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Abraxas pete corp share price consolidates from $6 to $5 but thats just a bump in the road.

|Includes: Abraxas Petroleum Corporation (AXAS)

See details why this is just a bump in the road and that much much higher prices are in the future for (NASDAQ:AXAS).

During 2010,

we sold certain properties, principally non-operated, non-core assets, to generate cash for debt repayment and to accelerate our drilling
program. We sold properties in nine different states for total net proceeds of approximately $29.8 million at various property auctions to numerous buyers. In
total, these properties produced approximately 560 Boepd during 2009, and had approximately 2,043 MBoe of proved reserves at December 31, 2009. The
first $10 million of net proceeds was used to repay the term loan portion of our credit facility and the remaining $19.8 million was used or will be used to
repay outstanding indebtedness under the revolving portion of our credit facility, for capital expenditures and general corporate purposes.

2011 Drilling Plans
We have established a large undeveloped acreage position in several unconventional and conventional resource plays which we intend to develop in
2011. We have set our initial capital expenditure budget for 2011 at $40 million, a 33% increase over 2010. After this offering, we expect to increase our 2011
capital expenditure budget to $60 million, which would be a 100% increase over 2010. Approximately 50% of the expanded 2011 budget will be spent on
unconventional horizontal oil wells in the Bakken/Three Forks and Niobrara plays in the Rocky Mountain region of the United States and the other 50% will
target conventional oil plays in the Permian Basin and onshore Gulf Coast regions of the United States and in the province of Alberta, Canada. The 2011
capital expenditure budget is subject to change depending upon a number of factors, including the availability and costs of drilling and service equipment and
crews, economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil and gas, the availability of sufficient capital resources,
the results of our exploitation efforts, the acquisition, review and interpretation of seismic data and our ability to obtain permits for drilling locations.

The following is a summary of the properties we intend to develop in 2011.
Rocky Mountain—Williston Basin—Bakken/Three Forks—Operated

We acquired our leasehold position in the Williston Basin principally through a producing property acquisition in January 2008 from St. Mary Land &
Exploration, now known as SM Energy Company. We own approximately 20,835 net acres in the basin, the overwhelming majority of which are held by
production from wells producing from formations other than the Bakken or Three Forks, including the Madison, Red River and Duperow formations. Our
average net working interest is approximately 19%, which equates to 109,658 gross acres, or approximately 86 gross (16 net) units on 1,280 acre spacing. Our
acreage position is concentrated in the following areas:

Industry Area Abraxas Area Net Acres

Nesson Anticline Nesson 2,270

Nesson Anticline North Fork 3,540

Rough Rider(1) Harding 7,010

Lewis & Clark(2) Elkhorn Ranch 2,035

Elm Coulee(3) Elm Coulee 440

Burke County, North Dakota Carter 3,200

Sheridan County, Montana Sheridan 2,340

Total 20,835


(1) Rough Rider covers portions of Williams and McKenzie Counties, North Dakota and Roosevelt and Richland Counties, Montana.
(2) Lewis & Clark covers portions of Billings, Golden Valley and Stark Counties, North Dakota.
(3) Elm Coulee covers portions of Richland County, Montana.
During 2010, in McKenzie County, North Dakota in the North Fork area, we drilled two operated wells, one targeting the Three Forks formation and
one targeting the Bakken formation. The first well, the Ravin 26-35 1H, was drilled to a total measured depth of 20,835 feet, including a 9,800 foot lateral in
the Three Forks formation. This well was completed with a 25-stage fracture stimulation and came on-line at an unrestricted daily rate of 1,008 Bbl of oil,
2.44 MMcf of wellhead gas and 290 Bbl of natural gas liquids, or 1,705 Boepd. We operate and own an approximate 60% working interest in this well. The
second well, the Stenehjem 27-34 1H, was drilled to a total measured depth of 16,504 feet, including a 5,965-foot lateral in the middle Bakken formation. A
20-stage fracture stimulation is tentatively scheduled for the first quarter of 2011. We operate and own an approximate 79% working interest in this well. We
intend to continue to acquire long-term leases in areas in which we own a concentrated interest, or in drilling units where we can increase our working interest relatively inexpensively.

