodity derivative
contracts. As the result of the global recession, commodity prices
may stay depressed or reduce further, thereby causing a prolonged downturn,
which could further reduce our cash flows from operations. This could
cause us to alter our business plans, including reducing our exploration and
development plans.
Our cash
flow from operations will also depend upon the volume of oil and gas that we
produce. Unless we otherwise expand reserves, our production volumes may decline
as reserves are produced. For example, in 2006, Abraxas replaced only 7% of the
reserves it produced. In 2007 we replaced 219% of the reserves we produced and
in 2008, we replaced 555% of the reserves we produced, primarily as the result
of the St. Mary property acquisition in January 2008. In the future,
if an appropriate opportunity presents itself, we may sell producing properties,
which could further reduce our production volumes. To offset the loss in
production volumes resulting from natural field declines and sales of producing
properties, we must conduct successful exploration and development activities,
acquire additional producing properties or identify additional behind-pipe zones
or secondary recovery reserves. We believe our numerous drilling opportunities
will allow us to increase our production volumes; however, our drilling
activities are subject to numerous risks, including the risk that no
commercially productive oil and gas reservoirs will be found. If our proved
reserves decline in the future, our production will also decline and,
consequently, our cash flow from operations, distributions from the Partnership
and the amount that we are able to borrow under our credit facilities will also
decline. The risk of not finding commercially productive reservoirs will be
compounded by the fact that 65% of Abraxas Petroleum’s and 39% of the
Partnership’s total estimated proved reserves at December 31, 2008 were
undeveloped. For the year ended December 31, 2008, we expended approximately
$49.6 million on our exploration and development activities s and continued
general well maintenance and work-overs utilizing our own work-over
rigs
Contractual
Obligations. We are committed to making cash payments in the future on
our long-term debt.
We have
no off-balance sheet debt or unrecorded obligations and we have not guaranteed
the debt of any other party. Below is a schedule of the future payments that we
are obligated to make based on agreements in place as of December 31,
2008.
|
Payments
due in:
|
||||||||||||||||
|
Contractual
Obligations (dollars in thousands)
|
Total
|
2009
|
2010-2011
|
2012-2013
|
Thereafter
|
|||||||||||
|
Long-term
debt (1)
|
$
|
170,969
|
$
|
40,134
|
$
|
295
|
$
|
125,936
|
$
|
4,604
|
||||||
|
Interest
on long-term debt (2)
|
11,895
|
4,584
|
6,261
|
618
|
432
|
|||||||||||
|
Total
|
$
|
182,864
|
$
|
44,718
|
$
|
6,556
|
$
|
126,554
|
$
|
5,036
|
||||||
|
|
___________________
|
|
(1)
|
These
amounts represent the balances outstanding under the Partnership Credit
Facility, the Partnership’s Subordinated Credit Agreement and Abraxas’
mortgage on its headquarters building. These repayments assume that we
will not draw down additional funds
|
|
(2)
|
Interest
expense assumes the balances of long-term debt at the end of the period
and current effective interest
rates.
|
We
maintain a reserve for costs associated with the retirement of tangible
long-lived assets. At December 31, 2008, our reserve for these obligations
totaled $9.9 million for which no contractual commitment exist. For additional
information relating to this obligation, see Note 1 of Notes to Consolidated
Financial Statements.
Off-Balance Sheet
Arrangements. At December 31, 2008, we had no existing off-balance sheet
arrangements, as defined under SEC regulations, that have or are reasonably
likely to have a current or future effect on our financial condition, revenues
or expenses, results of operations, liquidity, capital expenditures or capital
resources that is material to investors.
Contingencies.
From time to time, we are involved in litigation relating to claims arising out
of our operations in the normal course of business. At December 31, 2008 we
were not engaged in any legal proceedings that are expected, individually or in
the aggregate, to have a material adverse effect on us.
Other
obligations. We make and will continue to make substantial capital
expenditures for the acquisition, exploration, development and production of oil
and gas. In the past, we have funded our operations and capital expenditures
primarily through cash flow from operations, sales of properties, sales of
production payments and borrowings under our bank credit facilities and other
sources. Given our high degree of operating control, the timing and incurrence
of operating and capital expenditures is largely within our discretion.
Long-Term
Indebtedness
Long-term
indebtedness consisted of the following:
|
December
31,
2008
|
December
31,
2007
|
||||||
|
(in
thousands)
|
|||||||
|
Partnership
credit facility
|
$
|
125,600
|
$
|
45,900
|
|||
|
Partnership
subordinated credit agreement
|
40,000
|
—
|
|||||
|
Real
estate lien note
|
5,369
|
—
|
|||||
|
170,969
|
45,900
|
||||||
|
Less
current maturities
|
(40,134
|
)
|
—
|
||||
|
$
|
130,835
|
$
|
45,900
|
||||
Abraxas Senior
Secured Credit Facility. On June 27, 2007, Abraxas entered into a new
senior secured revolving credit facility, which we refer to as the Credit
Facility. The Credit Facility has a maximum commitment of $50.0 million.
Availability under the Credit Facility is subject to a borrowing base. The
borrowing base under the Credit Facility, which is currently $6.5 million, is
determined semi-annually by
the
lenders based upon our reserve reports, one of which must be prepared by our
independent petroleum engineers and one of which may be prepared internally. The
amount of the borrowing base is calculated by the lenders based upon their
valuation of our proved reserves utilizing these reserve reports and their own
internal decisions. In addition, the lenders, in their sole
discretion, may make one additional borrowing base redetermination during any
six-month period between scheduled redeterminations and we may also request one
redetermination during any six-month period between scheduled
redeterminations. The lenders may also make a redetermination in
connection with any sales of producing properties with a market value of 5% or
more of our current borrowing base. Our borrowing base at December
31, 2008 of $6.5 million was determined based upon our reserves at June 30,
2008. Our borrowing base can never exceed the $50.0 million maximum
commitment amount. Outstanding amounts under the Credit Facility will
bear interest at (a) the greater of the reference rate announced from time to
time by Société Générale, and (b) the Federal Funds Rate plus 0.5% of 1%, plus
in each case, (c) 0.5% - 1.5% depending on utilization of the borrowing base,
or, if Abraxas elects, at the London Interbank Offered Rate plus 1.5% - 2.5%,
depending on the utilization of the borrowing base. Subject to earlier
termination rights and events of default, the Credit Facility’s stated maturity
date is June 27, 2011. Interest will be payable quarterly on
reference rate advances and not less than quarterly on Eurodollar
advances.
Abraxas
is permitted to terminate the Credit Facility, and may, from time to time,
permanently reduce the lenders' aggregate commitment under the Credit Facility
in compliance with certain notice and dollar increment
requirements.
Each of
Abraxas’ subsidiaries other than the Partnership, Abraxas General Partner, LLC
and Abraxas Energy Investments, LLC has guaranteed Abraxas’ obligations under
the Credit Facility on a senior secured basis. Obligations under the
Credit Facility are secured by a first priority perfected security interest,
subject to certain permitted encumbrances, in all of Abraxas’ and the subsidiary
guarantors’ material property and assets.
Under the
Credit Facility, Abraxas is subject to customary covenants, including certain
financial covenants and reporting requirements. The Credit Facility
requires Abraxas to maintain a minimum current ratio as of the last day of each
quarter of not less than 1.00 to 1.00 and an interest coverage ratio (generally
defined as the ratio of consolidated EBITDA to consolidated interest expense as
of the last day of such quarter) of not less than 2.50 to 1.00.
In
addition to the foregoing and other customary covenants, the Credit Facility
contains a number of covenants that, among other things, will restrict Abraxas’
ability to:
· incur
or guarantee additional indebtedness;
· transfer
or sell assets;
· create
liens on assets;
· engage
in transactions with affiliates other than on an “arms-length”
basis;
· make
any change in the principal nature of its business; and
· permit
a change of control.
The
Credit Facility also contains customary events of default, including nonpayment
of principal or interest, violations of covenants, cross default and cross
acceleration to certain other indebtedness, bankruptcy and material judgments
and liabilities.
Amended and
Restated Partnership Credit Facility. On May 25, 2007, the Partnership
entered into a senior secured revolving credit facility which was amended and
restated on January 31, 2008 and further amended on January 16, 2009, which we
refer to as the Partnership Credit Facility. The Partnership Credit Facility has
a maximum commitment of $300.0 million. Availability under the
Partnership Credit Facility is subject to a borrowing base. The
borrowing base under the Partnership Credit Facility, which is currently $140.0
million, is determined semi-annually by the lenders based upon the Partnership’s
reserve reports, one of which must be prepared by the Partnership’s independent
petroleum engineers and one of which may be prepared internally. The amount of
the borrowing base is calculated by the lenders based upon their valuation of
the Partnership’s proved reserves utilizing these reserve reports and their own
internal decisions. In addition, the lenders, in their sole
discretion, may make one additional borrowing base
redetermination
during any six-month period between scheduled redeterminations. The
lenders may also make a redetermination in connection with any sales of
producing properties with a market value of 5% or more of the Partnership’s
current borrowing base. The Partnership’s current borrowing base of
$140.0 million was determined based upon its reserves at June 30,
2008. The borrowing base can never exceed the $300.0 million maximum
commitment amount. During the period beginning on January 16, 2009
and ending on the date that the Subordinated Credit Agreement is terminated,
outstanding amounts under the Partnership Credit Facility bear interest at (a)
the greater of (1) the reference rate announced from time to time by Société
Générale, (2) the Federal Funds Rate plus 0.5%, and (3) a rate determined by
Société Générale as the daily one-month LIBOR rate plus, in each case, (b) 1.5%
- 2.5%, depending on the utilization of the borrowing base, or, if the
Partnership elects, at the London Interbank Offered Rate plus 2.5% - 3.5%
depending on the utilization of the borrowing base. After the
termination of the Subordinated Credit Agreement, outstanding amounts under the
Partnership Credit Facility will bear interest at (a) the greater of (1) the
reference rate announced from time to time by Société Générale, (2) the Federal
Funds Rate plus 0.5%, and (3) a rate determined by Société Générale as the daily
one-month LIBOR rate plus, in each case, (b) 1.0% - 2.0%, depending on the
utilization of the borrowing base, or, if the Partnership elects, at the London
Interbank Offered Rate plus 2.0% - 3.0% depending on the utilization of the
borrowing base. At January 16, 2009, the interest rate on the
Partnership Credit Facility was 3.8%. Subject to earlier termination
rights and events of default, the Partnership Credit Facility’s stated maturity
date is January 31, 2013. Interest is payable quarterly on reference
rate advances and not less than quarterly on Eurodollar advances. The
Partnership is permitted to terminate the Partnership Credit Facility, and under
certain circumstances, may be required, from time to time, to permanently reduce
the lenders’ aggregate commitment under the Partnership Credit
Facility.
Each of
the general partner of the Partnership, Abraxas General Partner, LLC, which is a
wholly-owned subsidiary of Abraxas and which we refer to as the GP, and Abraxas
Operating, LLC, which is a wholly-owned subsidiary of the Partnership and which
we refer to as the Operating Company, has guaranteed the Partnership’s
obligations under the Partnership Credit Facility on a senior secured
basis. Obligations under the Partnership Credit Facility are secured
by a first priority perfected security interest, subject to certain permitted
encumbrances, in all of the property and assets of the GP, the Partnership and
the Operating Company, other than the GP’s general partner units in the
Partnership.
Under the
Partnership Credit Facility, the Partnership is subject to customary covenants,
including certain financial covenants and reporting requirements. The
Partnership Credit Facility requires the Partnership to maintain a minimum
current ratio as of the last day of each quarter of 1.00 to 1.00 and an interest
coverage ratio (defined as the ratio of consolidated EBITDA to consolidated
interest expense) as of the last day of each quarter of not less than 2.50 to
1.00. The Partnership Credit Facility required it to enter into derivative
contracts for specific volumes, which equated to approximately 85% of the
estimated oil and gas production from its net proved developed producing
reserves through December 31, 2011. The Partnership entered into
NYMEX-based fixed price commodity swaps on approximately 85% of its estimated
oil and gas production from its estimated net proved developed producing
reserves through December 31, 2011.
Under the
terms of the Partnership Credit Facility, the Partnership may make cash
distributions if, after giving effect to such distributions, the Partnership is
not in default under the Partnership Credit Facility, there is no borrowing base
deficiency and provided that (a) no such distribution shall be made
using the proceeds of any advance unless the unused portion of the amount then
available under the Partnership Credit Facility is greater than or equal to 10%
of the lesser of the Partnership’s borrowing base (which at January 16, 2009 was
$140.0 million) or the total commitment amount of the
Partnership Credit Facility (which at January 16, 2009 was currently
$300.0 million) at such time, (b) with respect to the cash distribution
scheduled to be made on or about May 15, 2009 attributable to the first quarter
of 2009, no such distribution shall be made unless (i) the sum of
unrestricted cash and the unused portion of the amount then available under the
Partnership Credit Facility after giving effect to such distribution exceeds
$20.0 million, or (ii) the Subordinated Credit Agreement shall have
terminated and (c) no cash distribution shall exceed $0.44 per unit per quarter
while the Subordinated Credit Agreement is outstanding. Additionally,
while the Subordinated Credit Agreement is outstanding, the Partnership’s
capital expenditures are limited to $12.5 million.
In
addition to the foregoing and other customary covenants, the Partnership Credit
Facility contains a number of covenants that, among other things, will restrict
the Partnership’s ability to:
· incur
or guarantee additional indebtedness;
· transfer
or sell assets;
· create
liens on assets;
· engage
in transactions with affiliates;
· make
any change in the principal nature of its business; and
· permit
a change of control.
The Partnership Credit Facility
also contains customary events of default, including nonpayment of principal or
interest, violations of covenants, cross default and cross acceleration to
certain other indebtedness including the Subordinated Credit Agreement described
below, bankruptcy and material judgments and liabilities.
Subordinated
Credit Agreement
On
January 31, 2008, the Partnership entered into a subordinated credit agreement
which was amended on January 16, 2009, which we refer to as the Subordinated
Credit Agreement. The Subordinated Credit Agreement has a maximum commitment of
$40.0 million. Outstanding amounts under the Subordinated Credit Agreement bear
interest at (a) the greater of (1) the reference rate announced from time to
time by Société Générale, (2) the Federal Funds Rate plus 0.5% and (3) a
rate determined by Société Générale as the daily one-month LIBOR Offered Rate,
plus in each case (b) 7.50% or, if the Partnership elects, at the greater of
(a) 2.0% and (b) at the London Interbank Offered Rate, in each case,
plus 8.50%. At January 16, 2009 the interest rate on the Subordinated Credit
Agreement was 10.5%. Principal payments under the Subordinated Credit
Agreement must be made on May 14, 2009 in an amount, which we refer to as the
May 14, 2009 Payment Amount, equal to the lesser of the amount of cash
distributed to Abraxas Energy Investments, LLC, a wholly-owned subsidiary of
Abraxas Petroleum, on or about February 14, 2009 and $2.25 million with the
balance due on the maturity date. The maturity date may be
accelerated if any limited partner of the Partnership, other than Perlman Value
Partners, exercises its right to convert its limited partner units into shares
of common stock of Abraxas Petroleum pursuant to the terms of the Exchange and
Registration Rights Agreement dated May 25, 2007, as amended, among Abraxas
Petroleum, the Partnership and the purchasers named therein. As a
result of the amendment to the Subordinated Credit Agreement, the date on which
the purchasers, if the Partnership’s initial public offering has not been
consummated prior to that date, may first exchange their Partnership units for
Abraxas Petroleum common stock is April 30, 2009. Subject to earlier
termination rights and events of default, the Subordinated Credit Agreement’s
stated maturity date is July 1, 2009. Interest is payable quarterly
on reference rate advances and not less than quarterly on Eurodollar
advances. The Partnership is permitted to terminate the Subordinated
Credit Agreement, and under certain circumstances, may be required, from time to
time, to make prepayments under the Subordinated Credit Agreement.
Each of
the GP and the Operating Company has guaranteed the Partnership’s obligations
under the Subordinated Credit Agreement on a subordinated secured
basis. Obligations under the Subordinated Credit Agreement are
secured by subordinated security interests, subject to certain permitted
encumbrances, in all of the property and assets of the Partnership, GP, and the
Operating Company, other than the GP’s general partner units in the
Partnership.
Under the
Subordinated Credit Agreement, the Partnership is subject to customary
covenants, including certain financial covenants and reporting requirements. The
Subordinated Credit Agreement requires the Partnership to maintain a minimum
current ratio as of the last day of each quarter of 1.00 to 1.00 and an interest
coverage ratio (defined as the ratio of consolidated EBITDA to consolidated
interest expense) as of the last day of each quarter of not less than 2.50 to
1.00. The Partnership Credit Facility required it to enter into derivative
contracts for specific volumes, which equated to approximately 85% of the
estimated oil and gas production from its net proved developed producing
reserves through December 31, 2011. The Partnership entered into
NYMEX-based fixed price commodity swaps on approximately 85% of its
estimated
oil and gas production from its estimated net proved developed producing
reserves through December 31, 2011.
In
addition to the foregoing and other customary covenants, the Subordinated Credit
Agreement contains a number of covenants that, among other things, will restrict
the Partnership’s ability to:
· incur
or guarantee additional indebtedness;
· transfer
or sell assets;
· create
liens on assets;
· engage
in transactions with affiliates;
· make
any change in the principal nature of its business; and
· permit
a change of control.
The
Subordinated Credit Agreement also contains customary events of default,
including nonpayment of principal or interest, violations of covenants, cross
default and cross acceleration to certain other indebtedness including the
Partnership Credit Facility, bankruptcy and material judgments and
liabilities. In addition, as a result of the amendment to the
Subordinated Credit Agreement, two events of default were added to the
Subordinated Credit Agreement. The first event of default would occur
if the Partnership fails to receive a letter of credit, which we refer to as the
APC L/C, in its favor from Abraxas Petroleum equal to the May 14, 2009 Payment
Amount, the Partnership fails to draw on the APC L/C on or before May 14, 2009
or the Partnership fails to use the proceeds of the APC L/C to make the
principal payment due on May 14, 2009. This event of default would
not occur in the event that the Partnership repays the principal amount due on
May 14, 2009 with funds received from Abraxas Petroleum. The
Partnership and Abraxas Petroleum have agreed that upon the occurrence of such a
payment or the Partnership’s drawing on the APC L/C that, in consideration
thereof, the Partnership would issue a number of additional units to Abraxas
Petroleum determined by dividing the May 14, 2009 Payment Amount by 110% of the
average trading yields of comparable E&P MLPs based on the closing market
price on May 14, 2009 multiplied by the most recent quarterly distribution paid
or declared by the Partnership times four. The other event of default
would occur if the Partnership fails to receive $20.0 million of proceeds from
an equity issuance on or before April 30, 2009.
Real
Estate Lien Note
On
May 9, 2008 the Company entered into an advancing line of credit in the amount
of $5.4 million for the purchase and finish out of a new building to serve as
its corporate headquarters. This note was refinanced in November
2008. The new note bears interest at a fixed rate of 6.375%, and is
payable in monthly installments of principal and interest of $39,754 based on a
twenty year amortization. The note matures in May 2015 at which time the
outstanding balance becomes due. The note is secured by a first lien deed of
trust on the property and improvements. As of December 31, 2008, $5.4 million
was outstanding on the note.
Hedging
Activities
Our
results of operations are significantly affected by fluctuations in commodity
prices and we seek to reduce our exposure to price volatility by hedging our
production through swaps, options and other commodity derivative instruments.
Under the terms of the Partnership Credit Facility, Abraxas Energy Partners was
required to enter into hedging arrangements for specified volumes, which equated
to approximately 85% of the estimated oil and gas production through December
31, 2011 from its net proved developed producing reserves.
In order
to mitigate its rate exposure, the Partnership entered into an interest rate
swap, effective August 12, 2008, to fix its floating LIBOR based debt. Our
2-year interest rates swap arrangement is for $100 million at a fixed rate
of 3.367%. The arrangement expires on August 12, 2010. The interest rate
swap was amended in February 2009 lowering the Partnership’s fixed rate from
3.367% to 2.95%.
See
“—Quantitative and Qualitative Disclosures about Market Risk—Hedging
Sensitivity” for further information.
Net
Operating Loss Carryforwards
At
December 31, 2008, we had, subject to the limitation discussed below, $194.4
million of net operating loss carryforwards for U.S. tax purposes. These loss
carryforwards will expire through 2028 if not utilized.
Uncertainties
exist as to the future utilization of the operating loss carryforwards under the
criteria set forth under FASB Statement No. 109. Therefore, we have established
a valuation allowance of $47.2 million and $60.8 million for deferred tax assets
at December 31, 2007 and 2008, respectively.
Related
Party Transactions
Abraxas
has adopted a policy that transactions between Abraxas and its officers,
directors, principal stockholders, or affiliates of any of them, will be on
terms no less favorable to Abraxas than can be obtained on an arm’s length basis
in transactions with third parties and must be approved by the vote of at least
a majority of the disinterested directors.
Abraxas
performs general and administrative services for the Partnership, such as
accounting, finance, land and engineering. The Partnership currently pays us
$2.6 million per year, which included an adjustment of $1.1 million
annually as a result of the St. Mary Acquisition, for performing these
general and administrative services. The amount of reimbursement is subject to
annual adjustments for inflation and acquisition or other expansion
adjustments.
Pursuant
to our operating agreements, the Partnership is required to reimburse us for all
direct and indirect expenses associated with operating our wells. Operating
expenses are the costs incurred in the operation of producing properties.
Expenses for utilities, direct labor, water injection and disposal, production
taxes and materials and supplies comprise the most significant portion of our
operating expenses. Operating expenses do not include general and administrative
expenses.
Critical
Accounting Policies
The
preparation of financial statements in conformity with generally accepted
accounting principles requires that management apply accounting policies and
make estimates and assumptions that affect results of operations and the
reported amounts of assets and liabilities in the financial statements. The
following represents those policies that management believes are particularly
important to the financial statements and that require the use of estimates and
assumptions to describe matters that are inherently uncertain.