Our expanded budget for 2011 includes approximately $20 million for up to five operated horizontal wells targeting the Bakken/Three Forks formation.
Service equipment and crews are in very short supply in the Williston Basin as a large number of rigs are drilling in the basin and together with the increasing
number of fracture stimulation stages per well, the average number of days for a frac job is more than seven days. This shortage has caused service costs to
escalate in the basin. As a result, we will likely delay the drilling of operated Bakken/Three Forks wells until additional services and crews are deployed to the
basin and service costs return to normal, which we anticipate to occur in mid-2011. We estimate gross drilling and completion costs for a horizontal well to be
$7.5 million and estimated ultimate reserves of 500 MBoe, using a 20:1 gas to oil ratio, with 95% of the revenues being oil and liquids. Our estimated ultimate
reserves are based on management's estimates and available industry data. Even through the Bakken/Three Forks play is in the early stages of re-development
with modern technology and the ultimate drainage area per well is largely unknown, some operators have drilled two wells per 1,280 acre unit which would
equate to up to 171 gross (33 net) locations on our leasehold. We anticipate that the industry will eventually drill as many as six wells per 1,280 acre unit which would equate up to 514 gross (98 net) locations on our leasehold.

Rocky Mountain—Williston Basin—Bakken/Three Forks—Non-Operated
During 2010, in Dunn, Divide, McKenzie and Williams Counties, North Dakota, we participated in 10.0 gross (0.35 net) non-operated Bakken/Three
Forks wells, six of which are operated by Continental Resources, Inc. Five of the wells are on production and the remaining five wells are currently drilling
and/or completing. Our budget for 2011 includes $3.0 million for non-operated wells targeting the Bakken/Three Forks formations. We believe that
participating in non-operated wells provides us with the opportunity to learn and leverage off other operators that have more experience and knowledge in the
play than us.

Onshore Gulf Coast Basin—Eagle Ford
The majority of our leasehold position in the onshore Gulf Coast Basin was acquired through our historical activity targeting the Edwards formation in
DeWitt and Lavaca Counties, Texas and more recently, through an active leasing program in DeWitt and Atascosa Counties, Texas.

In August 2010, we formed a joint venture, Blue Eagle, with Rock Oil to develop our acreage in the Eagle Ford Shale play. We contributed 8,333 net
acres, located in Atascosa, DeWitt and Lavaca Counties, Texas, to Blue Eagle and received an approximate 50% equity interest in Blue Eagle and Rock Oil
contributed $25 million in cash and received an approximate 50% equity interest. Rock Oil also committed to contribute an additional $50 million in cash to
Blue Eagle, which combined with the initial $25 million, will be used to acquire additional acreage and 3-D seismic data and to drill and complete wells
targeting the Eagle Ford Shale formation. Upon full funding by Rock Oil, we will own a 25% equity interest in Blue Eagle and Rock Oil will own a 75%
equity interest in Blue Eagle.

Blue Eagle's area of interest encompasses 12 counties across the Eagle Ford Shale basin for expected future acreage acquisitions. We operate the wells
owned by Blue Eagle and Rock Oil manages the day-to-day business affairs of Blue Eagle. Robert L.G. Watson, our President and CEO, serves on the board
of managers of Blue Eagle.

The Eagle Ford Shale play is comprised of three distinct hydrocarbon windows: 43% of Blue Eagle's initial leasehold position is located in the oil
window, 35% is located in the gas/condensate window and 22% is located in the dry gas window.

During 2010, Blue Eagle drilled one well, the T-Bird 1H, to a total measured depth of approximately 19,450 feet, including a 5,700 foot lateral. A 15-
stage fracture stimulation is currently scheduled for January 2011. The T-Bird 1H is in very close proximity to one of the most successful wells in the Eagle
Ford basin, the Enduring Keach Gas Unit No. 1 well, which came on-line at 15.8 MMcf and 1,000 Bbl of condensate per day in May 2010. The well produced
over 1.0 Bcfe during the first five months of production and is currently producing 1.6 MMcf and 100 Bbl of condensate per day. Blue Eagle's budget for
2011 currently includes four horizontal wells targeting the Eagle Ford formation and additional acreage and 3-D seismic data acquisitions, all of which will be
fully funded by Blue Eagle. We estimate gross drilling and completion costs for a horizontal well in the gas/condensate window of the Eagle Ford Shale play
to be $7.0 million and net estimated ultimate reserves of 500 MBoe, using a 20:1 gas to oil ratio, with 70% of the revenues being oil and liquids. The Eagle
Ford formation is much shallower in Blue Eagle's leasehold in the oil window than the gas/condensate window and we estimate gross drilling and completion
costs for a horizontal well in that oil window to be $5.0 million and estimated ultimate reserves of 250 MBoe, using a 20:1 gas to oil ratio, with 90% of the
revenues being oil. Our estimated ultimate reserves are based on management's estimates and available industry data. Even though the Eagle Ford Shale play
is in the early stages of development and the ultimate drainage area per well is largely unknown, some operators have drilled wells on 160 acre spacing which would equate to 52 net locations on Blue Eagle's leasehold. Blue Eagle holds in excess of 8,333 net acres in the play of which a total of 3,000 net acres are held by production with the remainder currently under primary lease terms.