Full Cost Method
of Accounting for Oil and Gas Activities. SEC Regulation S-X defines
the financial accounting and reporting standards for companies engaged in oil
and gas activities. Two methods are prescribed: the successful efforts method
and the full cost method. We have chosen to follow the full cost method under
which all costs associated with property acquisition, exploration and
development are capitalized. We also capitalize internal costs that can be
directly identified with our acquisition, exploration and development activities
and do not include any costs related to production, general corporate overhead
or similar activities. Under the successful efforts method, geological and
geophysical costs and costs of carrying and retaining undeveloped properties are
charged to expense as incurred. Costs of drilling exploratory wells that do not
result in proved reserves are charged to expense. Depreciation, depletion,
amortization and impairment of oil and gas properties are generally calculated
on a well by well or lease or field basis versus the “full cost” pool basis.
Additionally, gain or loss is generally recognized on all sales of oil and gas
properties under the successful efforts method. As a result our financial
statements will differ from companies that apply the successful efforts method
since we will generally reflect a higher level of capitalized costs as well as a
higher depreciation, depletion and amortization rate on our oil and gas
properties.
At the
time it was adopted, management believed that the full cost method would be
preferable, as earnings tend to be less volatile than under the successful
efforts method. However, the full cost method makes us susceptible to
significant non-cash charges during times of volatile commodity prices because
the full cost pool may be impaired when prices are low. These charges are not
recoverable when prices return to higher levels. We have experienced this
situation several times over the years, most recently in 2002 and the current
year. Our oil and gas reserves have a relatively long life. However, temporary
drops in commodity prices can have a material impact on our business including
impact from impairment testing procedures associated with the full cost method
of accounting as discussed below.
Under
full cost accounting rules, the net capitalized cost of oil and gas properties
may not exceed a “ceiling limit” which is based upon the present value of
estimated future net cash flows from proved reserves on a pool by pool basis,
discounted at 10%, plus the lower of cost or fair market value of unproved
properties and the cost of properties not being amortized, less income taxes. If
net capitalized costs of oil and gas properties exceed the ceiling limit, we
must charge the amount of the excess to earnings. This is called a “ceiling
limitation write-down.” This charge does not impact cash flow from
operating activities, but does reduce our stockholders’ equity and reported
earnings. The risk that we will be required to write down the carrying value of
oil and gas properties increases when oil and gas prices are depressed. In
addition, write-downs may occur if we experience substantial downward
adjustments to our estimated proved reserves or if purchasers cancel long-term
contracts for our gas production. An expense recorded in one period may not be
reversed in a subsequent period even though higher oil and gas prices may have
increased the ceiling applicable to the subsequent period. We apply the full
cost ceiling test on a quarterly basis on the date of the latest balance sheet
presented.
Estimates of
Proved Oil and Gas Reserves. Estimates of our proved reserves included in
this report are prepared in accordance with U.S. generally accepted accounting
principles (“GAAP”) and SEC guidelines. The accuracy of a reserve estimate is a
function of:
· the
quality and quantity of available data;
· the
interpretation of that data;
· the
accuracy of various mandated economic assumptions;
· and
the judgment of the persons preparing the estimate.
Our
proved reserve information included in this report were predominately based on
evaluations prepared by independent petroleum engineers. Estimates prepared by
other third parties may be higher or lower than those included herein. Because
these estimates depend on many assumptions, all of which may substantially
differ from future actual results, reserve estimates will be different from the
quantities of oil and gas that are ultimately recovered. In addition, results of
drilling, testing and production after the date of an estimate may justify
material revisions to the estimate.
You
should not assume that the present value of future net cash flows is the current
market value of our estimated proved reserves. In accordance with SEC
requirements, we based the estimated discounted future net cash flows from
proved reserves on prices and costs on the date of the estimate. Actual future
prices and costs may be materially higher or lower than the prices and costs as
of the date of the estimate.
The
estimates of proved reserves materially impact DD&A expense. If the
estimates of proved reserves decline, the rate at which we record DD&A
expense will increase, reducing future net income. Such a decline may result
from lower market prices, which may make it uneconomic to drill for and produce
higher cost fields.
Asset Retirement
Obligations. The estimated costs of restoration and removal of facilities
are accrued. The fair value of a liability for an asset’s retirement obligation
is recorded in the period in which it is incurred and the corresponding cost
capitalized by increasing the carrying amount of the related long-lived asset.
The liability is accreted to its then present value each period, and the
capitalized cost is depreciated over the useful life of the related asset. For
all periods presented, we have included estimated future costs of abandonment
and dismantlement in our full cost amortization base and amortize these costs as
a component of our depletion expense.
Accounting for
Derivatives. We use commodity price derivative contracts to limit our
exposure to fluctuations in oil and gas prices and interest rate swaps to hedge
our interest rate risk. Fluctuations in the market value are recognized in
earnings in the current period. Statement of Financial Accounting Standards,
(“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging
Activities”, was effective for us on January 1, 2001. SFAS 133, as amended and
interpreted, establishes accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in other
contracts, and for hedging activities. We have elected out of hedge accounting
as prescribed by SFAS 133 – accordingly all of our derivative contracts are
required to be recorded at fair value on our balance sheet, while changes in the
fair value of our derivative contracts are recognized in earnings in the current
period. Due to the volatility of oil and gas prices and, to a lesser extent,
interest rates, our financial condition and results of operations can be
significantly impacted by changes in the market value of our derivative
instruments. As of December 31, 2007 and 2008, the net market value of our oil
and gas derivatives was a liability of $9.1 million and a net asset of $39.2
million, respectively. The market value of our interest rate derivative was a
liability of $3.0 million at December 31, 2008.
Share-Based
Payments. We
currently utilize a standard option pricing model (i.e., Black-Scholes) to
measure the fair value of stock options granted to employees and directors.
Additional information about management’s assumptions can be found in footnote 6
to the consolidated financial statements. Options granted to
employees and directors are valued at the date of grant and expense is
recognized over the options vesting period. For the years ended December 31,
2006, 2007 and 2008, stock based compensation was approximately $998,000;
$996,000 and $1.4 million respectively.
Recent
Accounting Pronouncements
Fair
Value Measurements (SFAS No. 157) — In
September 2006, the Financial Accounting Standards Board (“FASB”) issued
Statement of Financial Accounting Standards (“SFAS”) No. 157, which
provides a single definition of fair value, together with a framework for
measuring it, and requires additional disclosure about the use of fair value to
measure assets and liabilities. SFAS No. 157 also emphasizes that fair
value is a market-based measurement, and sets out a fair value hierarchy with
the highest priority being quoted prices in active markets. Fair value
measurements are disclosed by level within that hierarchy. SFAS No. 157 is
effective for financial statements issued for fiscal years beginning after
November 15, 2007. The FASB agreed to defer the effective date of Statement
157 for one year for nonfinancial assets and nonfinancial liabilities that are
recognized or disclosed at fair value in the financial statements on a
nonrecurring basis. There is no deferral for financial assets and financial
liabilities. See Note 13 to the consolidated financial statements for more
information regarding this pronouncement.
The Fair
Value Option for Financial Assets and Financial Liabilities — Including an
Amendment of FASB Statement No. 115 (SFAS No. 159).-— In
February 2007, the FASB issued SFAS No. 159, which provides companies with
an option to measure, at specified election dates, many financial instruments
and certain other items at fair value that are not currently measured at fair
value. A company that adopts SFAS No. 159 will report unrealized gains and
losses on items, for which the fair value option has been elected, in earnings
at each subsequent reporting date. This statement also establishes presentation
and disclosure requirements designed to facilitate comparisons between entities
that choose different measurement attributes for similar types of assets and
liabilities. This statement is effective for fiscal years beginning after
November 15, 2007. We do not expect the implementation of SFAS No. 159
to have a material impact on our consolidated financial statements.
In
December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interest in
Consolidated Financial Statements, an amendment of Accounting Research Bulletin
(ARB) No. 51.” SFAS No. 160 clarifies that a noncontrolling interest
(previously commonly referred to as a minority interest) in a subsidiary is an
ownership interest in the consolidated entity and should be reported as equity
in the consolidated financial statements. The presentation of the consolidated
income statement has been changed by SFAS No. 160, and consolidated net
income attributable to both the parent and the noncontrolling interest is now
required to be reported separately. Previously, net income attributable to the
noncontrolling interest was typically reported as an expense or other deduction
in arriving at consolidated net income and was often combined with other
financial statement amounts. In addition, the ownership interests in
subsidiaries held by parties other than the parent must be clearly identified,
labeled, and presented in the equity in the consolidated financial statements
separately from the parent’s equity. Subsequent changes in a
parent’s
ownership
interest while the parent retains its controlling financial interest in its
subsidiary should be accounted for consistently, and when a subsidiary is
deconsolidated, any retained noncontrolling equity interest in the former
subsidiary must be initially measured at fair value. Expanded disclosures,
including a reconciliation of equity balances of the parent and noncontrolling
interest, are also required. SFAS No. 160 is effective for fiscal years,
and interim periods within those fiscal years, beginning on or after
December 15, 2008 and earlier adoption is prohibited. Prospective
application is required. Due to our investment in Abraxas Energy Partners, the
adoption of SFAS No. 160 could have a material impact on our financial
position and results of operations, however we do not believe that it will have
a material impact on our cash flows.
In
December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.”
SFAS No. 141(R) was issued in an effort to continue the movement toward the
greater use of fair values in financial reporting and increased transparency
through expanded disclosures. It changes how business acquisitions are accounted
for and will impact financial statements at the acquisition date and in
subsequent periods. Certain of these changes will introduce more volatility into
earnings. The acquirer must now record all assets and liabilities of the
acquired business at fair value, and related transaction and restructuring costs
will be expensed rather than the previous method of being capitalized as part of
the acquisition. SFAS No. 141(R) also impacts the annual goodwill
impairment test associated with acquisitions, including those that close before
the effective date of SFAS No. 141(R). The definitions of a “business” and
a “business combination” have been expanded, resulting in more transactions
qualifying as business combinations. SFAS No. 141(R) is effective for
fiscal years, and interim periods within those fiscal years, beginning on or
after December 31, 2008 and earlier adoption is prohibited. We cannot
predict the impact that the adoption of SFAS No. 141(R) will have on our
financial position, results of operations or cash flows with respect to any
acquisitions completed after December 31, 2008.
In March
2008, the FASB issued SFAS No. 161, “Disclosures about Derivative
Instruments and Hedging Activities,” which amends SFAS No. 133, “Accounting
for Derivative Instruments and Hedging Activities.” Enhanced disclosures to
improve financial reporting transparency are required and include disclosure
about the location and amounts of derivative instruments in the financial
statements, how derivative instruments are accounted for and how derivatives
affect an entity’s financial position, financial performance and cash flows. A
tabular format including the fair value of derivative instruments and their
gains and losses, disclosure about credit risk-related derivative features and
cross-referencing within the footnotes are also new requirements. SFAS
No. 161 is effective for financial statements issued for fiscal years and
interim periods beginning after November 15, 2008, with early application
and comparative disclosures encouraged, but not required. We have not yet
adopted SFAS No. 161. We do not believe that SFAS No. 161 will have a
material impact on our financial position, results of operations or cash
flows.
In May
2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted
Accounting Principles.” The statement is intended to improve financial reporting
by identifying a consistent hierarchy for selecting accounting principles to be
used in preparing financial statements that are prepared in conformance with
generally accepted accounting principles. Unlike Statement on Auditing Standards
(SAS) No. 69, “The Meaning of Present in Conformity With GAAP,” FAS No. 162 is
directed to the entity rather than the auditor. The statement is effective 60
days following the SEC’s approval of the Public Company Accounting Oversight
Board (PCAOB) amendments to AU Section 411, “The Meaning of Present Fairly in
Conformity with GAAP,” and is not expected to have any impact on the Company’s
results of operations, financial condition or liquidity.
On
December 29, 2008, the Securities and Exchange Commission adopted rule changes
to modernize its oil and gas reporting disclosures. The changes are
intended to provide investors with a more meaningful and comprehensive
understanding of oil and gas reserves.
The
updated disclosure requirements are designed to align with current practices and
changes in technology that have taken place in the oil and gas industry since
the adoption of the original reporting requirements more than 25 years
ago.
New
disclosure requirements include:
|
·
|
Permitting
the use of new technologies to determine proved reserves if those
technologies have been demonstrated empirically to lead to reliable
conclusions about reserve volumes.
|
|
·
|
Enabling
companies to additionally disclose their probable and possible reserves to
investors. Currently, the rules limit disclosure to only proved
reserves.
|
|
·
|
Allowing
previously excluded resources, such as oil sands, to be classified as oil
and gas reserves.
|
|
·
|
Requiring
companies to report on the independence and qualifications of a preparer
or auditor and requiring companies to file reports when a third party is
relied upon to prepare reserve estimates or conduct a reserves
audit.
|
|
·
|
Requiring
companies to report oil and gas reserves using an average price based upon
the prior 12-month period – rather than the year-end price – to maximize
the comparability of reserve estimates among companies and mitigate the
distortion of the estimates that arises when using a single pricing
date.
|
The new
requirements are effective for registration statements filed on or after January
1, 2010, and for annual reports on Forms 10-K and 20-F for fiscal years ending
on or after December 31, 2009.
Item 7A. Quantitative and Qualitative Disclosures about Market
Risk
Commodity
Price Risk
As an
independent oil and gas producer, our revenue, cash flow from operations, other
income and equity earnings and profitability, reserve values, access to capital
and future rate of growth are substantially dependent upon the prevailing prices
of oil, gas and natural gas liquids. Declines in commodity prices will adversely
affect our financial condition, liquidity, ability to obtain financing and
operating results. Lower commodity prices may reduce the amount of oil and gas
that we can produce economically. Prevailing prices for such commodities are
subject to wide fluctuation in response to relatively minor changes in supply
and demand and a variety of additional factors beyond our control, such as
global political and economic conditions. Historically, prices received for oil
and gas production have been volatile and unpredictable, and such volatility is
expected to continue. Most of our production is sold at market prices.
Generally, if the commodity indexes fall, the price that we receive for our
production will also decline. Therefore, the amount of revenue that we realize
is partially determined by factors beyond our control. Assuming the production
levels we attained during the year ended December 31, 2008, a 10% decline in oil
and gas, prices would have reduced our operating revenue and cash flow by
approximately $10.0 million for the year.
Hedging
Activity and Sensitivity
To
achieve more predictable cash flow, we reduce our exposure to fluctuations in
the prices of oil and gas. We have and may continue to enter into derivative
contracts, which we sometimes refer to as hedging arrangements, for a
significant portion of our oil and gas production. The Partnership Credit
Facility required the Partnership to enter into hedging arrangements on
specified volumes, which equated to approximately 85% of the estimated projected
oil and gas production from its estimated pro forma net proved developed
producing reserves through December 31, 2011. The Partnership has entered into
NYMEX-based fixed price commodity swaps on approximately 85% of its estimated
oil and gas production from its estimated net proved developed producing
reserves through December 31, 2011 at volume weighted average prices of $84.23
per barrel of oil and $8.27 per MMbtu of gas.
We
adopted SFAS 133 as amended by SFAS 137 and SFAS 138. Under SFAS 133, all
derivative instruments are recorded on the balance sheet at fair value. We
record our derivative instruments using the same method, accordingly the
instruments are recorded on the balance sheet at fair value with changes in the
market value of the derivatives being recorded in current income.
At
December 31, 2008, the Partnership had the following derivative contracts in
place:
|
Period
Covered
|
Product
|
Volume
(Production
per day)
|
Fixed
Price
|
|
Year
2009
|
Gas
|
10,595
Mmbtu
|
$8.45
|
|
Year
2009
|
Oil
|
1,000
Bbl
|
$83.80
|
|
Year
2010
|
Gas
|
9,130
Mmbtu
|
$8.22
|
|
Year
2010
|
Oil
|
895
Bbl
|
$83.26
|
|
Year
2011
|
Gas
|
8,010
Mmbtu
|
$8.10
|
|
Year
2011
|
Oil
|
810
Bbl
|
$86.45
|
We expect
to sustain realized and unrealized gains and losses as a result of these
derivative contracts. For the year ended December 31, 2007, we recognized a
realized gain of $1.9 million and an unrealized loss of $6.3 million, and for
the year ended December 31, 2008, we recognized a realized loss of $9.3 million
and an unrealized gain of $40.5 million on our derivative contracts. The
realized losses for the year ended December 31, 2008 were the result of the
contract prices for oil being significantly less than current market prices. The
unrealized gains were the result of the drastic drop in commodity prices during
the second half of 2008 resulting in the contract prices for oil and gas being
greater that the market price. On December 31, 2008, NYMEX futures prices were
$44.60 per barrel of oil and $5.62 per Mmbtu of gas. We expect to continue to
sustain realized and unrealized gains on our derivative contracts if market
prices continue to be less than our contract prices.
Interest
rate risk
The
Partnership is subject to interest rate risk associated with borrowings under
the Partnership Credit Facility and the Subordinated Credit
Agreement. At December 31, 2008, the Partnership had $125.6 million
in outstanding indebtedness under the Partnership Credit Facility. Outstanding
amounts under the Partnership Credit Facility bear interest at (a) the greater
of (1) the reference rate announced from time to time by Société Générale, (2)
the Federal Funds Rate plus 0.5%, and (3) a rate determined by Société Générale
as the daily one-month LIBOR rate plus, in each case, (b) 1.5% - 2.5%, depending
on the utilization of the borrowing base, or, if the Partnership elects, at the
London Interbank Offered Rate plus 2.5% - 3.5% depending on the utilization of
the borrowing base.
At December 31, 2008, the interest rate on the facility was 3.2%. For every
percentage point that the LIBOR rate rises, our interest expense would increase
by approximately $1.3 million on an annual basis. In addition the Partnership
had $40.0 million in outstanding indebtedness under the Subordinated Credit
Agreement. Outstanding amounts under the Subordinated Credit Agreement bear
interest at (a) the greater of (1) the reference rate announced from time to
time by Société Générale, (2) the Federal Funds Rate plus 0.5% and (3) a
rate determined by Société Générale as the daily one-month LIBOR Offered Rate,
plus in each case (b) 7.50% or, if the Partnership elects, at the greater of
(a) 2.0% and (b) at the London Interbank Offered Rate, in each case,
plus 8.50%. At December 31, 2008 the interest rate on the facility was 7.7%. For
every percentage point that the rate rises, our interest expense would increase
by approximately $400,000 on an annual basis. In order to mitigate our interest
rate exposure, we entered into an interest rate swap, effective August 12,
2008, to fix our floating LIBOR based debt. The arrangement expires on
August 12, 2010. The interest rate swap was amended in February 2009
lowering the Partnership’s fixed rate from 3.367% to 2.95%.
|
|
Item 8. Financial Statements and Supplementary
Data
|
For the
financial statements and supplementary data required by this Item 8, see the
Index to Consolidated Financial Statements.
|
|
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial
Disclosure
|
None
Item 9A.
Controls and Procedures
Conclusion Regarding the
Effectiveness of Disclosure Controls and Procedures
Under the
supervision and with the participation of our management, including our Chief
Executive Officer (our principal executive officer) and our Chief Financial
Officer (our principal financial officer), we evaluated the effectiveness of our
disclosure controls and procedures (as defined under Rule 13a-15(e)
and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the
“Exchange Act”)). Based on this evaluation, our Chief Executive Officer and our
Chief Financial Officer believe that the disclosure controls and procedures as
of December 31, 2008 were effective to ensure that information we are
required to disclose in the reports that we file or submit under the Exchange
Act is recorded, processed, summarized and reported within the time periods
specified in the SEC’s rules and forms and are effective to ensure that
information required to be disclosed by us is accumulated and communicated to
our management, including our Chief Executive Officer and Chief Financial
Officer, as appropriate, to allow timely decisions regarding required
disclosure.
Management’s Annual Report on
Internal Control Over Financial
Reporting
Our
management is responsible for establishing and maintaining adequate internal
control over financial reporting. Internal control over financial reporting is a
process designed by, or under the supervision of, the Company’s principal
executive and principal financial officers and implemented by the Company’s
Board of Directors, management and other personnel, to provide reasonable
assurance regarding the reliability of financial reporting and the preparation
of financial statements for external purposes in accordance with generally
accepted accounting principles and 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.
Under the
supervision and with the participation of our management, including our
principal executive officer and principal financial officer, 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. Based on our evaluation, our management concluded 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 BDO Seidman LLP, an independent
registered public accounting firm, as stated in their report which is included
herein.
Changes in Internal
Controls
There
were no changes in our internal control over financial reporting during the
quarter ended December 31, 2008 that materially affected, or are reasonably
likely to materially affect, our internal control over financial
reporting.
Item 9B. Other
Information
None.
Item
10. Directors,
Executive Officers and Corporate Governance
There is
incorporated in this Item 10 by reference that portion of our definitive proxy
statement for the 2009 Annual Meeting of Stockholders which appears therein
under the caption “Election of Directors – Board of Directors and Executive
Officers,” “– Code of Ethics” and “– Committees of the Board of
Directors.”
Audit
Committee and Audit Committee Financial Expert
The Audit
Committee of our board of directors consists of C. Scott Bartlett, Jr., Franklin
A. Burke and Paul A. Powell. The board of directors has determined
that each of the members of the Audit Committee is independent as determined in
accordance with the listing standards of the NASDAQ Stock Market and Item 407(a)
of Regulation S-K. In addition, the board of directors has determined
that C. Scott Bartlett, Jr., as defined by SEC rules, is an audit committee
financial expert.
Section
16(a) Compliance
Section
16(a) of the Exchange Act requires Abraxas directors and executive officers and
persons who own more than 10% of a registered class of Abraxas equity securities
to file with the Securities and Exchange Commission and the
NASDAQ initial reports of ownership and reports of changes in
ownership of Abraxas common stock. Officers, directors and greater
than 10% stockholders are required by SEC regulations to furnish us with copies
of all such forms they file. Based solely on a review of the copies
of such reports furnished to us and written representations that no other
reports were required. We believe that all our directors and
executive officers complied on a timely basis with all applicable filing
requirements under Section 16(a) of the Exchange Act during 2008.
Item
11. Executive
Compensation
There is
incorporated in this Item 11 by reference that portion of our definitive proxy
statement for the 2009 Annual Meeting of Stockholders which appears therein
under the captions “Election of Directors – Committees of the Board of
Directors” and “Executive Compensation”, except the material under the caption
“Compensation Committee Report on Executive Compensation.”
Item
12. Security
Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
There is
incorporated in this Item 12 by reference that portion of our definitive proxy
statement for the 2009 Annual Meeting of Stockholders which appears therein
under the caption “Securities Holdings of Principal Stockholders, Directors,
Nominees and Officers.”
Item
13. Certain
Relationships and Related Transactions, and Director
Independence
There is
incorporated in this Item 13 by reference that portion of our definitive proxy
statement for the 2009 Annual Meeting of Stockholders which appears therein
under the captions “Certain Transactions” and “Election of Directors – Board
Independence.”
Item
14. Principal Accountants Fees and Services
There is
incorporated in this Item 14 by reference that portion of our definitive proxy
statement for the 2009 Annual Meeting of Stockholders which appears therein
under the caption “Principal Auditor Fees and Services.”
PART
IV
|
|
Item
15. Exhibits, Financial Statement
Schedules
|
(a)1. Consolidated
Financial Statements
|
Page
|
|
|
Report
of Independent Registered Public Accounting Firm
on Consolidated Financial Statements
|
F-2
|
|
Report
of Independent Registered Public Accounting Firm on Internal Control over
Financial Reporting.
|
F-3
|
|
Consolidated
Balance Sheets at December 31, 2007 and 2008
|
F-4
|
|
Consolidated
Statements of Operations for the years ended December 31, 2006, 2007 and
2008
|
F-6
|
|
Consolidated
Statements of Stockholders’ Equity for the years
ended
December
31, 2006, 2007 and 2008
|
F-7
|
|
Consolidated
Statements of Cash Flows for the years ended December 31,
2006,
2007
and 2008
|
F-8
|
|
Consolidated
Statements of Other Comprehensive Income (loss) for the years
ended
December
31, 2006, 2007 and 2008
|
F-10
|
|
Notes
to Consolidated Financial Statements
|
F-11
|
|
(a)
2.
|
Financial Statement
Schedules
|
All
schedules have been omitted because they are not applicable, not required under
the instructions or the information requested is set forth in the consolidated
financial statements or related notes thereto.
(a)3. Exhibits
The
following Exhibits have previously been filed by the Registrant or are included
following the Index to Exhibits.
Exhibit
Number. Description
|
3.1
|
Articles
of Incorporation of Abraxas. (Filed as Exhibit 3.1 to our Registration
Statement on Form S-4, No. 33-36565 (the “S-4 Registration
Statement”)).
|
|
3.2
|
Articles
of Amendment to the Articles of Incorporation of Abraxas dated October 22,
1990. (Filed as Exhibit 3.3 to the S-4 Registration
Statement).
|
|
3.3
|
Articles
of Amendment to the Articles of Incorporation of Abraxas dated December
18, 1990. (Filed as Exhibit 3.4 to the S-4 Registration
Statement).
|
|
3.4
|
Articles
of Amendment to the Articles of Incorporation of Abraxas dated June 8,
1995. (Filed as Exhibit 3.4 to our Registration Statement on Form S-3, No.
333-00398 (the “S-3 Registration
Statement”)).
|
|
3.5
|
Articles
of Amendment to the Articles of Incorporation of Abraxas dated as of
August 12, 2000. (Filed as Exhibit 3.5 to our Annual Report on Form 10-K
(Filed April 2, 2001).
|
|
3.6
|
Amended
and Restated Bylaws of Abraxas. (Filed as Exhibit 3.1 to Abraxas’ Current
Report on Form 8-K. on November 17,
2008).
|
|
4.1
|
Specimen
Common Stock Certificate of Abraxas. (Filed as Exhibit 4.1 to the S-4
Registration Statement).
|
|
4.2
|
Specimen
Preferred Stock Certificate of Abraxas. (Filed as Exhibit 4.2 to our
Annual Report on Form 10-K filed on March 31,
1995).
|
|
*10.1
|
Abraxas
Petroleum Corporation 401(k) Profit Sharing Plan. (Filed as Exhibit 10.4
to Abraxas’ Registration Statement on
|
Form
S-4, No. 333-18673, (the “1996 Exchange Offer Registration
Statement”)).
|
|
*10.2
|
Abraxas
Petroleum Corporation Amended and Restated 1994 Long Term Incentive Plan.
(Filed as Exhibit 10.4 to Abraxas’ Registration Statement on Form S-4
filed on January 12, 2005).
|
|
*10.3
|
Form
of Indemnity Agreement between Abraxas and each of its directors and
officers. (Filed as Exhibit 10.4 to our Annual Report on Form 10-K filed
March 14, 2007).
|
|
*10.4
|
Employment
Agreement between Abraxas and Robert L. G. Watson. (Filed as Exhibit 10.19
to the Registration Statement on Form S-1, No. 333-95281 (the “2000 S-1
Registration Statement”)).
|
|
*10.5
|
Employment
Agreement between Abraxas and Chris E. Williford. (Filed as Exhibit 10.20
to the 2000 S-1 Registration
Statement).
|
|
*10.6
|
Employment
Agreement between Abraxas and Stephen T. Wendel. (Filed as Exhibit 10.26
to the Registration Statement on Form S-3, No. 333-127480 (the “S-3
Registration Statement”)).
|
|
*10.7
|
Employment
Agreement between Abraxas and William H. Wallace. (Filed as Exhibit 10.27
to the S-3 Registration Statement).
|
|
*10.8
|
Employment
Agreement between Abraxas and Lee T. Billingsley. (Filed as Exhibit 10.28
to the S-3 Registration Statement).
|
|
*10.9
|
Abraxas
Petroleum Corporation 2005 Non-Employee Directors Long-Term Equity
Incentive Plan. (Filed as Exhibit 10.1 to Abraxas’ Current Report on Form
8-K filed June 6, 2005).
|
|
*10.10
|
Form
of Stock Option Agreement under the Abraxas Petroleum Corporation 2005
Non-Employee Directors Long-Term Equity Incentive Plan. (Filed as Exhibit
10.2 to Abraxas’ Current Report on Form 8-K filed June 6,
2005).
|
|
*10.11
|
Abraxas
Petroleum Corporation Senior Management Incentive Bonus Plan 2006. (Filed
as Exhibit 10.17 to Annual Report on Form 10-K filed March 23,
2006).
|
|
10.12
|
Abraxas
Petroleum Corporation 2005 Employee Long-Term Equity Incentive Plan.
(Filed as Exhibit 10.1 to Abraxas’ Current Report on Form 8-K filed on May
26, 2006).
|
|
10.13
|
Form
of Employee Stock Option Agreement under the Abraxas 2005 Employee
Long-Term Equity Incentive Plan. (Previously filed as
Exhibit 10.2 to Abraxas’ Current Report on Form 8-K filed August 26,
2006).
|
|
10.14
|
Purchase
Agreement dated as of May 25, 2007, by and among Abraxas Petroleum
Corporation, Abraxas Energy Partners, L.P., Abraxas General Partner, LLC,
Abraxas Operating, LLC and the purchasers named therein. (Filed as Exhibit
10. 2 to Abraxas’ Current Report on Form 8-K filed May 31,
2007).
|
|
10.15
|
Registration
Rights Agreement dated as of May 25, 2007, by and among Abraxas Energy
Partners, L.P. and the purchasers named therein. (Filed as Exhibit 10. 3
to Abraxas’ Current Report on Form 8-K filed May 31,
2007).
|
|
10.16
|
Omnibus
Agreement dated as of May 25, 2007, by and among Abraxas Petroleum
Corporation, Abraxas Energy Partners, L.P., Abraxas General Partner, LLC
and Abraxas Operating, LLC. (Filed as Exhibit 10. 4 to Abraxas’ Current
Report on Form 8-K filed May 31,
2007).
|
|
10.17
|
Second
Amended and Restated Agreement of Limited Partnership of Abraxas Energy
Partners, L.P. (Filed as Exhibit 10.17 to Abraxas Annual Report
on Form 10-K filed on March 17,
2008)
|
|
10.18
|
Securities
Purchase Agreement dated May 25, 2007 by and among Abraxas Petroleum
Corporation and the purchasers named therein. (Filed as Exhibit 10.7 to
Abraxas’ Current Report on Form 8-K filed May 31,
2007).
|
|
10.19
|
Form
of Common Stock Purchase Warrant. (Filed as Exhibit 10. 8 to Abraxas’
Current Report on Form 8-K filed May 31,
2007).
|
|
10.20
|
Exchange
and Registration Rights Agreement dated as of May 25, 2007 by and among
Abraxas Petroleum Corporation, Abraxas Energy Partners, L.P. and the
purchasers named therein. (Filed as Exhibit 10. 9 to Abraxas’ Current
Report on Form 8-K filed May 31,
2007).
|
|
10.21
|
Credit
Agreement dated June 27, 2007 among Abraxas Petroleum Corporation, the
lenders party thereto and Société Générale as Administrative Agent and
Issuing Lender. (Filed as Exhibit 10.1 to Abraxas Current Report on Form
8-K filed June 28, 2007).
|
|
10.22
|
Amended
and Restated Credit Agreement dated January 31, 2008 among Abraxas Energy
Partners, L.P., the lenders party thereto, Société Générale as
Administrative Agent and Issuing Lender, The Royal Bank of Canada, as
Syndication Agent, and The Royal Bank of Scotland PLC, as Documentation
Agent. (Filed as Exhibit 10.2 to Abraxas’ Current Report on Form 8-K filed
on February 6, 2008).
|
|
10.23
|
Subordinated
Credit Agreement dated January 31, 2008 among Abraxas Energy Partners,
L.P., the lenders party thereto, Société Générale, as Administrative
Agent, and The Royal Bank of Canada, as Syndication Agent. (Filed as
Exhibit 10.3 to Abraxas’ Current Report on Form 8-K filed on February 6,
2008).
|
|
10.24
|
Intercreditor
and Subordination Agreement dated January 31, 2008 among Abraxas Energy
Partners, L.P., the Senior Lenders party thereto, the Subordinated Lenders
party thereto and Société Générale, as Administrative Agent. (Filed as
Exhibit 10.4 to Abraxas’ Current Report on Form 8-K filed on February 6,
2008).
|
|
10.25
|
Form
of Indemnification Agreement by and among Abraxas Energy Partners, L.P.,
Abraxas General Partner, LLC, and each of its officers and directors.
(Filed as Exhibit 10.25 to Abraxas’ Annual Report on Form 10-K filed on
March 17, 2008).
|
|
10.26
|
Amendment
No. 2 to Registration Rights Agreement dated October 6, 2008, by and among
Abraxas Energy Partners, L.P. and the Purchasers. (Filed as
Exhibit 10.1 to Abraxas’ Current Report on Form 8-K filed on October 6,
2008).
|
|
10.27
|
Amendment
No. 1 to Exchange and Registration Rights Agreement dated October 6, 2008
by and among Abraxas Petroleum Corporation, Abraxas Energy Partners, L.P.
and the Purchasers. (Filed as Exhibit 10.2 to Abraxas’ Current
Report on Form 8-K filed on October 6,
2008)
|
|
10.28
|
Amendment
No. 1 to Amended and Restated Credit Agreement dated January 16, 2009, by
and among Abraxas Energy Partners, L.P., Société Générale, as
administrative agent and issuing lender, The Royal Bank of Canada, as
syndication agent, The Royal Bank of Scotland PLC, as documentation agent,
and the lenders signatory thereto. (Filed as Exhibit 10.1 to Abraxas’
Current Report on Form 8-K filed on January 20,
2009).
|
|
10.29
|
Amendment
No. 1 to Subordinated Credit Agreement dated January 16, 2009 by and among
Abraxas Energy Partners, L.P., Société Générale, as administrative agent,
The Royal Bank of Canada, as syndication agent, and the lenders signatory
thereto. (Filed as Exhibit 10.1 to Abraxas’ Current Report on Form 8-K
filed on January 20, 2009).
|
|
14.1
|
Abraxas
Petroleum Corporation Code of Business Conduct and Ethics. (Filed as
Exhibit 14.1 to Abraxas Annual Report on Form 10-K filed March 22,
2006).
|
|
18.1
|
Change
in Accounting Principles. (Filed as Exhibit 18.1 to Abraxas Annual Report
on Form 10-K/A Number 2 filed on August 20, 2008
)
|
|
21.1
|
Subsidiaries
of Abraxas. (Filed as Exhibit 21.1 to Abraxas Annual Report on Form 10-K
filed on March 17, 2008)
|
|
23.1
|
Consent
of BDO Seidman, LLP. (Filed
herewith).
|
|
23.2
|
Consent
of DeGoyler and MacNaughton. (Filed
herewith).
|
|
31.1
|
Certification
– Chief Executive Officer. (Filed
herewith).
|
|
31.2
|
Certification
– Chief Financial Officer. (Filed
herewith).
|
|
32.1
|
Certification
by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed
herewith).
|
|
32.2
|
Certification
by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed
herewith).
|
|
*
|
Management
Compensatory Plan or Agreement.
|
Exhibit
Index
|
23.1
|
Consent
of BDO Seidman, LLP. (Filed
herewith).
|
|
23.2
|
Consent
of DeGoyler & MacNaughton (Filed
herewith).
|
|
31.1
|
Certification
– Chief Executive Officer. (Filed
herewith).
|
31.2 Certification
– Chief Financial Officer. (Filed herewith).
|
32.1
|
Certification
by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed
herewith).
|
|
32.2
|
Certification
by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed
herewith).
|
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.
ABRAXAS PETROLEUM
CORPORATION
|
By:
|
/s/Robert
L.G. Watson
|
By:
|
/s/Chris
E. Williford
|
|
|
President
and Principal Executive Officer
|
Exec.
Vice President and Principal Financial and Accounting
Officer
|
|||
DATED: February 24, 2009
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 date indicated.
|
Signature
|
Name
and Title
|
Date
|
||
|
/s/
Robert L.G. Watson
Robert
L.G. Watson
|
Chairman
of the Board, President (Principal Executive Officer) and
Director
|
February
24, 2009
|
||
|
/s/ Chris E. Williford
Chris
E. Williford
|
Exec.
Vice President and Treasurer (Principal Financial and Accounting
Officer)
|
February
24, 2009
|
||
|
/s/ Craig S. Bartlett, Jr.
Craig
S. Bartlett, Jr.
|
Director
|
February
24, 2009
|
||
|
/s/ Franklin A. Burke
Franklin
A. Burke
|
Director
|
February
24, 2009
|
||
|
/s/ Harold D. Carter
Harold
D. Carter
|
Director
|
February
24, 2009
|
||
|
/s/ Ralph F. Cox
Ralph
F. Cox
|
Director
|
February
24, 2009
|
||
|
/s/ Dennis E. Logue
Dennis
E. Logue
|
Director
|
February
24, 2009
|
||
|
/s/ Paul A. Powell
Paul
A. Powell
|
Director
|
February
24,
2009
|
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
|
Page
|
|
|
Abraxas Petroleum Corporation and Subsidiaries
|
|
|
F-2
|
|
|
F-3
|
|
|
F-4
|
|
|
F-6
|
|
|
F-7
|
|
|
F-8
|
|
|
F-9
|
|
|
F-10
|
All
schedules are omitted because they are not required, are not applicable or the
information required is included in the Consolidated Financial Statements or the
notes thereto.
Report of Independent Registered Public Accounting
Firm
Board of
Directors and Stockholders
Abraxas
Petroleum Corporation
San
Antonio, Texas
We have
audited the accompanying consolidated balance sheets of Abraxas Petroleum
Corporation as of December 31, 2007 and 2008 and the related consolidated
statements of operations, stockholders’ equity, cash flows, and other
comprehensive income (loss) 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, assessing the accounting principles
used and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our
opinion, the consolidated financial statements referred to above present fairly,
in all material respects, the financial position of Abraxas Petroleum
Corporation at December 31, 2007 and 2008, and the results of its operations and
its cash flows for each of the three years in the period ended December 31,
2008, in conformity with
accounting principles generally accepted in the United States of
America.
We also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), Abraxas Petroleum Corporation's 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 (COSO) and our report dated February
24, 2009 expressed an unqualified opinion thereon.
/s/ BDO
Seidman, LLP
Dallas,
Texas
February
24, 2009
Report
of Independent Registered Public Accounting Firm on Internal
Control over Financial Reporting
Board of
Directors and Stockholders
Abraxas
Petroleum Corporation
San
Antonio, Texas
We have
audited Abraxas Petroleum Corporation’s 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). Abraxas Petroleum Corporation’s
management is responsible for maintaining effective internal control over
financial reporting and for its assessment of the effectiveness of internal
control over financial reporting, included in the accompanying Item 9A,
“Management’s Report on Internal Control Over Financial Reporting”. Our
responsibility is to express an opinion on the company’s internal control over
financial reporting based on our audit.
We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness exists, and
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, Abraxas Petroleum Corporation 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 of Abraxas
Petroleum Corporation as of December 31, 2007 and 2008, and the related
consolidated statements of operations, stockholders’ equity, cash flows, and
comprehensive income (loss) for each of the three years in the period ended
December 31, 2008 and our report dated February 24, 2009 expressed an
unqualified opinion thereon.
|
/s/
BDO Seidman, LLP
|
|
Dallas,
Texas
February
24, 2009
CONSOLIDATED
BALANCE SHEETS
ASSETS
|
December
31,
|
|||||||
|
2007
|
2008
|
||||||
|
(Dollars
in thousands)
|
|||||||
|
Current
assets:
|
|||||||
|
Cash
and cash equivalents
|
$
|
18,936
|
$
|
1,924
|
|||
|
Accounts
receivable:
|
|||||||
|
Joint
owners
|
840
|
1,740
|
|||||
|
Oil
and gas production sales
|
5,288
|
6,168
|
|||||
|
Other
|
—
|
58
|
|||||
|
6,128
|
7,966
|
||||||
|
Derivative asset
– Current
|
2,658
|
22,832
|
|||||
|
Other
current assets
|
377
|
572
|
|||||
|
Total
current assets
|
28,099
|
33,294
|
|||||
|
Property
and equipment:
|
|||||||
|
Oil
and gas properties, full cost method of accounting:
|
|||||||
|
Proved
|
265,090
|
440,712
|
|||||
|
Unproved
properties excluded from depletion
|
—
|
—
|
|||||
|
Other
property and equipment
|
3,633
|
10,986
|
|||||
|
Total
|
268,723
|
451,698
|
|||||
|
Less
accumulated depreciation, depletion, and amortization
|
151,696
|
291,390
|
|||||
|
Total
property and equipment - net
|
117,027
|
160,308
|
|||||
|
Deferred
financing fees, net
|
856
|
1,443
|
|||||
|
Derivative
asset – long-term
|
359
|
16,394
|
|||||
|
Other
assets including marketable securities
|
778
|
400
|
|||||
|
Total
assets
|
$
|
147,119
|
$
|
211,839
|
|||
|
|
See
accompanying notes to consolidated financial
statements
|
ABRAXAS
PETROLEUM CORPORATION
CONSOLIDATED
BALANCE SHEETS (CONTINUED)
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
December
31,
|
|||||||
|
2007
|
2008
|
||||||
|
(Dollars
in thousands)
|
|||||||
|
Current
liabilities:
|
|||||||
|
Accounts
payable
|
$
|
7,413
|
$
|
10,748
|
|||
|
Joint
interest oil and gas production payable
|
2,429
|
3,176
|
|||||
|
Accrued
interest
|
241
|
350
|
|||||
|
Other
accrued expenses
|
1,514
|
1,886
|
|||||
|
Derivative
liability – current
|
5,154
|
3,000
|
|||||
|
Current
maturities of long-term debt
|
—
|
40,134
|
|||||
|
Total
current liabilities
|
16,751
|
59,294
|
|||||
|
Long-term
debt – less current maturities
|
45,900
|
130,835
|
|||||
|
Derivative
liability – long-term
|
3,941
|
—
|
|||||
|
Future
site restoration
|
1,183
|
9,959
|
|||||
|
Total
liabilities
|
67,775
|
200,088
|
|||||
|
Minority
interest
|
23,497
|
7,093
|
|||||
|
Commitments
and contingencies
|
|||||||
|
Stockholders’
equity:
|
|||||||
|
Convertible
preferred stock, par value $.01, authorized 1,000,000 shares; -0- shares
issued and outstanding.