Rocky Mountain—Powder River Basin—Niobrara
We own a total of 20,800 gross (18,700 net) acres in the southern Powder River Basin. Our core leasehold position in the Brooks Draw field, located in
Converse and Niobrara Counties, Wyoming, was acquired in 1999. Since then, we have drilled a total of 12 wells, including seven horizontal wells, and
acquired a 23-square mile proprietary 3-D seismic survey, which has aided in identifying fracture swarms. Of our 17,800 gross (15,700 net) acres of leasehold
in the Brooks Draw field, 14,000 gross/net acres are held by production and the remaining 3,800 gross (1,700 net) acres are under the primary term of the
leases which expire in 2012 or later. In addition, we own approximately 3,000 net acres in Campbell County, Wyoming which are held by production and are
near the Crossbow 3-19H well operated by EOG Resources Inc. in southern Campbell County, Wyoming and other recent horizontal activity. During 2010,
we followed the industry's activity, principally that of EOG Resources and Chesapeake Energy Corp., in this emerging oil play targeting the Niobrara
formation. One of our historical horizontal wells, the Sage Grouse 3H, is producing from the Niobrara formation out of the heel of the vertical section and has
produced over 25 MBbl of oil since 2005 and is estimated to cumulatively produce approximately 50 MBbl of oil. On our leasehold, the Niobrara formation
can be found at a depth of approximately 7,600 to 8,100 feet and is approximately 120 feet thick.

In 2011, we have budgeted to drill one horizontal well targeting the Niobrara formation in the Brooks Draw field. We may elect to increase our activity
in the area pending results of this well. We estimate gross drilling and completion costs for a horizontal well to be $5.0 million and estimated ultimate
reserves of 250 MBbl with 100% of the revenues being oil. Our estimated ultimate reserves are based on management's estimates and available industry and
historical data. Even though the Niobrara play is in its infancy and ultimate drainage area per well is entirely unknown at this time, on 160-acre spacing, we
believe that our held by production acreage could hold up to 117 net locations.

Alberta Basin—Pekisko
We acquired 9,120 gross/net acres of leasehold in two areas in western Alberta in 2010. During 2010, in the Twining area of Alberta, we entered into a
farmout agreement with a large Canadian independent to earn approximately eleven sections, or 7,200 acres of land, by drilling two successful wells. Both
wells targeted the Pekisko formation, which is productive across 210 oil pools created by stratigraphic traps along erosional unconformity from southwest
Saskatchewan to northeast British Columbia traversing the entire province of Alberta.

Oil from the Pekisko was first discovered in 1962 at Sylvan Lake and Twining. In the mid 1990's, the industry transitioned to horizontal drilling
throughout Central Alberta and since 2008, optimizations and renewed interest have increased production from the expansive Pekisko fairway.
Our first well, the Swalwell 6-6, was drilled to a total measured depth of approximately 9,725 feet, including a 4,400 foot lateral, and completed with a
ten-stage fracture stimulation. This well is currently shut-in pending re-completion this summer. The second well, the Twining 9-11, was drilled to a total
measured depth of approximately 10,650 feet, including a 5,250 foot lateral, and completed with a 14-stage acid stimulation. This well is scheduled to come
on-line during the first quarter of 2011. We own a 100% working interest in each of these wells. In addition to the farmout acreage, we have acquired 1,920
gross/net acres of leasehold in western Alberta. Our expanded budget for 2011 includes the drilling of four horizontal wells targeting the Pekisko formation.
We estimate gross drilling and completion costs for a horizontal well to be $3.0 million and estimated ultimate reserves of 150 MBoe, using a 20:1 gas to oil
ratio, with 83% of the revenues being oil. Our estimated ultimate reserves are based on management's estimates and available industry data. The Pekisko
formation is more conventional in nature as are the other targeted formations in the Alberta Basin. Based on geological analysis of the Pekisko fairway, we estimate that we have approximately ten potential drilling locations on our leasehold.

Alberta Basin—Bakken
We accumulated our leasehold in the emerging southern Alberta Basin Bakken play of Toole and Glacier Counties, Montana during 2010. We currently
own approximately 10,000 gross/net acres, the majority of which are under the primary term of the leases with expirations between 2015 and 2020. We also
own the minerals under 800 gross/net acres. During 2010, we monitored industry activity in the play, principally Rosetta Resources Inc. and Newfield
Exploration Company, and continued our own independent study of the play. During 2011, we intend to continue to acquire additional acreage in the
geologically specific parts of the play.