|
—
|
—
|
|||||
|
Common
stock, par value $.01 per share – authorized 200,000,000 shares; issued
49,020,949 and 49,622,423
|
490
|
496
|
|||||
|
Additional
paid-in capital
|
185,646
|
187,243
|
|||||
|
Accumulated
deficit
|
(130,791
|
)
|
(183,194
|
)
|
|||
|
Accumulated
other comprehensive income
|
502
|
113
|
|||||
|
Total
stockholders’ equity
|
55,847
|
4,658
|
|||||
|
Total
liabilities, minority interest and stockholders’ equity
|
$
|
147,119
|
$
|
211,839
|
|||
See
accompanying notes to consolidated financial statements
ABRAXAS
PETROLEUM CORPORATION
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
Years
Ended December 31,
|
||||||||||
|
2006
|
2007
|
2008
|
||||||||
|
(In
thousands except per share data)
|
||||||||||
|
Revenues:
|
||||||||||
|
Oil
and gas production revenues
|
$
|
49,448
|
$
|
46,906
|
$
|
99,084
|
||||
|
Rig
revenues
|
1,613
|
1,396
|
1,210
|
|||||||
|
Other
|
16
|
7
|
16
|
|||||||
|
51,077
|
48,309
|
100,310
|
||||||||
|
Operating
costs and expenses:
|
||||||||||
|
Lease
operating and production taxes
|
11,776
|
11,254
|
26,635
|
|||||||
|
Depreciation,
depletion, and amortization
|
14,939
|
14,292
|
23,343
|
|||||||
|
Impairment
|
—
|
—
|
116,366
|
|||||||
|
Rig
operations
|
819
|
801
|
856
|
|||||||
|
General
and administrative (including stock-based compensation of $998; $996; and
$1,404 respectively)
|
5,160
|
6,438
|
7,127
|
|||||||
|
32,694
|
32,785
|
174,327
|
||||||||
|
Operating
income (loss)
|
18,383
|
15,524
|
(74,017
|
)
|
||||||
|
Other
(income) expense:
|
||||||||||
|
Interest
income
|
(29
|
)
|
(408
|
)
|
(187
|
)
|
||||
|
Amortization
of deferred financing fees
|
1,591
|
671
|
1,028
|
|||||||
|
Interest
expense
|
16,767
|
8,392
|
10,496
|
|||||||
|
Financing
fees
|
—
|
—
|
359
|
|||||||
|
Loss
(gain) on derivative contracts (unrealized $(81); $6,288 and
$(37,860))
|
(646
|
)
|
4,363
|
(28,333
|
)
|
|||||
|
Loss
on debt extinguishment
|
—
|
6,455
|
—
|
|||||||
|
Gain
on sale of assets
|
—
|
(59,439
|
)
|
—
|
||||||
|
Other
|
347
|
8,523
|
||||||||
|
17,683
|
(39,619
|
)
|
(8,114
|
)
|
||||||
|
Income
(loss) from operations before income tax and minority
interest
|
700
|
55,143
|
(65,903
|
)
|
||||||
|
Income
tax
|
—
|
(283
|
)
|
—
|
||||||
|
Income
(loss) before minority interest
|
700
|
54,860
|
(65,903
|
)
|
||||||
|
Minority
interest in loss of partnership
|
—
|
1,842
|
13,500
|
|||||||
|
Net
income (loss)
|
$
|
700
|
$
|
56,702
|
$
|
(52,403
|
)
|
|||
|
Net
income (loss) per common share - basic
|
$
|
0.02
|
$
|
1.22
|
$
|
(1.07
|
)
|
|||
|
Net
income (loss) per common share - diluted
|
$
|
0.02
|
$
|
1.19
|
$
|
(1.07
|
)
|
|||
See
accompanying notes to consolidated financial statements
ABRAXAS
PETROLEUM CORPORATION
CONSOLIDATED
STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)
(In
thousands except number of shares)
|
Common
Stock
|
Treasury
Stock
|
||||||||||||||||||||||
|
Shares
|
Amount
|
Shares
|
Amount
|
Additional
Paid-
In
Capital
|
Accumulated
Deficit
|
Accumulated
Other
Comprehensive
Income(Loss)
|
Total
|
||||||||||||||||
|
Balance
at December 31, 2005
|
42,063,167
|
$
|
421
|
56,477
|
$
|
(408
|
)
|
$
|
162,795
|
$
|
(188,193
|
)
|
$
|
1,684
|
$
|
(23,701
|
)
|
||||||
|
Net
Income
|
—
|
—
|
—
|
—
|
—
|
700
|
—
|
700
|
|||||||||||||||
|
Change
in unrealized gain (loss) fair value of
investments
|
—
|
—
|
—
|
—
|
—
|
—
|
(709
|
)
|
(709
|
)
|
|||||||||||||
|
Stock-based
compensation
|
—
|
—
|
—
|
—
|
998
|
—
|
—
|
998
|
|||||||||||||||
|
Shares
issued for compensation
|
5,782
|
—
|
(20,925
|
)
|
123
|
14
|
—
|
—
|
137
|
||||||||||||||
|
Stock
options exercised
|
693,517
|
7
|
—
|
—
|
403
|
—
|
—
|
410
|
|||||||||||||||
|
Balance
at December 31, 2006
|
42,762,466
|
428
|
35,552
|
(285
|
)
|
164,210
|
(187,493
|
)
|
975
|
(22,165
|
)
|
||||||||||||
|
Net
Income
|
—
|
—
|
—
|
—
|
—
|
56,702
|
—
|
56,702
|
|||||||||||||||
|
Change
in unrealized gain (loss) fair value of
investments
|
—
|
—
|
—
|
—
|
—
|
—
|
(473
|
)
|
(473
|
)
|
|||||||||||||
|
Stock-based
compensation
|
—
|
—
|
—
|
—
|
996
|
—
|
—
|
996
|
|||||||||||||||
|
Shares
issued for compensation
|
22,960
|
—
|
(35,552
|
)
|
285
|
(94
|
)
|
—
|
—
|
191
|
|||||||||||||
|
Stock
options exercised
|
208,109
|
2
|
—
|
—
|
10
|
—
|
—
|
12
|
|||||||||||||||
|
Equity
issuance, net of offering costs
|
5,874,678
|
59
|
—
|
—
|
20,525
|
—
|
—
|
20,584
|
|||||||||||||||
|
Restricted
stock issue
|
152,736
|
1
|
—
|
—
|
(1
|
)
|
—
|
—
|
—
|
||||||||||||||
|
Balance
at December 31, 2007
|
49,020,949
|
490
|
—
|
—
|
185,646
|
(130,791
|
)
|
502
|
55,847
|
||||||||||||||
|
Net
Loss
|
(52,403
|
)
|
(52,403
|
)
|
|||||||||||||||||||
|
Change
in unrealized gain (loss) fair value of
investments
|
—
|
—
|
—
|
—
|
—
|
—
|
(389
|
)
|
(389
|
)
|
|||||||||||||
|
Stock-based
compensation
|
—
|
—
|
—
|
—
|
1,162
|
—
|
—
|
1,162
|
|||||||||||||||
|
Shares
issued for compensation
|
30,655
|
—
|
—
|
—
|
60
|
—
|
—
|
60
|
|||||||||||||||
|
Stock
options exercised
|
141,501
|
2
|
—
|
—
|
65
|
—
|
—
|
67
|
|||||||||||||||
|
Warrants
exercised
|
31,961
|
—
|
—
|
—
|
—
|
—
|
—
|
—
|
|||||||||||||||
|
Conversion
of units in Partnership
|
344,752
|
3
|
—
|
—
|
290
|
—
|
—
|
293
|
|||||||||||||||
|
Restricted
stock issued, net of cancellations
|
52,605
|
1
|
—
|
—
|
20
|
—
|
—
|
21
|
|||||||||||||||
|
Balance
at December 31, 2008
|
49,622,423
|
$
|
496
|
—
|
$
|
—
|
$
|
187,243
|
$
|
(183,194
|
)
|
$
|
113
|
$
|
4,658
|
||||||||
See
accompanying notes to consolidated financial statements.
ABRAXAS
PETROLEUM CORPORATION
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
Years
Ended December 31,
|
||||||||||
|
2006
|
2007
|
2008
|
||||||||
|
(In
thousands)
|
||||||||||
|
Operating
Activities
|
||||||||||
|
Net
income (loss)
|
$
|
700
|
$
|
56,702
|
$
|
(52,403
|
)
|
|||
|
Adjustments
to reconcile net income (loss) to net cash provided by operating
activities:
|
||||||||||
|
Minority
interest in partnership loss
|
—
|
(1,842
|
)
|
(13,500
|
)
|
|||||
|
(Gain)
loss on sale of partnership interest
|
—
|
(59,439
|
)
|
—
|
||||||
|
Change
in derivative fair value
|
(81
|
)
|
6,235
|
(42,304
|
)
|
|||||
|
Depreciation,
depletion, and
amortization
|
14,939
|
14,292
|
23,343
|
|||||||
|
Impairment
|
—
|
—
|
116,366
|
|||||||
|
Accretion
of future site restoration
|
133
|
127
|
570
|
|||||||
|
Amortization
of deferred financing fees
|
1,591
|
671
|
1,028
|
|||||||
|
Stock-based
compensation
|
998
|
996
|
1,404
|
|||||||
|
Other
non-cash transactions
|
92
|
191
|
7,446
|
|||||||
|
Changes
in operating assets and liabilities:
|
||||||||||
|
Accounts
receivable
|
2,357
|
112
|
(1,838
|
)
|
||||||
|
Other
assets and liabilities
|
(486
|
)
|
15
|
(206
|
)
|
|||||
|
Accounts
payable
|
(5,406
|
)
|
1,063
|
4,082
|
||||||
|
Accrued
expenses
|
724
|
(791
|
)
|
(601
|
)
|
|||||
|
Net
cash provided by operations
|
15,561
|
18,332
|
43,387
|
|||||||
|
Investing
Activities
|
||||||||||
|
Capital
expenditures, including purchases
and
development of properties
|
(26,346
|
)
|
(26,908
|
)
|
(174,586)
|
|||||
|
Proceeds
from the sale of oil and gas properties
|
12,244
|
—
|
642
|
|||||||
|
Net
cash used in investing activities
|
(14,102
|
)
|
(26,908
|
)
|
(173,944
|
)
|
||||
|
Financing
Activities
|
||||||||||
|
Proceeds
from issuance of common stock
|
455
|
22,441
|
88
|
|||||||
|
Proceeds
from issuance of partnership equity
|
—
|
100,000
|
—
|
|||||||
|
Cost
of common stock and partnership equity issuance
|
—
|
(9,098
|
)
|
—
|
||||||
|
Proceeds
from long-term borrowings
|
20,444
|
46,690
|
135,084
|
|||||||
|
Payments
on long-term borrowings
|
(22,357
|
)
|
(128,404
|
)
|
(10,015)
|
|||||
|
Partnership
distribution to minority interest
|
—
|
(3,163
|
)
|
(9,997
|
)
|
|||||
|
Deferred
financing fees
|
—
|
(997
|
)
|
(1,615
|
)
|
|||||
|
Net
cash provided by (used in) financing activities
|
(1,458
|
)
|
27,469
|
113,545
|
||||||
|
Increase
(decrease) in cash
|
1
|
18,893
|
(17,012
|
)
|
||||||
|
Cash
at beginning of year
|
42
|
43
|
18,936
|
|||||||
|
Cash
at end of year
|
$
|
43
|
$
|
18,936
|
$
|
1,924
|
||||
|
Supplemental
disclosures of cash flow information:
|
||||||||||
|
Interest
paid
|
$
|
12,583
|
$
|
9,494
|
$
|
9,817
|
||||
See
accompanying notes to consolidated financial statements.
ABRAXAS
PETROLEUM CORPORATION
CONSOLIDATED
STATEMENTS OF OTHER COMPREHENSIVE INCOME (LOSS)
|
Years
Ended December 31,
|
||||||||||
|
2006
|
2007
|
2008
|
||||||||
|
(In
thousands)
|
||||||||||
|
Net
income (loss)
|
$
|
700
|
$
|
56,702
|
$
|
(52,403
|
)
|
|||
|
Other Comprehensive income (loss):
|
||||||||||
|
Change in unrealized value of investments
|
(709
|
)
|
(473
|
)
|
(389
|
)
|
||||
|
Other comprehensive loss
|
(709
|
)
|
(473
|
)
|
(389
|
)
|
||||
|
Comprehensive income (loss)
|
$
|
(9
|
)
|
$
|
56,229
|
$
|
(52,792
|
)
|
||
See
accompanying notes to consolidated financial statements.
ABRAXAS
PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization
and Significant Accounting Policies
Nature
of Operations
Abraxas
Petroleum Corporation (“Abraxas” or “Abraxas Petroleum”) is an independent
energy company primarily engaged in the exploration of and the acquisition,
development, and production of oil and gas principally in Texas, the
Mid-Continent and the Rocky Mountains. The consolidated financial statements
include the accounts of the Company and its wholly owned subsidiaries and its
47.3% interest in Abraxas Energy Partners, L.P. (the “Partnership”). All
intercompany accounts and transactions have been eliminated in
consolidation.
The
terms “Abraxas” and “Abraxas Petroleum” refers only to Abraxas Petroleum
Corporation, the term “Partnership” refers only to Abraxas Energy Partners
L.P. and the terms “we,” “us,” “our,” or the “Company,” refer to
Abraxas Petroleum Corporation, together with its consolidated subsidiaries
including Abraxas Energy Partners, L.P., unless the context otherwise
requires.
The
consolidated financial statements include the accounts of the Company and its
wholly-owned subsidiaries and the operations of the Partnership which was formed
on May 25, 2007. The operations of Abraxas Petroleum and the
Partnership are consolidated for financial reporting purposes. The interest of
the 52.7% owners of the Partnership is presented as minority
interest. Abraxas owns the remaining 47.3% of the partnership
interests. The Company has determined that based on its control of the general
partner of the Partnership, this 47.3% owned entity should be consolidated for
financial reporting purposes. See Note 4 for condensed consolidating financial
statements.
Liquidity
The
current global recession has had a significant impact on our operations. As a
result of the global recession, commodity prices are depressed and may stay
depressed or reduce further, thereby causing a prolonged downturn, which could
reduce our future cash flows from operations. This could cause us to
alter our business plans, including reducing our exploration and development
plans. Additionally the Partnership’s Subordinated Credit Agreement matures on
July 1, 2009. The Partnership has intended to repay its indebtedness
under the Subordinated Credit Agreement with proceeds from its initial public
offering. However, the equity capital markets have been negatively
affected in recent months. As a result, we cannot assure you that the
Partnership will be successful in completing the IPO prior to the maturity of
the Subordinated Credit Agreement. Abraxas
Energy is currently in discussions with Société Générale to amend the existing
Senior Secured Credit Facility and/or the Subordinated Credit Agreement in the
event the IPO is not completed by April 30, 2009. The Partnership has
also entered into discussions with other lending institutions to re-finance the
$40 million currently outstanding on the Subordinated Credit
Agreement. While the Company believes that there are options to this
short term maturity requirement, there are no guarantees that any of these
options will be successfully implemented.
Use
of Estimates
The
preparation of consolidated financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at
the date of the consolidated financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results
could differ from those estimates. Management believes that it is
reasonably possible that estimates of future proved oil and gas revenues could
significantly change in the future.
Concentration
of Credit Risk
Financial
instruments, which potentially expose the Company to credit risk consist
principally of trade receivables and oil and gas price derivative
contracts. Accounts receivable are generally from companies with
significant oil and gas marketing activities. The Company performs
ongoing credit evaluations and, generally, requires no collateral from its
customers. The counterparty to the Partnership’s oil and gas price contracts is
the same financial institution from which the Partnership has outstanding debt,
accordingly the Company believes its exposure to credit risk to this
counterparty is currently mitigated in part by this, as well as the current
overall financial condition of the counterparty.
The
Company maintains its cash and cash equivalents in excess of Federally insured
limits in prominent financial institutions considered by the Company to be of
high credit quality.
Cash
and Equivalents
Cash and
cash equivalents include cash on hand, demand deposits and short-term
investments with original maturities of three months or less.
Accounts
Receivable
Accounts
receivable are reported net of an allowance for doubtful accounts of
approximately $10,000 and $33,000 at December 31, 2007 and 2008, respectively.
The allowance for doubtful accounts is determined based on the Company's
historical losses, as well as a review of certain accounts. Accounts are charged
off when collection efforts have failed and the account is deemed
uncollectible.
Oil
and Gas Properties
The
Company follows the full cost method of accounting for oil and gas
properties. Under this method, all direct costs and certain indirect
costs associated with acquisition of properties and successful as well as
unsuccessful exploration and development activities are capitalized.
Depreciation, depletion, and amortization of capitalized oil and gas properties
and estimated future development costs, excluding unproved properties, are based
on the unit-of-production method based on proved reserves. Net
capitalized costs of oil and gas properties, as adjusted for asset retirement
obligations, less related deferred taxes, are limited to the lower of
unamortized cost or the cost ceiling, defined as the sum of the present value of
estimated future net revenues from proved reserves based on unescalated prices
discounted at 10 percent, plus the cost of properties not being amortized, if
any, plus the lower of cost or estimated fair value of unproved properties
included in the costs being amortized, if any, less related income
taxes. The Company does not have any properties that are being
excluded from amortization. Costs in excess of the present value of estimated
future net revenues as discussed above are charged to proved property impairment
expense. No gain or loss is recognized upon sale or disposition of
oil and gas properties, except in unusual circumstances. We apply the full cost
ceiling test on a quarterly basis on the date of the latest balance sheet
presented. During the fourth quarter the Company incurred approved property
impairment due to the decrease in commodity prices during the period. For the
year ended December 31, 2008, the Company incurred an impairment of $116.4
million, based on year end prices of $44.60 per barrel of oil and $5.62 per Mcf
of gas.
Other
Property and Equipment
Other
property and equipment are recorded on the basis of
cost. Depreciation of other property and equipment is provided over
the estimated useful lives using the straight-line method. Major
renewals and betterments are recorded as additions to the property and equipment
accounts. Repairs that do not improve or extend the useful lives of
assets are expensed.
Estimates
of Proved Oil and Gas Reserves
Estimates
of our proved reserves included in this report are prepared in accordance with
U.S. generally accepted accounting principles (“GAAP”) and SEC guidelines. The
accuracy of a reserve estimate is a function of:
· the
quality and quantity of available data;
· the
interpretation of that data;
· the
accuracy of various mandated economic assumptions;
· and
the judgment of the persons preparing the estimate.
Our
proved reserve information included in this report was based on evaluations
prepared by independent petroleum engineers. Estimates prepared by other third
parties may be higher or lower than those included herein. Because these
estimates depend on many assumptions, all of which may substantially differ from
future actual results, reserve estimates will be different from the quantities
of oil and gas that are ultimately recovered. In addition, results of drilling,
testing and production after the date of an estimate may justify material
revisions to the estimate.
In
accordance with SEC requirements, we based the estimated discounted future net
cash flows from proved reserves on prices and costs on the date of the estimate.
Future prices and costs may be materially higher or lower than the prices and
costs as of the date of the estimate which would impact the estimated value of
our reserves.
The
estimates of proved reserves materially impact DD&A expense. If the
estimates of proved reserves decline, the rate at which we record DD&A
expense will increase, reducing future net income. Such a decline may result
from lower market prices, which may make it uneconomic to drill for and produce
higher cost fields.
Derivative
Instruments and Hedging Activities
The
Company enters into agreements to hedge the risk of future oil and gas price
fluctuations. Such agreements are primarily in the form of fixed
price swaps, which limit the impact of price fluctuations with respect to the
Company’s sale of oil and gas. The Company does not enter into speculative
hedges.
Statement
of Financial Accounting Standards, (“SFAS”) No. 133, “Accounting for Derivative
Instruments and Hedging Activities,” as amended and interpreted, establishes
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging
activities. The Company elected out of hedge accounting as
prescribed by SFAS 133. Accordingly, all derivatives are recorded on
the balance sheet at fair value with changes in fair value being recognized in
earnings.
Fair
Value of Financial Instruments
The
Company includes fair value information in the notes to consolidated financial
statements when the fair value of its financial instruments is materially
different from the carrying value. The Company assumes the carrying
value of those financial instruments that are classified as current approximates
fair value because of the short maturity of these instruments. For
noncurrent financial instruments, the Company uses quoted market prices or, to
the extent that there are no available quoted market prices, market prices for
similar instruments.
Share-Based
Payments
The
Company currently utilizes a standard option pricing model (i.e., Black-Scholes)
to measure the fair value of stock options granted to employees and
directors. Options granted to employees and directors are valued at
the date of grant and expense is recognized over the options vesting period. For
the years ended December 31, 2006, 2007 and 2008, stock based compensation was
approximately $998,000; $996,000 and $1.4 million respectively. For additional
information regarding share-based payments please see Note 6 “Stock-based
Compensation, Option Plans and Warrants.”
Restoration,
Removal and Environmental Liabilities
The
Company is subject to extensive Federal, state and local environmental laws and
regulations. These laws regulate the discharge of materials into the environment
and may require the Company to remove or mitigate the environmental effects of
the disposal or release of petroleum substances at various
sites. Environmental
expenditures
are expensed or capitalized depending on their future economic
benefit. Expenditures that relate to an existing condition caused by
past operations and that have no future economic benefit are
expensed.
Liabilities
for expenditures of a noncapital nature are recorded when environmental
assessments and/or remediation is probable, and the costs can be reasonably
estimated. Such liabilities are generally undiscounted unless the timing of cash
payments for the liability or component are fixed or reliably
determinable.
FASB
Statement of Financial Accounting Standards No. 143, “Accounting for Asset
Retirement Obligations” (SFAS 143) addresses accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. SFAS 143 requires that the fair value of a
liability for an asset's retirement obligation be recorded in the period in
which it is incurred and the corresponding cost capitalized by increasing the
carrying amount of the related long-lived asset. The liability is accreted to
its then present value each period, and the capitalized cost is depreciated over
the estimated useful life of the related asset. For all periods presented, we
have included estimated future costs of abandonment and dismantlement in our
full cost amortization base and amortize these costs as a component of our
depletion expense in the accompanying consolidated financial
statements.
The
following table summarizes the Company’s asset retirement obligation
transactions during the following years ended December 31:
|
2006
|
2007
|
2008
|
||||||||
|
(in
thousands)
|
||||||||||
|
Beginning
asset retirement obligation
|
$
|
883
|
$
|
1,019
|
$
|
1,183
|
||||
|
New
wells placed on production and other
|
29
|
43
|
9,046
|
|||||||
|
Deletions
related to property disposals
|
(26
|
)
|
(6
|
)
|
(840
|
)
|
||||
|
Accretion
expense
|
133
|
127
|
570
|
|||||||
|
Ending
asset retirement obligation
|
$
|
1,019
|
$
|
1,183
|
$
|
9,959
|
||||
Revenue
Recognition and Major Purchasers
The
Company recognizes oil and gas revenue from its interest in producing wells as
oil and gas is sold from those wells, net of royalties. The Company utilizes the
sales method to account for gas production volume imbalances. Under
this method, income is recorded based on the Company’s net revenue interest in
production taken for delivery. The Company had no material gas imbalances at
December 31, 2007 and 2008.
Rig
revenue is recognized as workover rig services are performed on our wells on
behalf of third party working interest owners.
During
2006, 2007 and 2008 two purchasers accounted for 25%and, 24%; 25% and
23%; and 14% and 15% of oil and gas revenues,
respectively.
Deferred
Financing Fees
Deferred
financing fees are being amortized on the effective yield basis over the term of
the related debt arrangements.
Income
Taxes
The
Company records deferred income taxes using the asset and liability
method. Deferred tax assets and liabilities are recognized for the
future tax consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and their
respective tax basis and operating loss and tax credit carryforwards. Deferred
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.
Other
Comprehensive Income
FASB
Statement of Financial Accounting Standards No. 130, “Reporting Comprehensive
Income” (SFAS 130) requires disclosure of comprehensive income, which includes
reported net income as adjusted for other comprehensive
income. Comprehensive income for the Company is the change in
the market value of marketable securities.
Accounting
for Uncertainty in Income Taxes
In June 2006 the Financial Accounting
Standards Board issued Interpretation No. 48, Accounting for Uncertainty in
Income Taxes – an Interpretation of FASB Statement No. 109 (FIN 48), FIN 48 is
intended to clarify the accounting for uncertainty in income taxes recognized in
a company’s financial statements and prescribes the recognition and measurement
of a tax position taken or expected to be taken in a tax return. FIN 48 also
provides guidance on de-recognition, classification, interest and penalties,
accounting in interim periods, disclosure and transition.
Under FIN 48, evaluation of a tax
position is a two-step process. The first step is to determine whether it is
more-likely- than- not that a tax position will be sustained upon examination,
including the resolution of any related appeals or litigation based on the
technical merits of that position. The second step is to measure a tax position
that meets the more-likely-than-not threshold to determine the amount of benefit
to be recognized in the financial statements. A tax position is measured at the
largest amount of benefit that is greater than 50% 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 period in which the threshold is met. Previously recognized tax
positions that no longer meet the more-likely-than-not criteria should be
de-recognized in the first subsequent reporting period in which the threshold is
no longer met.
The adoption of FIN 48 at January 1,
2008 did not have an impact on the Company’s financial position.
New
Accounting Pronouncements
Fair
Value Measurements (SFAS No. 157) — In
September 2006, the Financial Accounting Standards Board (“FASB”) issued
Statement of Financial Accounting Standards (“SFAS”) No. 157, which
provides a single definition of fair value, together with a framework for
measuring it, and requires additional disclosure about the use of fair value to
measure assets and liabilities. SFAS No. 157 also emphasizes that fair
value is a market-based measurement, and sets out a fair value hierarchy with
the highest priority being quoted prices in active markets. Fair value
measurements are disclosed by level within that hierarchy. SFAS No. 157 is
effective for financial statements issued for fiscal years beginning after
November 15, 2007. The FASB agreed to defer the effective date of Statement
157 for one year for nonfinancial assets and nonfinancial liabilities that are
recognized or disclosed at fair value in the financial statements on a
nonrecurring basis. There is no deferral for financial assets and financial
liabilities. See Note 15 for further details of the impact of this
statement on the consolidated financial statements.
In
December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.”
SFAS No. 141(R) was issued in an effort to continue the movement toward the
greater use of fair values in financial reporting and increased transparency
through expanded disclosures. It changes how business acquisitions are accounted
for and will impact financial statements at the acquisition date and in
subsequent periods. Certain of these changes will introduce more volatility into
earnings. The acquirer must now record all assets and liabilities of the
acquired business at fair value, and related transaction and restructuring costs
will be expensed rather than the previous method of being capitalized as part of
the acquisition. SFAS No. 141(R) also impacts the annual goodwill
impairment test associated with acquisitions, including those that close before
the effective date of SFAS No. 141(R). The definitions of a “business” and
a “business combination” have been expanded, resulting in more transactions
qualifying as business combinations. SFAS No. 141(R) is effective for
fiscal years, and interim periods within those fiscal years, beginning on or
after December 31, 2008 and earlier adoption is prohibited. We
cannot
predict
the impact that the adoption of SFAS No. 141(R) will have on our financial
position, results of operations or cash flows with respect to any acquisitions
completed after December 31, 2008.
In
December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interest in
Consolidated Financial Statements, an amendment of Accounting Research Bulletin
(ARB) No. 51.” SFAS No. 160 clarifies that a noncontrolling interest
(previously commonly referred to as a minority interest) in a subsidiary is an
ownership interest in the consolidated entity and should be reported as equity
in the consolidated financial statements. The presentation of the consolidated
income statement has been changed by SFAS No. 160, and consolidated net
income attributable to both the parent and the noncontrolling interest is now
required to be reported separately. Previously, net income attributable to the
noncontrolling interest was typically reported as an expense or other deduction
in arriving at consolidated net income and was often combined with other
financial statement amounts. In addition, the ownership interests in
subsidiaries held by parties other than the parent must be clearly identified,
labeled, and presented in the equity in the consolidated financial statements
separately from the parent’s equity. Subsequent changes in a parent’s ownership
interest while the parent retains its controlling financial interest in its
subsidiary should be accounted for consistently, and when a subsidiary is
deconsolidated, any retained noncontrolling equity interest in the former
subsidiary must be initially measured at fair value. Expanded disclosures,
including a reconciliation of equity balances of the parent and noncontrolling
interest, are also required. SFAS No. 160 is effective for fiscal years,
and interim periods within those fiscal years, beginning on or after
December 15, 2008 and earlier adoption is prohibited. Prospective
application is required. Due to our investment in Abraxas Energy Partners, the
adoption of SFAS No. 160 could have a material impact on our financial
position and results of operations, however we do not believe that it will have
a material impact on our cash flows. Under current accounting rules, when
cumulative losses applicable to the minority interest exceed the minority
interest equity capital in the entity, such excess and any further losses
applicable to the minority interest are charged to the earnings of the majority
interest. For the year ended December 31, 2008, Abraxas included a loss of $9.3
million relating to the Partnerships loss in excess of the minority interest
equity. Under SFAS No. 160 the loss in excess of capital would be a component of
consolidated equity and would not be included in the earnings of the majority
interest.
The Fair
Value Option for Financial Assets and Financial Liabilities — Including an
Amendment of FASB Statement No. 115 (SFAS No. 159) — In
February 2007, the FASB issued SFAS No. 159, which provides companies with
an option to measure, at specified election dates, many financial instruments
and certain other items at fair value that are not currently measured at fair
value. A company that adopts SFAS No. 159 will report unrealized gains and
losses on items, for which the fair value option has been elected, in earnings
at each subsequent reporting date. This statement also establishes presentation
and disclosure requirements designed to facilitate comparisons between entities
that choose different measurement attributes for similar types of assets and
liabilities. This statement is effective for fiscal years beginning after
November 15, 2007. We have not elected the fair value treatment afforded by
SFAS No. 159.
In March
2008, the FASB issued SFAS No. 161, “Disclosures about Derivative
Instruments and Hedging Activities,” which amends SFAS No. 133, “Accounting
for Derivative Instruments and Hedging Activities.” Enhanced disclosures to
improve financial reporting transparency are required and include disclosure
about the location and amounts of derivative instruments in the financial
statements, how derivative instruments are accounted for and how derivatives
affect an entity’s financial position, financial performance and cash flows. A
tabular format including the fair value of derivative instruments and their
gains and losses, disclosure about credit risk-related derivative features and
cross-referencing within the footnotes are also new requirements. SFAS
No. 161 is effective for financial statements issued for fiscal years and
interim periods beginning after November 15, 2008, with early application
and comparative disclosures encouraged, but not required. We have not yet
adopted SFAS No. 161. We do not believe that SFAS No. 161 will have a
material impact on our financial position, results of operations or cash
flows.
In May
2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted
Accounting Principles.” The statement is intended to improve financial reporting
by identifying a consistent hierarchy for selecting accounting principles to be
used in preparing financial statements that are prepared in conformance with
generally accepted accounting principles. Unlike Statement on Auditing Standards
(SAS) No. 69, “The Meaning of Present in Conformity With GAAP,” FAS No. 162 is
directed to the entity rather than the auditor. The statement is effective 60
days following the SEC’s approval of the Public Company Accounting Oversight
Board (PCAOB) amendments to AU Section 411, “The Meaning of Present Fairly in
Conformity with GAAP,” and is not expected to have any impact on the Company’s
results of operations, financial condition or liquidity.
On
December 29, 2008, the Securities and Exchange Commission adopted rule changes
to modernize its oil and gas reporting disclosures. The changes are
intended to provide investors with a more meaningful and comprehensive
understanding of oil and gas reserves.
The
updated disclosure requirements are designed to align with current practices and
changes in technology that have taken place in the oil and gas industry since
the adoption of the original reporting requirements more than 25 years
ago.
New
disclosure requirements include:
|
·
|
Permitting
the use of new technologies to determine proved reserves if those
technologies have been demonstrated empirically to lead to reliable
conclusions about reserve volumes.
|
|
·
|
Enabling
companies to additionally disclose their probable and possible reserves to
investors. Currently, the rules limit disclosure to only proved
reserves.
|
|
·
|
Allowing
previously excluded resources, such as oil sands, to be classified as oil
and gas reserves.
|
|
·
|
Requiring
companies to report on the independence and qualifications of a preparer
or auditor and requiring companies to file reports when a third party is
relied upon to prepare reserve estimates or conduct a reserves
audit.
|
|
·
|
Requiring
companies to report oil and gas reserves using an average price based upon
the prior 12-month period – rather than the year-end price – to maximize
the comparability of reserve estimates among companies and mitigate the
distortion of the estimates that arises when using a single pricing
date.
|
The new
requirements are effective for registration statements filed on or after January
1, 2010, and for annual reports on Forms 10-K and 20-F for fiscal years ending
on or after December 31, 2009. The Company believes that this new requirement
could have a significant impact on reported reserves and depletion rates when
implemented.
Segment
and Related Information
Although
we have a number of operating divisions, separate segment data has not been
presented as they meet the criteria for aggregation as permitted by SFAS No.
131, “Disclosures About Segments of an Enterprise and Related
Information."
2.
Partnership Formation
On May
25, 2007, Abraxas Petroleum Corporation entered into a contribution, conveyance
and assumption agreement with the Partnership, Abraxas General Partner, LLC, a
Delaware limited liability company and wholly-owned subsidiary of Abraxas which we
refer to as the GP, Abraxas Energy Investments, LLC, a Texas limited liability
company and wholly-owned subsidiary of Abraxas which we refer to as the LP, and
Abraxas Operating, LLC, a Texas limited liability company and wholly-owned
subsidiary of Abraxas Energy Partners which we refer to as the Operating
Company. Among other things, the contribution agreement provided for the
contribution by Abraxas to the Operating Company of certain assets located in
South and West Texas in exchange for all of the equity interests of the
Operating Company.
In
consideration for these assets, the Partnership and the Operating Company,
jointly and severally, assumed all of Abraxas’ existing indebtedness under its
Floating Rate Senior Secured Notes due 2009, which we refer to as the notes, and
the obligation to pay certain preformation and transaction expenses and issued
general partner units and common units to the GP and the LP, respectively, in
exchange for their ownership interests in the Operating Company. On May 25,
2007, Abraxas Energy Partners sold 6,002,408 common units, representing an
approximate 52.8% interest in Abraxas Energy Partners, for $16.66 per Common
Unit, or approximately $100 million, pursuant to a purchase agreement dated May
25, 2007, to a group of accredited investors. After consummation of
these transactions, the general partner units and the common units owned by the
GP and the LP constituted a 47.2% ownership interest in the
Partnership.
As a
result of these transactions, the Company recognized a gain of $59.4 million in
2007. The gain was calculated in accordance with the requirements
of SEC Staff Accounting Bulletin 51, (Topic 5H) based on the fact
that the Company elected gain treatment as a policy and the transaction met the
following criteria: (1) there were no additional broad corporate
reorganizations contemplated; (2) there was not a reason to believe that the
gain would not be realized, since there is no additional capital raising
transaction anticipated nor was there a significant concern about the new
entity’s ability to continue in existence; (3) the share price of capital raised
in the private placement was objectively determined; (4) no repurchases of the
new subsidiary’s units are planned; and (5) the Company acknowledges that it
will consistently apply the policy, and any future transactions that might
result in a loss must be recorded as a loss in the statement of
operations.
3.
Registration and Exchange Rights Agreements
Registration Rights
Agreement. On
May 25, 2007, in connection with Abraxas Energy’s private placement
offering, the Partnership entered into a registration rights agreement with the
private investors, which was amended on December 5, 2007 and on October 6,
2008. Under the registration rights agreement, the Partnership agreed
as soon as practicable, (a) to prepare and file with the SEC a registration
statement for (1) an initial public offering of common units and (2) a
shelf registration statement for the resale of the common units held by the
private investors and (b) to use commercially reasonable efforts to cause
the IPO registration statement and the shelf registration statement to be
declared effective by April 30, 2009.
The
registration rights agreement required the Partnership to pay liquidated damages
if the IPO registration statement or the shelf registration statement is not
declared effective by April 30, 2009. The liquidated damages equate
to $0.04165 per common unit for the first 60 days after April 30, 2009,
with such amount increasing by an additional $0.04165 per common unit for each
30-day period for the next 60 days up to a maximum of $0.1666 per common
unit. Liquidated damages are payable in cash, unless the Partnership is unable
to as a result of a restriction under its credit facility, in which case, the
liquidated damages will be paid in-kind. As the Company currently believes that
it is not probable that amounts will be payable under this provision, no
liability has been recorded for this contingency as of December 31,
2008.
Exchange and Registration Rights
Agreement. Abraxas
Energy, Abraxas Petroleum and the private investors entered into an exchange and
registration rights agreement dated May 25, 2007, and amended on October 6,
2008. Under the terms of the amended agreement, in the event that the
Partnership has not consummated its initial public offering by April 30, 2009
(“the Trigger Date”), the private investors have the right to convert their
common units purchased in the private placement offering into shares of common
stock of Abraxas Petroleum. Each of the Partnership’s common units are
convertible into a number of shares of Abraxas Petroleum common stock equal to
$16.66 divided by the then current market price of Abraxas Petroleum’s common
stock times 0.9. Abraxas Petroleum also agreed within 30 days of
the Trigger Date, to prepare and file with the SEC a registration statement to
enable the resale of ABP common stock. Abraxas Petroleum further agreed to use
its commercially reasonable efforts to cause the registration statement to
become effective by the 120th calendar
day following the Trigger Date. In consideration of the October 2008
amendment, Abraxas Energy agreed to pay the private investors $0.0625 per unit
per quarter beginning with the fourth quarter of 2008 and ending on certain
events, including the initial public offering. This payment is
payable in cash, unless the Partnership is unable to as a result of a
restriction under its credit facility, in which case, the payment will be paid
in-kind. In the fourth quarter of 2008, in connection with conversion rights
held by the original investors in the Partnership, approximately 343,000 shares
of Common stock were issued upon conversion of partnership units.
Terms of
the exchange and registration rights agreement are such that there is a maximum
number of shares of Abraxas Common Stock, representing approximately 20% of the
total number of common shares outstanding, into which the holders of the
Partnership units may convert without further action on the part of Abraxas
shareholders. As a result of this, the minority interest reflected in the
Company’s balance sheet represents the value of these potential shares into
which the Partnership units may be converted. Losses at the Partnership in
excess of this amount (approximately $7.1 million) have not been allocated to
the minority interest and, instead have been absorbed by the Company. To the
extent that the Partnership operates profitably in the future, such profits will
be
first
allocated back to the Company to the extent of any excess losses previously
recorded, prior to the allocation of such profits to the minority
interest.
4.
Condensed Consolidating Financial Statements
The consolidated financial statements
include the accounts of the Company and its wholly-owned subsidiaries and the
operations of the Partnership which was formed on May 25, 2007. The
operations of Abraxas Petroleum and the Partnership are consolidated for
financial reporting purposes. The interest of the 52.7% owners of the
Partnership presented as minority interest. Abraxas owns the
remaining 47.3% of the partnership interests. The Company has determined that
based on its control of the general partner of the Partnership, this 47.3% owned
entity should be consolidated for financial reporting purposes. The
consolidating financial statements are presented as
follows:
|
Condensed
Consolidating Balance Sheet
|
|||||||||||||
|
December
31, 2008
|
|||||||||||||
|
(In
thousands)
|
|||||||||||||
|
Abraxas
Petroleum
Corporation
|
Abraxas
Energy
Partners,
L.P.
|
Reclassifi-
cations
and
eliminations
|
Consolidated
|
||||||||||
|
Assets:
|
|||||||||||||
|
Cash
|
$
|
—
|
$
|
1,924
|
$
|
—
|
$
|
1,924
|
|||||
|
Accounts
receivable, less allowance for doubtful accounts
|
11,514
|
7,695
|
(11,243
|
)
|
7,966
|
||||||||
|
Derivative
asset – current
|
—
|
22,832
|
—
|
22,832
|
|||||||||
|
Other
current assets
|
535
|
37
|
—
|
572
|
|||||||||
|
Total
current assets
|
12,049
|
32,488
|
(11,243
|
)
|
33,294
|
||||||||
|
Property
and equipment – net
|
41,291
|
119,017
|
—
|
160,308
|
|||||||||
|
Deferred
financing fees, net
|
102
|
1,341
|
—
|
1,443
|
|||||||||
|
Derivative asset
– long-term
|
—
|
16,394
|
—
|
16,394
|
|||||||||
|
Investment
in partnership
|
11,889
|
—
|
(11,889
|
)
|
—
|
||||||||
|
Other
assets
|
400
|
—
|
—
|
400
|
|||||||||
|
Total
assets
|
$
|
65,731
|
$
|
169,240
|
$
|
(23,132
|
)
|
$
|
211,839
|
||||
|
Liabilities
and Stockholders’ deficit:
|
|||||||||||||
|
Current
liabilities:
|
|||||||||||||
|
Accounts
payable
|
$
|
21,659
|
$
|
1,150
|
$
|
(8,885
|
)
|
$
|
13,924
|
||||
|
Accrued
interest
|
18
|
332
|
—
|
350
|
|||||||||
|
Other
accrued expenses
|
1,643
|
243
|
—
|
1,886
|
|||||||||
|
Derivative
liability – current
|
—
|
3,000
|
—
|
3,000
|
|||||||||
|
Current
maturities of long-term debt
|
134
|
40,000
|
—
|
40,134
|
|||||||||
|
Dividend
payable
|
—
|
2,358
|
(2,358
|
)
|
—
|
||||||||
|
Total
current liabilities
|
23,454
|
47,083
|
(11,243
|
)
|
59,294
|
||||||||
|
Long-term
debt
|
5,235
|
125,600
|
—
|
130,835
|
|||||||||
|
Future
site restoration
|
910
|
9,049
|
—
|
9,959
|
|||||||||
|
Total
liabilities
|
29,599
|
181,732
|
(11,243
|
)
|
200,088
|
||||||||
|
Minority
interest
|
—
|
7,093
|
7,093
|
||||||||||
|
Partnership
capital
|
—
|
34,324
|
(34,324
|
)
|
—
|
||||||||
|
Stockholders’/Partners
equity (deficit)
|
36,132
|
(46,816
|
)
|
15,342
|
4,658
|
||||||||
|
Total
liabilities and stockholders’ equity (deficit)
|
$
|
65,731
|
$
|
169,240
|
$
|
(23,132
|
)
|
$
|
211,839
|
||||
|
Condensed
Consolidating Balance Sheet
|
|||||||||||||
|
December
31, 2007
|
|||||||||||||
|
(In
thousands)
|
|||||||||||||
|
Abraxas
Petroleum
Corporation
|
Abraxas
Energy
Partners,
L.P.
|
Reclassifi-
cations
and
eliminations
|
Consolidated
|
||||||||||
|
Assets:
|
|||||||||||||
|
Cash
|
$
|
17,177
|
$
|
1,759
|
$
|
—
|
$
|
18,936
|
|||||
|
Accounts
receivable, less allowance for doubtful accounts
|
6,288
|
4,696
|
(4,856
|
)
|
6,128
|
||||||||
|
Derivative
asset – current
|
—
|
2,658
|
—
|
2,658
|
|||||||||
|
Other
current assets
|
355
|
22
|
—
|
377
|
|||||||||
|
Total
current assets
|
23,820
|
9,135
|
(4,856
|
)
|
28,099
|
||||||||
|
Property
and equipment – net
|
21,533
|
95,494
|
—
|
117,027
|
|||||||||
|
Deferred
financing fees, net
|
141
|
715
|
—
|
856
|
|||||||||
|
Derivative asset
– long-term
|
—
|
359
|
—
|
359
|
|||||||||
|
Investment
in partnership
|
27,838
|
—
|
(27,838
|
)
|
—
|
||||||||
|
Other
assets
|
778
|
—
|
—
|
778
|
|||||||||
|
Total
assets
|
$
|
74,110
|
$
|
105,703
|
$
|
(32,694
|
)
|
$
|
147,119
|
||||
|
Liabilities
and Stockholders’ deficit:
|
|||||||||||||
|
Current
liabilities:
|
|||||||||||||
|
Accounts
payable
|
$
|
14,698
|
$
|
—
|
$
|
(4,856
|
)
|
$
|
9,842
|
||||
|
Accrued
interest
|
—
|
241
|
—
|
241
|
|||||||||
|
Other
accrued expenses
|
1,514
|
—
|
—
|
1,514
|
|||||||||
|
Derivative
liability – current
|
—
|
5,154
|
—
|
5,154
|
|||||||||
|
Total
current liabilities
|
16,212
|
5,395
|
(4,856
|
)
|
16,751
|
||||||||
|
Long-term
debt
|
—
|
45,900
|
—
|
45,900
|
|||||||||
|
Derivative
liability – long-term
|
—
|
3,941
|
—
|
3,941
|
|||||||||
|
Future
site restoration
|
404
|
779
|
—
|
1,183
|
|||||||||
|
Total
liabilities
|
16,616
|
56,015
|
(4,856
|
)
|
67,775
|
||||||||
|
Minority
interest
|
—
|
23,497
|
23,497
|
||||||||||
|
Partnership
capital
|
—
|
57,438
|
(57,438
|
)
|
—
|
||||||||
|
Stockholders’/Partners
equity (deficit)
|
57,494
|
(7,750
|
)
|
6,103
|
55,847
|
||||||||
|
Total
liabilities and stockholders’ equity (deficit)
|
$
|
74,110
|
$
|
105,703
|
$
|
(32,694
|
)
|
$
|
147,119
|
||||
|
Condensed
Consolidating Parent Company and Subsidiary Statement of
Operations
|
|||||||||||||
|
For
the year ended December 31, 2008
|
|||||||||||||
|
(In
thousands)
|
|||||||||||||
|
Abraxas
Petroleum
Corporation
|
Abraxas
Energy
Partners,
L.P.
|
Reclassifi-
cations
and
eliminations
|
Consolidated
|
||||||||||
|
Revenues:
|
|||||||||||||
|
Oil
and gas production revenues
|
$
|
15,693
|
$
|
83,391
|
$
|
—
|
$
|
99,084
|
|||||
|
Rig
revenues
|
1,210
|
—
|
—
|
1,210
|
|||||||||
|
Other
|
16
|
—
|
—
|
16
|
|||||||||
|
16,919
|
83,391
|
—
|
100,310
|
||||||||||
|
Operating
costs and expenses:
|
|||||||||||||
|
Lease
operating and production taxes
|
4,058
|
22,577
|
—
|
26,635
|
|||||||||
|
Depreciation,
depletion, and amortization
|
3,380
|
20,063
|
(100
|
)
|
23,343
|
||||||||
|
Impairment
|
19,145
|
97,121
|
100
|
116,366
|
|||||||||
|
Rig
operations
|
856
|
—
|
—
|
856
|
|||||||||
|
General
and administrative
|
4,470
|
2,657
|
—
|
7,127
|
|||||||||
|
31,909
|
142,418
|
—
|
174,327
|
||||||||||
|
Operating
income (loss)
|
(14,990
|
)
|
(59,027
|
)
|
—
|
(74,017
|
)
|
||||||
|
Other
(income) expense:
|
|||||||||||||
|
Interest
income
|
(165
|
)
|
(22
|
)
|
—
|
(187
|
)
|
||||||
|
Amortization
of deferred financing fees
|
40
|
988
|
—
|
1,028
|
|||||||||
|
Interest
expense
|
293
|
10,203
|
—
|
10,496
|
|||||||||
|
Financing
fees
|
—
|
359
|
—
|
359
|
|||||||||
|
Loss
(gain) on derivative contracts
|
—
|
(28,333
|
)
|
—
|
(28,333
|
)
|
|||||||
|
Other
|
7,418
|
1,105
|
—
|
8,523
|
|||||||||
|
7,586
|
(15,700
|
)
|
—
|
(8,114
|
)
|
||||||||
|
Income
(loss) from operations before income tax and minority
interest
|
(22,576
|
)
|
(43,327
|
)
|
—
|
(65,903
|
)
|
||||||
|
Income
tax
|
—
|
—
|
—
|
—
|
|||||||||
|
Income
from operations before minority interest
|
(22,576
|
)
|
(43,327
|
)
|
—
|
(65,903
|
)
|
||||||
|
Minority
interest
|
—
|
—
|
13,500
|
13,500
|
|||||||||
|
Net
income (loss)
|
$
|
(22,576
|
)
|
$
|
(43,327
|
)
|
$
|
13,500
|
$
|
(52,403
|
)
|
||
|
Condensed
Consolidating Parent Company and Subsidiary Statement of
Operations
|
|||||||||||||
|
For
the year ended December 31, 2007
|
|||||||||||||
|
(In
thousands)
|
|||||||||||||
|
Abraxas
Petroleum
Corporation
|
Abraxas
Energy
Partners,
L.P.