Texas Oil Plays
Permian Basin – Spires Ranch—Strawn.

We acquired our leasehold on the Spires Ranch, which is located in Nolan County, Texas, in 2008 after shooting a 20-square mile 3-D seismic survey. The Spires Ranch is offsetting the Nina Lucia field, operated by Sheridan Production Company, LLC, which has produced over 40 MMBbls of oil from the Pennsylvanian-aged Strawn Reef. We currently own approximately 5,600 gross/net acres, of which approximately 240 gross/net acres are held by production and the remaining 5,360 gross/net acres are under the primary term of the lease, which expires in March 2011 unless the 180-day continuous drilling clause is in effect. During 2009 and 2010, we drilled three wells targeting the Strawn formation and the deeper Ellenburger formation. The first well, the Spires 202, was drilled to a total vertical depth of approximately 7,300 feet and encountered a thick oil
column, but the flank of the structure was pressure depleted. After updating our 3-D seismic interpretation, the Spires 149-1 was drilled to a total vertical
depth of 7,300 feet. This well is currently producing oil and liquids-rich gas while waiting on fracture stimulation. Subsequently, the Spires 126-1H was
drilled to a total measured depth of 9,645 feet, including a 2,300 foot lateral. We expect this well to be completed in the first quarter of 2011. We own a 100%
working interest in each of these wells and in our entire leasehold on the Spires Ranch. Our budget for 2011 includes the drilling of two horizontal wells
targeting the Strawn formation. We estimate gross drilling and completion costs for a horizontal well to be $1.6 million and net estimated ultimate reserves of
112 MBoe, using a 20:1 gas to oil ratio, with 71% of the revenues being oil. Our estimated ultimate reserves are based on management's estimates and
available industry data. Based on our 3-D seismic interpretation and well results to-date, we estimate that we have approximately 10 potential drilling
locations on our leasehold.

Permian Basin—Shallow Howe—Yates.
We acquired the Howe field, which is located in Ward County, Texas, in 1994. Our leasehold position of approximately 2,000 gross/net acres is held by production. The field principally produces gas from the deeper Devonian and Montoya formations at depths of 12,000 to 16,000 feet. During 2010, we evaluated a shallow oil play targeting the Yates formation at a depth of 2,800 feet, which has proven to be productive in offsetting fields.

Our budget for 2011 includes the drilling of four vertical wells targeting the Yates formation. We will own a 100% working interest in
each of these wells. We estimate gross drilling and completion costs for a vertical well to be $400,000 and estimated ultimate reserves of 40 MBoe, using a
20:1 gas to oil ratio, with 99% of the revenues being oil. Our estimated ultimate reserves are based on management's estimates and available industry data.
Based on trend analysis of the Yates formation, we estimate that we have approximately 40 potential drilling locations on our leasehold.
Onshore Gulf Coast Basin—Portilla—Frio. We acquired the Portilla field, which is located in San Patricio County, Texas, in 1993. Our leasehold
position of approximately 1,100 gross/net acres is held by production. The field was discovered by The Superior Oil Company in 1950 and the wells produce
oil and gas from over 70 identified Frio sands at depths of 7,000 to 9,000 feet and from the deeper Vicksburg formation. The Portilla field is a water drive
reservoir; however, the water does not encroach from the side of the field inward but through coning in each individual wellbore.

During 2009 and 2010, we drilled three oil in-fill development wells in the Frio formation to prove the concept of water coning. As a result, we believe there are many un-drained pockets of oil between the existing producing wells.
The Welder 86 and 87 were each drilled to a total depth of approximately 8,700 feet and the Welder 88 was drilled to a total depth of approximately 7,600
feet. The first two wells came on-line at a combined rate of 185 Boepd and the third well is currently being completed. We own a 100% working interest in
each of these wells and in the entire Portilla field. Our budget for 2011 includes the drilling of eight vertical wells targeting the Frio sands at depths of 7,400
and 8,100 feet. We estimate gross drilling and completion costs for a vertical well to be $700,000 for the 7,400 target, or $900,000 for the combined 7,400 and
8,100 targets, and estimated ultimate reserves of 47 and 88 MBbl, respectively, with 100% of the revenues being oil. Our estimated ultimate reserves are
based on management's estimates and historical data. Based on in-depth historical analysis of the Frio formation in the Portilla field, we estimate that we have
approximately 15 potential drilling locations on our leasehold.