(1)
|
Reclassifi-
cations
and
eliminations
|
Consolidated
|
||||||||||
|
Revenues:
|
|||||||||||||
|
Oil
and gas production revenues
|
$
|
24,758
|
$
|
22,148
|
$
|
—
|
$
|
46,906
|
|||||
|
Rig
revenues
|
1,396
|
—
|
—
|
1,396
|
|||||||||
|
Other
|
7
|
—
|
—
|
7
|
|||||||||
|
26,161
|
22,148
|
—
|
48,309
|
||||||||||
|
Operating
costs and expenses:
|
|||||||||||||
|
Lease
operating and production taxes
|
6,118
|
5,136
|
—
|
11,254
|
|||||||||
|
Depreciation,
depletion, and amortization
|
7,253
|
7,039
|
—
|
14,292
|
|||||||||
|
Rig
operations
|
801
|
—
|
—
|
801
|
|||||||||
|
General
and administrative
|
5,451
|
987
|
—
|
6,438
|
|||||||||
|
19,623
|
13,162
|
—
|
32,785
|
||||||||||
|
Operating
income (loss)
|
6,538
|
8,986
|
—
|
15,524
|
|||||||||
|
Other
(income) expense:
|
|||||||||||||
|
Interest
income
|
(387
|
)
|
(21
|
)
|
—
|
(408
|
)
|
||||||
|
Amortization
of deferred financing fees
|
550
|
121
|
—
|
671
|
|||||||||
|
Interest
expense
|
6,597
|
1,795
|
—
|
8,392
|
|||||||||
|
Loss
(gain) on derivative contracts
|
238
|
4,125
|
—
|
4,363
|
|||||||||
|
Loss
on debt extinguishment
|
—
|
6,455
|
—
|
6,455
|
|||||||||
|
Gain
on sale of assets
|
(59,439
|
)
|
—
|
—
|
(59,439
|
)
|
|||||||
|
Other
|
347
|
—
|
—
|
347
|
|||||||||
|
(52,094
|
)
|
12,475
|
—
|
(39,619
|
)
|
||||||||
|
Income
(loss) from operations before income tax and minority
interest
|
58,632
|
(3,489)
|
—
|
55,143
|
|||||||||
|
Income
tax
|
(283
|
)
|
—
|
—
|
(283
|
)
|
|||||||
|
Income
from operations before minority interest
|
58,349
|
(3,489
|
)
|
—
|
54,860
|
||||||||
|
Minority
interest
|
—
|
—
|
1,842
|
1,842
|
|||||||||
|
Net
income (loss)
|
$
|
58,349
|
$
|
(3,489
|
)
|
$
|
1,842
|
$
|
56,702
|
||||
|
(1)
|
From
inception, May 25 through December
31.
|
|
Condensed
Consolidating Parent Company and Subsidiary Statement of Cash
Flows
|
|||||||||||||
|
For
the year ended December 31, 2008
|
|||||||||||||
|
(In
thousands)
|
|||||||||||||
|
Abraxas
Petroleum
Corporation
|
Abraxas
Energy
Partners,
L.P.
|
Reclassifi-
cations
and
eliminations
|
Consolidated
|
||||||||||
|
Operating
Activities
|
|||||||||||||
|
Net
income (loss)
|
$
|
(22,576
|
)
|
$
|
(43,327
|
)
|
$
|
13,500
|
$
|
(52,403
|
)
|
||
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
|||||||||||||
|
Minority
interest in partnership loss
|
—
|
—
|
(13,500
|
)
|
(13,500
|
)
|
|||||||
|
Change
in derivative fair value
|
—
|
(42,304
|
)
|
—
|
(42,304
|
)
|
|||||||
|
Depreciation,
depletion, and
amortization
|
3,380
|
20,063
|
(100
|
)
|
23,343
|
||||||||
|
Proved property
impairment
|
19,145
|
97,121
|
100
|
116,366
|
|||||||||
|
Accretion
of future site restoration
|
63
|
507
|
—
|
570
|
|||||||||
|
Amortization
of deferred financing fees
|
40
|
988
|
—
|
1,028
|
|||||||||
|
Stock-based
compensation
|
1,162
|
242
|
—
|
1,404
|
|||||||||
|
Other
non-cash transactions
|
7,446
|
—
|
—
|
7,446
|
|||||||||
|
Changes
in operating assets and liabilities
|
6,397
|
(4,960
|
)
|
—
|
1,437
|
||||||||
|
Net
cash provided by operations
|
15,057
|
28,330
|
—
|
43,387
|
|||||||||
|
Investing
Activities
|
|||||||||||||
|
Capital
expenditures, including purchases
and
development of properties – net of dispositions
|
(42,044
|
)
|
(131,900
|
)
|
—
|
(173,944
|
)
|
||||||
|
Net
cash used in investing activities
|
(42,044
|
)
|
(131,900
|
)
|
—
|
(173,944
|
)
|
||||||
|
Financing
Activities
|
|||||||||||||
|
Proceeds
from issuance of common stock
|
88
|
—
|
—
|
88
|
|||||||||
|
Proceeds
from long-term borrowings
|
5,384
|
129,700
|
—
|
135,084
|
|||||||||
|
Payments
on long-term borrowings
|
(15
|
)
|
(10,000
|
)
|
—
|
(10,015
|
)
|
||||||
|
Partnership
distribution
|
4,354
|
(14,351
|
)
|
—
|
(9,997
|
)
|
|||||||
|
Deferred
financing fees
|
(1
|
)
|
(1,614
|
)
|
—
|
(1,615
|
)
|
||||||
|
Net
cash provided by (used in) financing activities
|
9,810
|
103,735
|
—
|
113,545
|
|||||||||
|
Increase
(decrease) in cash
|
(17,177
|
)
|
165
|
—
|
(17,012
|
)
|
|||||||
|
Cash
at beginning of year
|
17,177
|
1,759
|
—
|
18,936
|
|||||||||
|
Cash
at end of year
|
$
|
—
|
$
|
1,924
|
$
|
—
|
$
|
1,924
|
|||||
|
Condensed
Consolidating Parent Company and Subsidiary Statement of Cash
Flows
|
|||||||||||||
|
For
the year ended December 31, 2007
|
|||||||||||||
|
(In
thousands)
|
|||||||||||||
|
Abraxas
Petroleum
Corporation
|
Abraxas
Energy
Partners,
L.P.
|
Reclassifi-
cations
and
eliminations
|
Consolidated
|
||||||||||
|
Operating
Activities
|
|||||||||||||
|
Net
income (loss)
|
$
|
58,349
|
$
|
(3,489
|
)
|
$
|
1,842
|
$
|
56,702
|
||||
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
|||||||||||||
|
Minority
interest in partnership loss
|
—
|
—
|
(1,842
|
)
|
(1,842
|
)
|
|||||||
|
(Gain)
loss on sale of partnership interest
|
(59,439
|
)
|
—
|
—
|
(59,439
|
)
|
|||||||
|
Change
in derivative fair value
|
157
|
6,078
|
—
|
6,235
|
|||||||||
|
Depreciation,
depletion, and
amortization
|
7,253
|
7,039
|
—
|
14,292
|
|||||||||
|
Accretion
of future site restoration
|
(18
|
)
|
145
|
—
|
127
|
||||||||
|
Amortization
of deferred financing fees
|
550
|
121
|
—
|
671
|
|||||||||
|
Stock-based
compensation
|
996
|
—
|
—
|
996
|
|||||||||
|
Other
non-cash transactions
|
191
|
—
|
—
|
191
|
|||||||||
|
Changes
in operating assets and liabilities
|
4,827
|
(4,428
|
)
|
—
|
399
|
||||||||
|
Net
cash provided by operations
|
12,866
|
5,466
|
—
|
18,332
|
|||||||||
|
Investing
Activities
|
|||||||||||||
|
Capital
expenditures, including purchases
and
development of properties
|
(12,822
|
)
|
(14,086
|
)
|
—
|
(26,908
|
)
|
||||||
|
Net
cash used in investing activities
|
(12,822
|
)
|
(14,086
|
)
|
—
|
(26,908
|
)
|
||||||
|
Financing
Activities
|
|||||||||||||
|
Proceeds
from issuance of common stock
|
22,441
|
—
|
—
|
22,441
|
|||||||||
|
Proceeds
from issuance of partnership equity - (net)
|
(6,305
|
)
|
97,207
|
—
|
90,902
|
||||||||
|
Proceeds
from long-term borrowings
|
790
|
45,900
|
—
|
46,690
|
|||||||||
|
Payments
on long-term borrowings
|
(2,500
|
)
|
(125,904
|
)
|
—
|
(128,404
|
)
|
||||||
|
Partnership
distribution
|
2,825
|
(5,988
|
)
|
—
|
(3,163
|
)
|
|||||||
|
Deferred
financing fees
|
(161
|
)
|
(836
|
)
|
—
|
(997
|
)
|
||||||
|
Net
cash provided by (used in) financing activities
|
17,090
|
10,379
|
—
|
27,469
|
|||||||||
|
Increase
(decrease) in cash
|
17,134
|
1,759
|
—
|
18,893
|
|||||||||
|
Cash
at beginning of year
|
43
|
—
|
—
|
43
|
|||||||||
|
Cash
at end of year
|
$
|
17,177
|
$
|
1,759
|
$
|
—
|
$
|
18,936
|
|||||
5.
Acquisitions
On
January 31, 2008, Abraxas Operating , LLC, a wholly-owned subsidiary of the
Partnership, consummated the acquisition of certain oil and gas
properties located in various states from St. Mary Land & Exploration
Company (“St. Mary”) and certain other sellers. The properties are primarily
located in the Rockies and Mid-Continent regions of the United States, and
include approximately 57.2 Bcfe (9,525 MBOE) of estimated proved reserves for a
purchase price of approximately $126.0 million.
The
Partnership borrowed approximately $115.6 million under the Partnership Credit
Facility and $50 million under its Subordinated Credit Agreement in order to
complete this acquisition and repay its previously outstanding
indebtedness
of $45.9 million. For a complete description of these credit facilities, please
see Note 6 “Long-Term Debt”.
Simultaneously,
Abraxas Petroleum announced that it had completed the acquisition of certain oil
and gas properties from St. Mary with estimated proved reserves of approximately
4.3 Bcfe (725 MBOE) for a purchase price of approximately $5.6
million. Abraxas paid the purchase price from its internal
funds. The right to purchase these properties had been assigned to
Abraxas by the Partnership.
Substantially
all amounts paid in the acquisition, including acquisition costs of
approximately $1.1 million, were allocated to the oil and gas properties. The
following unaudited supplemental information presents pro forma financial
results assuming the acquisition had occurred on January 1 of 2008 and
2007. The unaudited pro forma financial results are not necessarily
those that would have been attained had the acquisition occurred as of an
earlier date, nor are they necessarily representative of the future results that
may occur.
|
Unaudited
Pro Forma Financial Information
|
||||||
|
Year
ended December 31,
|
||||||
| 2007 |
2008
|
|||||
|
Revenue
|
$
|
87,643
|
$
|
104,2621
|
||
|
Net
income (loss)
|
$
|
58,242
|
$
|
(50,281)
|
)
|
|
|
Earnings
(loss) per share – basic
|
$
|
1.26
|
$
|
(1.022
|
)
|
|
6.
Long-Term Debt
The
following is a description of the Company’s debt as of December 31, 2007 and
2008, respectively:
|
December
31,
2007
|
December
31,
2008
|
||||||
|
Partnership
credit facility
|
$ |
45,900
|
$ |
125,600
|
|||
|
Subordinated
Partnership credit agreement
|
—
|
40,000
|
|||||
|
Senior
secured credit facility
|
—
|
—
|
|||||
|
Real
estate lien note
|
—
|
5,369
|
|||||
|
45,900
|
170,969
|
||||||
|
Less
current maturities
|
—
|
(40,134
|
)
|
||||
|
$
|
45,900
|
$
|
130,835
|
||||
Maturities
of long-term debt are as follows:
|
Year
ended December 31,
|
|||
|
2009
|
$
|
40,134
|
|
|
2010
|
143
|
||
|
2011
|
152
|
||
|
2012
|
163
|
||
|
2013
|
125,773
|
||
|
Thereafter
|
4,604
|
||
|
$
|
170,969
|
Abraxas Senior
Secured Credit Facility. On June 27, 2007, Abraxas entered into a new
senior secured revolving credit facility, which we refer to as the Credit
Facility. The Credit Facility has a maximum commitment of
$50
million. Availability under the Credit Facility is subject to a borrowing base.
The borrowing base under the Credit Facility, which is currently $6.5 million,
is determined semi-annually by the lenders based upon our reserve reports, one
of which must be prepared by our independent petroleum engineers and one of
which may be prepared internally. The amount of the borrowing base is calculated
by the lenders based upon their valuation of our proved reserves utilizing these
reserve reports and their own internal decisions. In addition, the
lenders, in their sole discretion, may make one additional borrowing base
redetermination during any six-month period between scheduled redeterminations
and we may also request one redetermination during any six-month period between
scheduled redeterminations. The lenders may also make a
redetermination in connection with any sales of producing properties with a
market value of 5% or more of our current borrowing base. Our
borrowing base at December 31, 2008 of $6.5 million was determined based upon
our reserves at June 30, 2008. Our borrowing base can never exceed
the $50.0 million maximum commitment amount. Outstanding amounts
under the Credit Facility will bear interest at (a) the greater of the reference
rate announced from time to time by Société Générale, and (b) the Federal Funds
Rate plus 0.5% of 1%, plus in each case, (c) 0.5% - 1.5% depending on
utilization of the borrowing base, or, if Abraxas elects, at the London
Interbank Offered Rate plus 1.5% - 2.5%, depending on the utilization of the
borrowing base. Subject to earlier termination rights and events of default, the
Credit Facility’s stated maturity date is June 27, 2011. Interest
will be payable quarterly on reference rate advances and not less than quarterly
on Eurodollar advances.
Abraxas
is permitted to terminate the Credit Facility, and may, from time to time,
permanently reduce the lenders' aggregate commitment under the Credit Facility
in compliance with certain notice and dollar increment
requirements.
Each of
Abraxas’ subsidiaries other than the Partnership, Abraxas General Partner, LLC
and Abraxas Energy Investments, LLC has guaranteed Abraxas’ obligations under
the Credit Facility on a senior secured basis. Obligations under the
Credit Facility are secured by a first priority perfected security interest,
subject to certain permitted encumbrances, in all of Abraxas’ and the subsidiary
guarantors’ material property and assets.
Under the
Credit Facility, Abraxas is subject to customary covenants, including certain
financial covenants and reporting requirements. The Credit Facility
requires Abraxas to maintain a minimum Current Ratio as of the last day of each
quarter of not less than 1.00 to 1.00 and an interest coverage ratio (generally
defined as the ratio of consolidated EBITDA to consolidated interest expense as
of the last day of such quarter) of not less than 2.50 to 1.00.
In
addition to the foregoing and other customary covenants, the Credit Facility
contains a number of covenants that, among other things, will restrict Abraxas’
ability to:
· incur
or guarantee additional indebtedness;
· transfer
or sell assets;
· create
liens on assets;
· engage
in transactions with affiliates other than on an “arms-length”
basis;
· make
any change in the principal nature of its business; and
· permit
a change of control.
The
Credit Facility also contains customary events of default, including nonpayment
of principal or interest, violations of covenants, cross default and cross
acceleration to certain other indebtedness, bankruptcy and material judgments
and liabilities.
The
Company is in compliance with all covenants as of December 31,
2008.
Amended and
Restated Partnership Credit Facility. On May 25, 2007, the Partnership
entered into a senior secured revolving credit facility which was amended and
restated on January 31, 2008 and further amended on January 16, 2009, which we
refer to as the Partnership Credit Facility. The Partnership Credit Facility has
a maximum commitment of $300.0 million. Availability under the
Partnership Credit Facility is subject to a borrowing base. The
borrowing base under the Partnership Credit Facility, which is currently $140.0
million, is determined semi-annually by the lenders based upon the Partnership’s
reserve reports, one of which must be prepared by the Partnership’s independent
petroleum engineers and one of which may be prepared internally.
The
amount of
the borrowing base is calculated by the lenders based upon their valuation of
the Partnership’s proved reserves utilizing these reserve reports and their own
internal decisions. In addition, the lenders, in their sole
discretion, may make one additional borrowing base redetermination during any
six-month period between scheduled redeterminations. The lenders may
also make a redetermination in connection with any sales of producing properties
with a market value of 5% or more of the Partnership’s current borrowing
base. The Partnership’s current borrowing base of $140.0 million was
determined based upon its reserves at June 30, 2008. The borrowing
base can never exceed the $300.0 million maximum commitment
amount. During the period beginning on January 16, 2009 and ending on
the date that the Subordinated Credit Agreement is terminated, outstanding
amounts under the Partnership Credit Facility bear interest at (a) the greater
of (1) the reference rate announced from time to time by Société Générale, (2)
the Federal Funds Rate plus 0.5%, and (3) a rate determined by Société Générale
as the daily one-month LIBOR rate plus, in each case, (b) 1.5% - 2.5%, depending
on the utilization of the borrowing base, or, if the Partnership elects, at the
London Interbank Offered Rate plus 2.5% - 3.5% depending on the utilization of
the borrowing base. After the termination of the Subordinated Credit
Agreement, outstanding amounts under the Partnership Credit Facility will bear
interest at (a) the greater of (1) the reference rate announced from time to
time by Société Générale, (2) the Federal Funds Rate plus 0.5%, and (3) a rate
determined by Société Générale as the daily one-month LIBOR rate plus, in each
case, (b) 1.0% - 2.0%, depending on the utilization of the borrowing base, or,
if the Partnership elects, at the London Interbank Offered Rate plus 2.0% - 3.0%
depending on the utilization of the borrowing base. At January 16,
2009, the interest rate on the Partnership Credit Facility was
3.8%. Subject to earlier termination rights and events of default,
the Partnership Credit Facility’s stated maturity date is January 31,
2013. Interest is payable quarterly on reference rate advances and
not less than quarterly on Eurodollar advances. The Partnership is
permitted to terminate the Partnership Credit Facility, and under certain
circumstances, may be required, from time to time, to permanently reduce the
lenders’ aggregate commitment under the Partnership Credit
Facility.
Each of
the general partner of the Partnership, Abraxas General Partner, LLC, which is a
wholly-owned subsidiary of Abraxas and which we refer to as the GP, and Abraxas
Operating, LLC, which is a wholly-owned subsidiary of the Partnership and which
we refer to as the Operating Company, has guaranteed the Partnership’s
obligations under the Partnership Credit Facility on a senior secured
basis. Obligations under the Partnership Credit Facility are secured
by a first priority perfected security interest, subject to certain permitted
encumbrances, in all of the property and assets of the GP, the Partnership and
the Operating Company, other than the GP’s general partner units in the
Partnership.
Under the
Partnership Credit Facility, the Partnership is subject to customary covenants,
including certain financial covenants and reporting requirements. The
Partnership Credit Facility requires the Partnership to maintain a minimum
Current Ratio as of the last day of each quarter of 1.00 to 1.00 and an interest
coverage ratio (defined as the ratio of consolidated EBITDA to consolidated
interest expense) as of the last day of each quarter of not less than 2.50 to
1.00. The Partnership Credit Facility required it to enter into derivative
contracts for specific volumes, which equated to approximately 85% of the
estimated oil and gas production from its net proved developed producing
reserves through December 31, 2011. The Partnership entered into
NYMEX-based fixed price commodity swaps on approximately 85% of its estimated
oil and gas production from its estimated net proved developed producing
reserves through December 31, 2011.
Under the
terms of the Partnership Credit Facility, the Partnership may make cash
distributions if, after giving effect to such distributions, the Partnership is
not in default under the Partnership Credit Facility, there is no borrowing base
deficiency and provided that (a) no such distribution shall be made
using the proceeds of any advance unless the unused portion of the amount then
available under the Partnership Credit Facility is greater than or equal to 10%
of the lesser of the Partnership’s borrowing base (which at January 16, 2009 was
$140.0 million) or the total commitment amount of the
Partnership Credit Facility (which at January 16, 2009 was currently
$300.0 million) at such time, (b) with respect to the cash distribution
scheduled to be made on or about May 15, 2009 attributable to the first quarter
of 2009, no such distribution shall be made unless (i) the sum of
unrestricted cash and the unused portion of the amount then available under the
Partnership Credit Facility after giving effect to such distribution exceeds
$20.0 million, or (ii) the Subordinated Credit Agreement shall have
terminated and (c) no cash distribution shall exceed $0.44 per unit per quarter
while the Subordinated Credit Agreement is outstanding. Additionally,
while the Subordinated Credit Agreement is outstanding, the Partnership’s
capital expenditures are limited to $12.5 million.
In
addition to the foregoing and other customary covenants, the Partnership Credit
Facility contains a number of covenants that, among other things, will restrict
the Partnership’s ability to:
· incur
or guarantee additional indebtedness;
· transfer
or sell assets;
· create
liens on assets;
· engage
in transactions with affiliates;
· make
any change in the principal nature of its business; and
· permit
a change of control.
The
Partnership Credit Facility also contains customary events of default, including
nonpayment of principal or interest, violations of covenants, cross default and
cross acceleration to certain other indebtedness including the Subordinated
Credit Agreement described below, bankruptcy and material judgments and
liabilities.
The
Partnership is in compliance with all covenants as of December 31,
2008.
Subordinated
Credit Agreement
On
January 31, 2008, the Partnership entered into a subordinated credit agreement
which was amended on January 16, 2009, which we refer to as the Subordinated
Credit Agreement. The Subordinated Credit Agreement has a maximum commitment of
$40.0 million. Outstanding amounts under the Subordinated Credit
Agreement bear interest at (a) the greater of (1) the reference rate announced
from time to time by Société Générale, (2) the Federal Funds Rate plus 0.5% and
(3) a rate determined by Société Générale as the daily one-month LIBOR
Offered Rate, plus in each case (b) 7.50% or, if the Partnership elects, at the
greater of (a) 2.0% and (b) at the London Interbank Offered Rate, in
each case, plus 8.50%. At January 16, 2009 the interest rate on the Subordinated
Credit Agreement was 10.5%. Principal payments under the Subordinated
Credit Agreement must be made on May 14, 2009 in an amount, which we refer to as
the May 14, 2009 Payment Amount, equal to the lesser of the amount of cash
distributed to Abraxas Energy Investments, LLC, a wholly-owned subsidiary of
Abraxas Petroleum, on or about February 14, 2009 and $2.25 million with the
balance due on the maturity date. The maturity date may be
accelerated if any limited partner of the Partnership, other than Perlman Value
Partners, exercises its right to convert its limited partner units into shares
of common stock of Abraxas Petroleum pursuant to the terms of the Exchange and
Registration Rights Agreement dated May 25, 2007, as amended, among Abraxas
Petroleum, the Partnership and the purchasers named therein. As a
result of the amendment to the Subordinated Credit Agreement, the date on which
the purchasers, if the Partnership’s initial public offering has not been
consummated prior to that date, may first exchange their Partnership units for
Abraxas Petroleum common stock is April 30, 2009. Subject to earlier
termination rights and events of default, the Subordinated Credit Agreement’s
stated maturity date is July 1, 2009. Interest is payable quarterly
on reference rate advances and not less than quarterly on Eurodollar
advances. The Partnership is permitted to terminate the Subordinated
Credit Agreement, and under certain circumstances, may be required, from time to
time, to make prepayments under the Subordinated Credit Agreement.
Each of
the GP and the Operating Company has guaranteed the Partnership’s obligations
under the Subordinated Credit Agreement on a subordinated secured
basis. Obligations under the Subordinated Credit Agreement are
secured by subordinated security interests, subject to certain permitted
encumbrances, in all of the property and assets of the Partnership, GP, and the
Operating Company, other than the GP’s general partner units in the
Partnership.
Under the
Subordinated Credit Agreement, the Partnership is subject to customary
covenants, including certain financial covenants and reporting requirements. The
Subordinated Credit Agreement requires the Partnership to maintain a minimum
current ratio as of the last day of each quarter of 1.00 to 1.00 and an interest
coverage ratio (defined as the ratio of consolidated EBITDA to consolidated
interest expense) as of the last day of each quarter of not less than 2.50 to
1.00. The Partnership Credit Facility required it to enter into derivative
contracts for specific volumes, which equated to approximately 85% of the
estimated oil and gas production from its net proved developed producing
reserves through December 31, 2011. The Partnership entered into
NYMEX-based fixed price
commodity
swaps on approximately 85% of its estimated oil and gas production from its
estimated net proved developed producing reserves through December 31,
2011.
In
addition to the foregoing and other customary covenants, the Subordinated Credit
Agreement contains a number of covenants that, among other things, will restrict
the Partnership’s ability to:
· incur
or guarantee additional indebtedness;
· transfer
or sell assets;
· create
liens on assets;
· engage
in transactions with affiliates;
· make
any change in the principal nature of its business; and
· permit
a change of control.
The
Subordinated Credit Agreement also contains customary events of default,
including nonpayment of principal or interest, violations of covenants, cross
default and cross acceleration to certain other indebtedness including the
Partnership Credit Facility, bankruptcy and material judgments and
liabilities. In addition, as a result of the amendment to the
Subordinated Credit Agreement, two events of default were added to the
Subordinated Credit Agreement. The first event of default would occur
if the Partnership fails to receive a letter of credit, which we refer to as the
APC L/C, in its favor from Abraxas Petroleum equal to the May 14, 2009 Payment
Amount, the Partnership fails to draw on the APC L/C on or before May 14, 2009
or the Partnership fails to use the proceeds of the APC L/C to make the
principal payment due on May 14, 2009. This event of default would
not occur in the event that the Partnership repays the principal amount due on
May 14, 2009 with funds received from Abraxas Petroleum. The
Partnership and Abraxas Petroleum have agreed that upon the occurrence of such a
payment or the Partnership’s drawing on the APC L/C that, in consideration
thereof, the Partnership would issue a number of additional units to Abraxas
Petroleum determined by dividing the May 14, 2009 Payment Amount by 110% of the
average trading yields of comparable E&P MLPs based on the closing market
price on May 14, 2009 multiplied by the most recent quarterly distribution paid
or declared by the Partnership times four. The other event of default
would occur if the Partnership fails to receive $20.0 million of proceeds from
an equity issuance on or before April 30, 2009.
The
Partnership is in compliance with all covenants as of December 31,
2008.
Real
Estate Lien Note
On
May 9, 2008 the Company entered into an advancing line of credit in the amount
of $5.4 million for the purchase and finish out of a new building to serve as
its corporate headquarters. This note was refinanced in November
2008. The new note bears interest at a fixed rate of 6.375%, and is
payable in monthly installments of principal and interest of $39,754 based on a
twenty year amortization. The note matures in May 2015 at which time the
outstanding balance becomes due. The note is secured by a first lien deed of
trust on the property and improvements. As of December 31, 2008, $5.4 million
was outstanding on the note.
7.
Property and Equipment
The major
components of property and equipment, at cost, are as follows:
|
Estimated
|
December
31,
|
||||||||
|
Useful
Life
|
2007
|
2008
|
|||||||
|
Years
|
(In
thousands)
|
||||||||
|
Oil
and gas properties
|
—
|
$
|
265,090
|
$
|
440,712
|
||||
|
Equipment
and other
|
3-39
|
3,633
|
10,986
|
||||||
|
$
|
268,723
|
$
|
451,698
|
||||||
8. Stock-based
Compensation, Option Plans and Warrants
Stock-based
Compensation
The
Company currently utilizes a standard option pricing model (i.e., Black-Scholes)
to measure the fair value of stock options granted to employees. The fair value
for these options was estimated at the date of grant using a Black-Scholes
option pricing model with the following weighted-average assumptions for 2006,
2007 and 2008, risk-free interest rates of 4.62% in 2006, 4.63% in
2007 and 3.39% in 2008; dividend yields of -0-%; volatility factors of the
expected market price of the Company’s common stock of 62% in 2006, 55% in
2007and 52% in 2008, determined by daily historical prices as well as
other market indicators, and a weighted-average expected life of the option of
4.71 to 5.06 years in 2006, 7.14 years in 2007 and 7.86 in
2008.
Stock
Options
The
Company grants options to its officers, directors, and other employees under
various stock option and incentive plans.
The
Company’s 2005 Directors Plan (as defined below), has authorized the grant of
options to directors for up to 900,000 shares of the Company’s common
stock. All options granted generally become fully exercisable over
three to four years of continued service at 25% to 33% on each anniversary date
or as specified by the Compensation Committee of the Board of
Directors.
The
Company’s 2005 Employee Long-Term Equity Incentive Plan has authorized the grant
of up to 2.1 million awards to management and employees, including options.
Options have a term not to exceed 10 years. Options issued under this plan vest
according to a vesting schedule as determined by the compensation committee.
Vesting may occur upon (1) the attainment of one or more performance goals or
targets established by the committee (2) the optionee’s continued employment or
service for a specified period of time, (3) the occurrence of any event or the
satisfaction of any other condition specified by the committee; or (4) a
combination of any of the foregoing
A summary
of the Company’s stock option activity for the three years ended
December 31, 2008 follows:
|
Options
(000s)
|
Weighted-Average
Exercise
Price
|
Weighted
Average
Remaining
Life
|
Intrinsic
value
Per
Share
|
||||||||
|
Options
outstanding December 31, 2005
|
3,016
|
0.88
|
|||||||||
|
Granted
|
190
|
5.29
|
|||||||||
|
Exercised
|
(747
|
)
|
0.87
|
||||||||
|
Forfeited/Expired
|
(2
|
)
|
4.39
|
||||||||
|
Options
outstanding December 31, 2006
|
2,457
|
$
|
2.29
|
||||||||
|
Granted
|
383
|
3.75
|
|||||||||
|
Exercised
|
(310
|
)
|
1.12
|
||||||||
|
Forfeited/Expired
|
(4
|
)
|
5.37
|
||||||||
|
Options
outstanding December 31, 2007
|
2,526
|
$
|
2.65
|
||||||||
|
Granted
|
86
|
4.37
|
|||||||||
|
Exercised
|
(183
|
)
|
1.37
|
||||||||
|
Forfeited/Expired
|
(39
|
)
|
2.55
|
||||||||
|
Options
outstanding December 31, 2008
|
2,390
|
5.15
|
$
|
1.60
|
|||||||
|
Exercisable
at end of year
|
1,963
|
$
|
4.65
|
$
|
1.42
|
||||||
Other
information pertaining to option activity was as follows during the years ended
December 31:
|
|
2006
|
2007
|
2008
|
|||||||
|
Weighted
average grant-date fair value of stock options granted (per
share)
|
$
|
2.98
|
$
|
2.26
|
$
|
2.47
|
||||
|
Total
fair value of options vested (000’s)
|
$
|
890
|
$
|
888
|
$
|
1,022
|
||||
|
Total
intrinsic value of options exercised (000’s)
|
$
|
409
|
$
|
256
|
$
|
149
|
||||
As of December 31, 2008 the total
compensation cost related to non-vested awards not yet recognized is
approximately $927,000, which will be recognized in 2009 through
2011.
The following table represents the
range of option prices and the weighted average remaining life of outstanding
options as of December 31, 2008 of:
|
Options
outstanding
|
Exercisable
|
|||||||||||
|
Number
Outstanding
|
Weighted
average
remaining
life
|
Weighted
average
exercise
price
|
Number
exercisable
|
Weighted
average
remaining
life
|
Weighted
average
exercise
price
|
|||||||
|
$0.50
– 0.97
|
802,957
|
2.62
|
$
0.72
|
802,957
|
2.62
|
$ 0.71
|
||||||
|
$1.01
– 1.41
|
225,000
|
3.06
|
$ 1.19
|
225,000
|
3.06
|
$ 1.19
|
||||||
|
$2.06
– 2.75
|
92,857
|
5.10
|
$ 2.67
|
92,857
|
5.10
|
$ 2.67
|
||||||
|
$3.09
– 4.90
|
1,176,964
|
7.19
|
$ 4.31
|
796,631
|
6.99
|
$ 4.47
|
||||||
|
$6.05
|
92,000
|
6.39
|
$ 6.05
|
46,000
|
6.39
|
$ 6.05
|
||||||
|
2,389,778
|
1,963,445
|
|||||||||||
Restricted
Stock Awards
Restricted
stock awards are awards of common stock that are subject to restrictions on
transfer and to a risk of forfeiture if the awardee terminates employment with
the Company prior to the lapse of the restrictions. The value of such stock is
determined using the market price on the grant date. Compensation expense is
recorded over the applicable restricted stock vesting periods. The Company did
not award restricted shares prior to 2006.
A summary
of the Company’s restricted stock activity for the year ended December 31,
2008 is presented in the following table:
|
Number
of
Shares
|
Weighted
average
grant
date
fair
value
|
||||
|
Unvested
December 31, 2006
|
—
|
$
|
—
|
||
|
Granted
|
152,736
|
3.60
|
|||
|
Vested
|
—
|
—
|
|||
|
Forfeited
|
(388
|
)
|
—
|
||
|
Unvested
December 31, 2007
|
152,348
|
3.60
|
|||
|
Granted
|
55,952
|
2.85
|
|||
|
Vested/Released
|
(41,061
|
)
|
3.60
|
||
|
Forfeited
|
(2,959
|
)
|
3.51
|
||
|
Unvested
December 31, 2008
|
164,280
|
$
|
3.35
|
Phantom
Units
On
January 31, 2008, in connection with the closing of the St. Mary
acquisition, the Board of Directors of the general partner of the Partnership
awarded phantom units with distribution equivalency rights under its long-term
incentive plan to certain key employees of Abraxas Petroleum.
The
phantom units and associated distribution equivalency rights will vest over four
years and their value is based on the price of common units, as determined by
the Board of Directors of the general partner of the Partnership, quarterly cash
distributions and the percentage increase in cash distributions over
time.
For the
year ended December 31, 2008, the Partnership incurred equity based compensation
expense of $242,000 relating to phantom units.
Director
Stock Awards
On June
1, 2005, the stockholders approved the 2005 Non-Employee Directors Long-Term
Equity Incentive Plan (the “2005 Directors Plan”). The following is a
summary of the 2005 Directors Plan.
Purpose. The
purpose of the 2005 Directors Plan is to attract and retain members of the Board
of Directors and to promote the growth and success of Abraxas by aligning the
long-term interests of the Board of Directors with those of Abraxas’
stockholders by providing an opportunity to acquire an interest in Abraxas and
by providing both rewards for performance and long term incentives for future
contributions to the success of Abraxas.
Administration and
Eligibility. The 2005 Directors Plan will be administered by the
Compensation Committee (the “Committee”) of the Board of Directors and
authorizes the Board to grant non-qualified stock options or issue restricted
stock to those persons who are non-employee directors of Abraxas, including
advisory directors of Abraxas, which currently amounts to a total of nine
people.
Shares Reserved and
Awards. The 2005 Directors Plan reserves 900,000 shares of
Abraxas common stock, subject to adjustment following certain events, as
discussed below. The 2005 Directors Plan provides that each year, at
the first regular meeting of the Board of Directors immediately following
Abraxas’ annual stockholder’s meeting, each non-employee director shall be
granted or issued awards of 10,000 shares of Abraxas common stock, for
participation in Board and Committee meetings during the previous calendar
year. The maximum annual award for any one person is 10,000 shares of
Abraxas common stock or options for common stock. If options, as
opposed to shares, are awarded, the exercise share price shall be no less than
100% of the fair market value on the date of the award while the option terms
and vesting schedules are at the discretion of the Committee. In
addition to the 10,000 shares or options, directors are compensated $12,000 per
year, paid quarterly by issuance of common stock. During 2006, 2007, and 2008
there were 5,782; 22,960; and 30,655 shares, respectively, issued related to
this compensation. The number of shares issued is determined based on
the stock price on the date of issuance.
At
December 31, 2008, the Company has approximately 1.5 million shares
reserved for future issuance for conversion of its stock options, warrants, and
incentive plans for the Company’s directors, employees and
consultants.
Warrants
On May
25, 2007, Abraxas entered into a Securities Purchase Agreement with certain
accredited investors pursuant to which Abraxas issued warrants to purchase
1,174,938 shares of common stock, to the investors at a price of $3.83 per
share. The warrants expire on May 25, 2012 and are exercisable at a price of
$3.83 per share, subject to certain adjustments. During 2008, 182,768 warrants
were exercised.
9. Income
Taxes
Deferred
income taxes reflect the net tax effects of temporary differences between the
carrying amounts of assets and liabilities for financial reporting purposes and
the amounts used for income tax purposes. Significant components of
the Company’s deferred tax liabilities and assets are as
follows:
|
December
31,
|
||||||||||
|
2006
|
2007
|
2008
|
||||||||
|
(In
thousands)
|
||||||||||
|
Deferred
tax liabilities:
|
||||||||||
|
Marketable
securities
|
$
|
261
|
$
|
169
|
$
|
33
|
||||
|
U.S.
full cost pool
|
10,806
|
—
|
—
|
|||||||
|
Partnership
interest
|
—
|
26,356
|
18,349
|
|||||||
|
Total
deferred tax liabilities
|
11,067
|
26,525
|
18,382
|
|||||||
|
Deferred
tax assets:
|
||||||||||
|
U.S.
full cost pool
|
—
|
135
|
418
|
|||||||
|
Capital
loss carryforward
|
4,234
|
5,010
|
—
|
|||||||
|
Depletion
carryforward
|
4,311
|
5,179
|
5,189
|
|||||||
|
Net
operating loss (“NOL”) carryforward
|
67,429
|
60,067
|
68,034
|
|||||||
|
Suspended
losses
|
—
|
1,400
|
—
|
|||||||
|
Alternative
minimum tax credit
|
—
|
100
|
78
|
|||||||
|
Allocated
minority loss carryforward
|
—
|
—
|
3,267
|
|||||||
|
Other
|
1,965
|
1,805
|
2,159
|
|||||||
|
Total
deferred tax assets
|
77,939
|
73,696
|
79,145
|
|||||||
|
Valuation
allowance for deferred tax assets
|
(66,872
|
)
|
(47,171
|
)
|
(60,763
|
)
|
||||
|
Net
deferred tax assets
|
11,067
|
26,525
|
18,382
|
|||||||
|
Net
deferred tax
|
$
|
—
|
$
|
—
|
$
|
—
|
||||
Significant
components of the provision (benefit) for income taxes are as
follows:
|
Years
ended December 31,
|
|||||||||||
|
2006
|
2007
|
2008
|
|||||||||
|
(in
thousands)
|
|||||||||||
|
Current:
|
|||||||||||
|
Federal
|
$
|
-
|
$
|
100
|
$
|
-
|
|||||
|
State
|
-
|
183
|
-
|
||||||||
|
Foreign
|
-
|
-
|
-
|
||||||||
|
$
|
-
|
$
|
283
|
$
|
-
|
||||||
|
Deferred:
|
|||||||||||
|
Federal
|
$
|
-
|
$
|
-
|
$
|
-
|
|||||
|
Foreign
|
-
|
-
|
-
|
||||||||
|
$
|
-
|
-
|
-
|
||||||||
At December 31, 2008, the Company had,
subject to the limitation discussed below, $194.4 million of net operating loss
carryforwards for U.S. tax purposes. These loss carryforwards will
expire from 2021 through 2028 if not utilized.
In
addition to any Section 382 limitations, uncertainties exist as to the future
utilization of the operating loss carryforwards under the criteria set forth
under SFAS Statement No. 109. Therefore, the Company has established a valuation
allowance of $66.9 million for deferred tax assets at December 31, 2006 and
$47.2 million at December 31, 2007 and $60.8 million at December 31,
2008.
The
reconciliation of income tax computed at the U.S. federal statutory tax rates to
income tax expense is:
|
Years
ended:
|
||||||||||
|
December
31,
|
||||||||||
|
2006
|
2007
|
2008
|
||||||||
|
(In
thousands)
|
||||||||||
|
Tax
(expense) benefit at U.S. statutory rates (35%)
|
$
|
(436
|
)
|
$
|
(19,945
|
)
|
$
|
18,341
|
||
|
(Increase)
Decrease in deferred tax asset valuation allowance
|
56
|
19,701
|
(13,592
|
)
|
||||||
|
Expired
capital loss carryforward
|
-
|
-
|
(4,742
|
)
|
||||||
|
State
margin tax
|
-
|
(183
|
)
|
-
|
||||||
|
Permanent
differences
|
(6
|
)
|
(5
|
)
|
(6
|
)
|
||||
|
Other
|
386
|
149
|
(1
|
)
|
||||||
|
$
|
-
|
$
|
283
|
$
|
-
|
|||||
10. Commitments
and Contingencies
Operating
Leases
During
the years ended December 31, 2006, 2007 and 2008 the Company incurred rent
expense related to leasing office facilities of approximately $252,000, $254,000
and $321,000 respectively. During 2008 the Company acquired a building for its
corporate headquarters; accordingly there are no future minimum rental payments
under such leases at December 31, 2008.
Litigation
and Contingencies
From time
to time, the Company is involved in litigation relating to claims arising out of
its operations in the normal course of business. At December 31,
2008 the Company was not engaged in any legal proceedings that are expected,
individually or in the aggregate, to have a material adverse effect on the
Company.
11.
Earnings per Share
The following table sets forth the
computation of basic and diluted earnings per share:
|
Years
ended December 31:
|
|||||||||||
|
2006
|
2007
|
2008
|
|||||||||
|
Numerator:
|
|||||||||||
|
Income
(loss) from continuing operations
|
$
|
700,000
|
$
|
56,702,000
|
$
|
(52,403,000
|
)
|
||||
|
Denominator:
|
|||||||||||
|
Denominator
for basic earnings per share – weighted-average common shares
outstanding
|
42,578,584
|
46,336,825
|
49,004,918
|
||||||||
|
Effect
of dilutive securities:
Stock
options, restricted shares and warrants
|
1,283,797
|
1,256,670
|
—
|
||||||||
|
Dilutive
potential common shares
Denominator
for diluted earnings per share – adjusted weighted-average shares and
assumed exercise of options, restricted shares and
warrants
|
43,862,381
|
47,593,495
|
49,004,918
|
||||||||
|
Net
income (loss) per common share Basic
|
$
|
0.02
|
$
|
1.22
|
$
|
(1.07
|
)
|
||||
|
Net
income (loss) per common share – Diluted
|
$
|
0.02
|
$
|
1.19
|
$
|
(1.07
|
)
|
||||
Basic earnings per share excludes any
dilutive effects of options, warrants unvested restricted stock and convertible
securities and is computed by dividing income available to common stockholders
by the weighted average number of common shares outstanding for the period.
Diluted earnings per share are computed similar to basic, however diluted
earnings per share reflects the assumed conversion of all potentially dilutive
securities. For the year ended December 31, 2008, 334,656 potential shares
relating to stock options, were excluded from the calculation of diluted
earnings per share since their inclusion would have been anti-dilutive due to
the loss incurred in the period.
|
|
12. Quarterly
Results of Operations (Unaudited)
|
Selected
results of operations for each of the fiscal quarters during the years ended
December 31, 2007 and 2008 are as follows:
|
1st
Quarter
|
2nd
Quarter
|
3rd
Quarter
|
4th
Quarter
|
|||||||||||
|
(In
thousands, except per share data)
|
||||||||||||||
|
Year
Ended December 31, 2007
|
||||||||||||||
|
Net
revenue
|
$
|
11,651
|
$
|
12,973
|
$
|
11,404
|
$
|
12,281
|
||||||
|
Operating
income
|
$
|
3,547
|
$
|
4,840
|
$
|
3,648
|
$
|
3,489
|
||||||
|
Net
income (loss)
|
$
|
(988)
|
$
|
57,485
|
(1)
|
$
|
2,998
|
$
|
(2,793
|
)
|
||||
|
Net
income (loss) per common share – basic
|
$
|
(0.02
|
)
|
$
|
1.29
|
$
|
0.06
|
$
|
(0.06
|
)
|
||||
|
Net
income (loss) per common share – diluted.
|
$
|
(0.02
|
)
|
$
|
1.27
|
$
|
0.06
|
$
|
(0.06
|
)
|
||||
|
Year
Ended December 31, 2008
|
||||||||||||||
|
Net
revenue
|
$
|
22,170
|
$
|
34,423
|
$
|
29,246
|
$
|
14,471
|
||||||
|
Operating
income (loss)
|
$
|
9,865
|
$
|
19,183
|
$
|
13,925
|
$
|
(116,990
|
)(2)
|
|||||
|
Net
income (loss)
|
$
|
(8,991)
|
$
|
(57,688
|
)
|
$
|
70,755
|
(1)
|
$
|
(56,479
|
)
|
|||
|
Net
income (loss) per common share – basic.
|
$
|
(0.18
|
)
|
$
|
(1.18
|
)
|
$
|
1.44
|
$
|
(1.15
|
)
|
|||
|
Net
income (loss) per common share – diluted
|
$
|
(0.18
|
)
|
$
|
(1.18
|
)
|
$
|
1.43
|
$
|
(1.15
|
)
|
|||
|
(1)
|
Includes
gain on sale of interest in partnership of $59.4
million.
|
|
(2)
|
Includes
proved property impairment of $116.4
million.
|
13. Benefit
Plans
The
Company has a defined contribution plan (401(k)) covering all eligible employees
of the Company. The Company matched 50% of employee contributions in
2006 and 2007. Company contributions to the plan were $128,523 and $168,977 in
2006 and 2007, respectively. In 2008, in accordance with the safe harbor
provisions of the plan the Company contributed $144,954 to the plan. The
employee contribution limitations are determined by formulas, which limit the
upper one third of the plan members from contributing amounts that would cause
the plan to be top-heavy. The employee contribution is limited to
$15,000, $15,500 and $15,500 in 2006, 2007 and 2008, respectively. The
contribution limit for 2006, 2007 and 2008 was $20,000, $20,500 and $20,500 for
employees 50 years of age or older, respectively.
14. Hedging Program and
Derivatives
The
Company does not use hedge accounting rules as prescribed by SFAS 133 “
Accounting for Derivative Instruments and Hedging Activities”, and related
interpretations. Accordingly, instruments are recorded on the balance sheet at
their fair value with adjustments to the carrying value of the instruments being
recognized in revenue in the current period.
Under the
terms of the Partnership Credit Facility, Abraxas Energy Partners was required
to enter into derivative contracts, or hedging arrangements, for specified
volumes, which equated to approximately 85% of their estimated oil and gas
production through December 31, 2011 from its net proved developed producing
reserves. Abraxas Energy Partners has entered into NYMEX–based fixed
price commodity swaps at then current market prices.
At
December 31, 2008 the Partnership had the following oil and gas derivative
contracts in place:
|
Period
Covered
|
Product
|
Volume
(Production
per day)
|
Fixed
Price
|
|
Year
2009
|
Gas
|
10,595
Mmbtu
|
$ 8.45
|
|
Year
2009
|
Oil
|
1,000
Bbl
|
$ 83.80
|
|
Year
2010
|
Gas
|
9,130
Mmbtu
|
$ 8.22
|
|
Year
2010
|
Oil
|
895
Bbl
|
$ 83.26
|
|
Year
2011
|
Gas
|
8,010
Mmbtu
|
$ 8.10
|
|
Year
2011
|
Oil
|
810Bbl
|
$ 86.45
|
In order
to mitigate its interest rate exposure, the Partnership entered into an interest
rate swap, effective August 12, 2008, to fix its floating LIBOR based debt.
The 2-year interest rate swap arrangement is for $100 million at a fixed
rate of 3.367%. The arrangement expires on August 12, 2010. The interest
rate swap was amended in February 2009 lowering the Partnership’s fixed rate
from 3.367% to 2.95%.
15.
Financial Instruments
SFAS
157—Effective January 1, 2008, the Company adopted Financial
Accounting Standards Board (“FASB”) Statement No. 157, Fair Value Measurements
(“SFAS 157”), which defines fair value, establishes a framework for
measuring fair value, establishes a fair value hierarchy based on the quality of
inputs used to measure fair value and enhances disclosure requirements for fair
value measurements. The implementation of SFAS 157 did not cause a change in the
method of calculating fair value of assets or liabilities, with the exception of
incorporating a measure of the Company’s own nonperformance risk or that of its
counterparties as appropriate, which was not material. The primary impact from
adoption was additional disclosures.
The
Company elected to implement SFAS 157 with the one-year deferral permitted by
FASB Staff Position No. FAS 157-2, Effective Date of FASB Statement
No. 157 (“FSP
157-2”), issued February 2008, which defers the effective date of SFAS 157 for
one year for certain nonfinancial assets and nonfinancial liabilities measured
at fair value, except those that are recognized or disclosed at fair value in
the financial statements on a recurring basis. As it relates to the Company, the
deferral applies to certain nonfinancial assets and liabilities as may be
acquired in a business combination and thereby measured at fair value; impaired
oil and gas property assessments; and the initial recognition of asset
retirement obligations for which fair value is used.
Fair Value
Hierarchy—SFAS 157 establishes a three-level valuation hierarchy for
disclosure of fair value measurements. The valuation hierarchy categorizes
assets and liabilities measured at fair value into one of three different levels
depending on the observability of the inputs employed in the measurement. The
three levels are defined as follows:
|
·
|
Level
1 – inputs to the valuation methodology are quoted prices (unadjusted) for
identical assets or liabilities in active
markets.
|
|
·
|
Level
2- inputs to the valuation methodology include quoted prices for similar
assets and liabilities in active markets, and inputs that are observable
for the asset or liability, either directly or indirectly, for
substantially the full term of the financial
instrument.
|
|
·
|
Level
3 - inputs to the valuation methodology are unobservable and significant
to the fair value measurement.
|
A
financial instrument’s categorization within the valuation hierarchy is based
upon 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 in its entirety requires judgment and considers
factors specific to the asset or liability. The Company is further required to
assess the creditworthiness of the counter party to the derivative contract. The
results of the assessment of non-performance risk, based on the counter party’s
credit risk, could result in an adjustment of the carrying value of the
derivative instrument. The following table presents information about the
Company’s assets and liabilities measured at fair value on a recurring basis as
of December 31, 2008, and indicates the fair value hierarchy of the valuation
techniques utilized by the Company to determine such fair value (in
thousands):
|
Quoted
Prices
in
Active
Markets
for
Identical
Assets
(Level
1)
|
Significant
Other
Observable
Inputs
(Level
2)
|
Significant
Unobservable
Inputs
(Level 3)
|
Balance
as of
December
31,
2008
|
||||||||||
|
Assets:
|
|||||||||||||
|
Investment
in common stock
|
$
|
113
|
$
|
—
|
$
|
—
|
$
|
113
|
|||||
|
NYMEX
Fixed Price Derivative contracts
|
—
|
39,226
|
—
|
39,226
|
|||||||||
|
Total
Assets
|
$
|
113
|
$
|
39,226
|
$
|
—
|
$
|
39,339
|
|||||
|
Liabilities:
|
|||||||||||||
|
NYMEX
Fixed Price Derivative contracts
|
$
|
—
|
$
|
—
|
$
|
—
|
$
|
—
|
|||||
|
Interest
Rate Swaps
|
—
|
—
|
3,000
|
3,000
|
|||||||||
|
Total
Liabilities
|
$
|
—
|
$
|
—
|
$
|
3,000
|
$
|
3,000
|
|||||
The
Company has an investment in a former subsidiary consisting of shares of common
stock. The stock is actively traded on the Toronto Stock Exchange. This
investment is valued at its quoted price as of December 31, 2008 in US dollars.
Accordingly this investment is characterized as Level 1.
The
Partnership’s derivative contracts consist of NYMEX-based fixed price commodity
swaps and interest rate swaps, which are not traded on a public exchange. The
NYMEX-based fixed price derivative contracts are indexed to NYMEX futures
contracts, which are actively traded, for the underlying commodity, and are
commonly used in the energy industry. A number of financial institutions and
large energy companies act as counter-parties to these type of derivative
contracts. As the fair value of these derivative contracts is based on a number
of inputs, including contractual volumes and prices stated in each derivative
contract, current and future NYMEX commodity prices, and quantitative models
that are based upon readily observable market parameters that are actively
quoted and can be validated through external sources, we have characterized
these derivative contracts as Level 2.
In August
2008, the Partnership entered into a two year interest rate swap. The notional
amount is $100.0 million for the first year and $50.0 million for the second
year. The Partnership will pay interest at 3.367% and be paid on a floating
Libor rate. The interest rate swap was amended in February 2009 and increased
the notional amount in the second year to $100.00 million and reduced the
overall interest rate to 2.95%. As there is no actively traded market for this
type of swap and no observable market parameters, these derivative contracts are
classified as Level 3.
Additional
information for the Partnership’s recurring fair value measurements using
significant unobservable inputs (Level 3 inputs) for the year ended December 31,
2008 is as follows (in millions):
|
Derivative
Assets and (Liabilities) - net
|
||
|
Balance
December 31,
2007
|
$
|
—
|
|
Total
realized and unrealized losses included in change in net
liability
|
(2,832)
|
|
|
Settlements
during the
period
|
(168)
|
|
|
Ending
balance December 31,
2008
|
$
|
(3,000)
|
16.
Minority interest in (income) loss of Partnership
The minority interest in the (income)
loss of the Partnership represents the third parties 52.7% interest in the
Partnership’s net income/ loss. Additionally, in accordance with generally
accepted accounting principles, when cumulative losses applicable to the
minority interest exceed the minority interest equity capital in the entity,
such excess and any further losses applicable to the minority interest are
charged to the earnings of the majority interest. If future earnings are
recognized by the minority interest, such earnings will then be credited to the
majority interest (Abraxas) to the extent of such losses previously absorbed and
any excess earnings will increase the recorded value. For the year ended
December 31, 2008, primarily as a result of the ceiling test impairment of the
Partnerships oil and gas properties, losses applicable to the minority interest
exceeded the minority interest equity capital by $9.3 million and, as a result,
$9.3 million of the minority interest loss in excess of equity was charged to
earnings and was reflected as a reduction of the loss applicable to the minority
interest.
17. Supplemental
Oil and Gas Disclosures (Unaudited)
The
accompanying table presents information concerning the Company’s oil and gas
producing activities as required by Statement of Financial Accounting Standards
No. 69, “Disclosures about Oil and Gas Producing
Activities.” Capitalized costs relating to oil and gas producing
activities from continuing operations are as follows:
|
December
31,
|
|||||||
|
2007
|
2008
|
||||||
|
(In
thousands)
|
|||||||
|
Proved
oil and gas properties
|
$
|
265,090
|
$
|
440,712
|
|||
|
Unproved
properties
|
-
|
-
|
|||||
|
Total
|
265,090
|
440,712
|
|||||
|
Accumulated
depreciation, depletion, and amortization, and impairment
|
(148,550
|
)
|
(287,993
|
)
|
|||
|
Net
capitalized costs
|
$
|
116,540
|
$
|
152,719
|
|||
Cost
incurred in oil and gas property acquisitions and development activities related
to continuing operations are as follows:
|
Years
Ended December 31,
|
||||||||||
|
2006
|
2007
|
2008
|
||||||||
|
(In
thousands)
|
||||||||||
|
Development
costs
|
$
|
26,117
|
$
|
16,793
|
$
|
47,690
|
||||
|
Exploration
costs
|
—
|
—
|
1,920
|
|||||||
|
Acquisition
costs
|
—
|
10,000
|
127,671
|
|||||||
|
$
|
26,117
|
$
|
26,793
|
$
|
177,281
|
|||||
The
results of operations for oil and gas producing activities from continuing
operations for the three years ended December 31, 2006, 2007 and 2008,
respectively are as follows:
|
Years
Ended December 31,
|
||||||||||
|
2006
|
2007
|
2008
|
||||||||
|
(In
thousands)
|
||||||||||
|
Revenues
|
$
|
49,448
|
$
|
46,906
|
$
|
99,084
|
||||
|
Production
costs
|
(11,776
|
)
|
(11,254
|
)
|
(26,635
|
)
|
||||
|
Depreciation,
depletion, and amortization
|
(14,809
|
)
|
(14,147
|
)
|
(23,077
|
)
|
||||
|
Proved
property impairment
|
—
|
—
|
(116,366
|
)
|
||||||
|
General
and administrative
|
(1,040
|
)
|
(1,361
|
)
|
(1,431
|
)
|
||||
|
Results
of operations from oil and gas producing activities (excluding corporate
overhead and interest costs)
|
$
|
21,823
|
$
|
20,144
|
$
|
(68,425
|
)
|
|||
|
Depletion
rate per barrel of oil equivalent
|
$
|
11.51
|
$
|
12.58
|
$
|
14.42
|
||||
Estimated
Quantities of Proved Oil and Gas Reserves
The
following table presents the Company’s estimate of its net proved oil and gas
reserves as of December 31, 2006, 2007, and 2008 related to continuing
operations. The Company’s management emphasizes that reserve
estimates are inherently imprecise and that estimates of new discoveries are
more imprecise than those of producing oil and gas
properties. Accordingly, the estimates are expected to change as
future information becomes available. The estimates have been
prepared by independent petroleum reserve engineers. Proved oil and gas
reserves are the estimated quantities of oil and gas that 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 gas reserves are those expected to be
recovered through existing wells with existing equipment and operating methods.
All of the Company’s proved reserves are located in the continental United
States.
Proved
reserves were estimated in accordance with guidelines established by the United
States Securities and Exchange Commission and the FASB, which require that
reserve estimates be prepared under existing economic and operating
conditions with no provision for price and cost escalations except by
contractual arrangements; therefore, year-end prices and costs were used in
estimating net cash flows.
|
Liquid
Hydrocarbons
|
Gas
|
||||
|
(Barrels)
|
(Mcf)
|
||||
|
(In
thousands)
|
|||||
|
Proved
developed and undeveloped reserves:
|
|||||
|
Balance
at December 31, 2005
|
3,035
|
80,271
|
|||
|
Revisions
of previous estimates
|
(90
|
)
|
(2,053
|
)
|
|
|
Extensions
and discoveries
|
11
|
440
|
|||
|
Sales
of minerals in place
|
—
|
(1,810
|
)
|
||
|
Production
|
(200
|
)
|
(6,515
|
)
|
|
|
Balance
at December 31, 2006
|
2,756
|
70,333
|
|||
|
Revisions
of previous estimates
|
541
|
8,652
|
|||
|
Extensions
and discoveries
|
31
|
14,586
|
|||
|
Production
|
(197
|
)
|
(5,568
|
)
|
|
|
Balance
at December 31, 2007 (1)
|
3,131
|
88,003
|
|||
|
Revisions
of previous estimates
|
(1,651
|
)
|
(6,160
|
)
|
|
|
Extensions
and discoveries
|
458
|
5,862
|
|||
|
Purchases
of minerals in place
|
5,684
|
27,110
|
|||
|
Sales
of minerals in place
|
(27
|
)
|
(56
|
)
|
|
|
Production
|
(550
|
)
|
(6,343
|
)
|
|
|
Balance
at December 31, 2008 (1)
|
7,045
|
108,416
|
|||
|
Liquid
Hydrocarbons
|
Gas
|
||||
|
(Barrels)
|
(Mcf)
|
||||
|
Proved
developed reserves:
|
|||||
|
December 31,
2006
|
1,708
|
37,333
|
|||
|
December 31,
2007(1)
|
2,184
|
33,908
|
|||
|
December 31,
2008 (1)
|
5,563
|
48,209
|
|
(1)
|
Proved
reserves at December 31, 2007 and 2008 include 1,206 barrels and 4,478
barrels of oil, respectively and 65,460 and 83,406 Mcf of gas,
respectively attributable to the Partnership in which there is a
52.8% and 52.9% minority interest,
respectively.
|
Reserve
extensions and discoveries which increased significantly during 2007 were
primarily attributable to the Yoakum (Edwards) field in the Gulf Coast
region. Other operators in neighboring fields have been successful
with closer spacing and new completion techniques which resulted in the booking
of additional proved undeveloped reserves in our field. Revisions of
previous estimates which increased appreciably during 2007 were primarily
attributable to higher commodity prices at December 31, 2007 over the prior
year-end which extends the economic life of many wells and thus, increases
reserves estimates.
Purchases
of minerals in place increased significantly during 2008 which was attributable
to the acquisition of oil and gas properties from St. Mary in January 2008.
Revisions of previous estimates which decreased appreciably during 2008 was
primarily attributable to lower commodity prices at December 31, 2008 over the
prior year-end which shortens the economic life of many wells and thus,
decreases reserve estimates.
|
|
Standardized
Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas
Reserves
|
The
following disclosures concerning the standardized measure of future cash flows
from proved oil and gas are presented in accordance with SFAS
No. 69. The standardized measure does not purport to represent
the fair market value of the Company’s proved oil and gas
reserves. An estimate of fair market value would also take into
account, among other factors, the recovery of reserves not classified as proved,
anticipated future changes in prices and costs, and a discount factor more
representative of the time value of money and the risks inherent in reserve
estimates.
Under the
standardized measure, future cash inflows were estimated by applying period-end
prices at December 31, 2008 adjusted for fixed and determinable
escalations, to the estimated future production of year-end proved
reserves. Future cash inflows were reduced by estimated future
production and development costs based on year-end costs to determine pre-tax
cash inflows. Future income taxes were computed by applying the
statutory tax rate to the excess of pre-tax cash inflows over the tax basis of
the properties. Operating loss carryforwards, tax credits, and
permanent differences to the extent estimated to be available in the future were
also considered in the future income tax calculations, thereby reducing the
expected tax expense.
Future
net cash inflows after income taxes were discounted using a 10% annual discount
rate to arrive at the Standardized Measure. Set forth below is the Standardized
Measure relating to proved oil and gas reserves relating to continuing
operations for the three years ended December 31, 2006, 2007 and 2008.
|
Years
Ended December 31,
|
||||||||||
|
2006
|
2007
|
2008
|
||||||||
|
(In
thousands)
|
||||||||||
|
Future
cash inflows
|
$
|
567,805
|
$
|
830,193
|
$
|
811,644
|
||||
|
Future
production costs
|
(169,805
|
)
|
(235,146
|
)
|
(312,756
|
)
|
||||
|
Future
development costs
|
(73,377
|
)
|
(111,221
|
)
|
(134,073
|
)
|
||||
|
Future
income tax expense
|
—
|
—
|
—
|
|||||||
|
Future
net cash flows
|
324,623
|
483,826
|
364,815
|
|||||||
|
Discount
|
(167,779
|
)
|
(268,140
|
)
|
(212,823
|
)
|
||||
|
Standardized
Measure of discounted future net cash relating to proved reserves
(1)
|
$
|
156,844
|
$
|
215,686
|
$
|
151,992
|
||||
|
(1)
|
The
standardized measure of discounted future cash flows included $147,750 and
$118,570 at December 31, 2007 and 2008, respectively attributable to the
Partnership in which there was a 52.8% and 52.9% minority interest,
respectively.
|
|
|
Changes in Standardized Measure
of Discounted Future Net Cash Flows Relating to Proved Oil and Gas
Reserves
|
|
|
The
following is an analysis of the changes in the Standardized Measure
related to continuing operations:
|
|
Year
Ended December 31,
|
||||||||||
|
2006
|
2007
|
2008
|
||||||||
|
(In
thousands)
|
||||||||||
|
Standardized
Measure – beginning of year
|
$
|
309,895
|
$
|
156,844
|
$
|
215,686
|
||||
|
Sales
and transfers of oil and gas produced, net of production
costs
|
(38,318
|
)
|
(35,652
|
)
|
(72,449
|
)
|
||||
|
Net
change in prices and development and production costs from prior
year
|
(114,517
|
)
|
44,791
|
(69,094
|
)
|
|||||
|
Extensions,
discoveries, and improved recovery, less related costs
|
914
|
29,834
|
8,694
|
|||||||
|
Purchases
of minerals in place
|
—
|
—
|
61,761
|
|||||||
|
Sales
of minerals in place
|
(3,268
|
)
|
—
|
(366
|
)
|
|||||
|
Revisions
of previous quantity estimates
|
(15,914
|
)
|
24,033
|
(16,222
|
)
|
|||||
|
Change
in timing and other
|
(12,937
|
)
|
(19,847
|
)
|
2,414
|
|||||
|
Accretion
of discount
|
30,989
|
15,683
|
21,568
|
|||||||
|
Standardized
Measure, end of year
|
$
|
156,844
|
$
|
215,686
|
$
|
151,992
|
||||