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AXAS > SEC Filings for AXAS > Form 10-K on 18-Mar-2013All Recent SEC Filings

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Form 10-K for ABRAXAS PETROLEUM CORP


18-Mar-2013

Annual Report


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 operations, liquidity and capital resources. This discussion excludes the operations of Blue Eagle, except our equity share of Blue Eagle's income (loss). The Blue Eagle joint venture was dissolved effective August 31, 2012. This discussion should be read in conjunction with our Consolidated Financial Statements and the Notes thereto. See "Financial Statements and Supplementary Data" in Item 8.

General

We are an independent energy company primarily engaged in the acquisition, exploration, exploitation, development and production of oil and gas in the United States and Canada. Historically, we have grown through the acquisition and subsequent development and exploitation 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 in two 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:

commodity prices and the effectiveness of our hedging arrangements;

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;


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the level of and interest rates on borrowings; and

the level and success of exploration and development activity.

Commodity Prices and Hedging Arrangements. 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, 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.

The prices of oil and gas have been volatile. During 2012, the price of oil decreased from the levels experienced in 2011. The New York Mercantile Exchange (NYMEX) price for West Texas Intermediate crude oil (WTI) averaged $94.16 per barrel in 2012 as compared to $96.19 per barrel in 2011. During 2012, the average price of gas decreased from an average NYMEX Henry Hub spot price of $4.16 per MMBtu in 2011 to $2.83 per MMBtu in 2012. Prices closed on December 31, 2012 at $91.82 per Bbl of oil and $3.43 per MMBtu of gas. If commodity prices decline, our revenue and cash flow from operations will also likely decline. In addition, lower commodity prices could also reduce the amount of oil and gas that we can produce economically. If gas prices remain depressed or oil prices decline significantly, 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 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.


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The following table sets forth our average differentials for the years ended December 31, 2010, 2011 and 2012:

                                       Oil                                 Gas
                          2010        2011        2012        2010        2011        2012
Average realized price   $ 71.37     $ 89.06     $ 85.11     $  3.97     $  3.58     $  2.36
Average NYMEX price      $ 79.51     $ 95.06     $ 94.16     $  4.38     $  4.14     $  2.83
Differential             $ (8.14 )   $ (6.00 )   $ (9.05 )   $ (0.41 )   $ (0.56 )   $ (0.47 )

Our hedging arrangements equate to approximately 60% of the estimated oil production from our net proved developed producing reserves (as of December 31, 2012) through December 31, 2013, 80% in 2014, 78% in 2016 and 81% for 2016. By removing a significant portion of price volatility on our future oil and gas production, we believe we will mitigate, but not eliminate, the potential effects of changing commodity prices on our 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 in the past and will in the future 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 commodity derivative contracts. In 2011, we incurred a realized gain of $1.7 million and an unrealized gain of $5.7 million. In 2012, we incurred a realized loss of $0.3 million and an unrealized gain of $2.7 million. We have not designated any of these derivative contracts as a hedge as prescribed by applicable accounting rules.

The following table sets forth the summary position of our derivative contracts at December 31, 2012:

                                        Oil
Contract Periods   Daily Volume (Bbl)       Swap Price (per Bbl)
2013                             1,341     $                86.70
2014                             1,100     $                92.58
2015                               933     $                85.00
2016                               883     $                84.00

At December 31, 2012, the aggregate fair market value of our commodity derivative contracts was a liability of approximately $6.4 million.

On March 12, 2012, we monetized our gas derivative contracts for $12.4 million.

Production Volumes. Our proved reserves will decline as oil and gas is produced, unless we find, acquire or develop additional properties containing proved reserves or conduct successful exploration and development activities. Based on the reserve information set forth in our reserve estimates as of December 31, 2012, our average annual estimated decline rate for net proved developed producing reserves is 13% during the first five years, 8% in the next five years, and approximately 7% thereafter. These rates of decline are estimates and actual production declines could be materially higher. While we have had some success in finding, acquiring and developing additional reserves, we have not always been able to fully replace the production volumes lost from natural field declines and property sales. Our ability to acquire or find additional reserves in the future will be dependent, in part, upon the amount of available funds for acquisition, exploration and development projects.

We had capital expenditures during 2012 of $68.6 million related to our exploration and development activities. We have a capital expenditure budget for 2013 of $70 million. Approximately 68% of the 2013 budget will be spent on unconventional horizontal oil wells in the Bakken/Three Forks and Niobrara plays in the Rocky Mountain region, approximately 27% in the Eagle Ford Shale play in South Texas with the remainder targeting conventional oil plays in the Permian Basin region and in the province of Alberta, Canada. The 2013 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, and our ability to obtain permits for drilling locations.

The following table presents historical net production volumes for the years ended December 31, 2010, 2011 and 2012:

                                                            Year Ended December 31,
                                                        2010          2011          2012
Total production (MBoe)                                   1,422         1,272         1,437
Average daily production
(Boepd)                                                   3,896         3,484         3,926
% Oil/ NGL                                                   36 %          45 %          52 %

Availability of Capital. As described more fully under "Liquidity and Capital Resources" below, our sources of capital are cash flow from operating activities, borrowings under our credit facility, cash on hand, proceeds from the sale of properties, monetizing of derivative instruments, and if an appropriate opportunity presents itself, the sale of debt or equity securities, although we may not be able to complete any financing on terms acceptable to us, if at all. As of December 31, 2012, we had approximately $37.0 million of availability under our credit facility.

Borrowings and Interest. At December 31, 2012, we had a total of $113.0 million outstanding under our credit 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 drilling opportunities which, in turn, will be dependent upon


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the level of our production volumes and commodity prices. 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 two-year interest rate swap for $100 million at a fixed rate of 3.367% originally expired on August 12, 2010. The interest rate swap was amended in February 2009 lowering our fixed rate to 2.95%. The interest rate swap was further amended in November 2009, lowering our fixed rate to 2.55% and extending the term through August 12, 2012. The interest rate swap expired in August 2012.

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. At December 31, 2012, we operated properties accounting for approximately 81% of our PV-10, giving us substantial control over the timing and incurrence of operating and capital expenditures. We have identified numerous additional drilling locations on our existing leaseholds, the successful development of which we believe could significantly increase our production and proved reserves. Over the five years ended December 31, 2012, we drilled or participated in 146 gross (41.29 net) wells of which 99% were commercially productive.

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. If our proved reserves decline in the future, our production may also decline and, consequently, our cash flow from operations and the amount that we are able to borrow under our credit facility may also decline. In addition, approximately 49% of our estimated proved reserves at December 31, 2012 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.

Results of Operations

Selected Operating Data. The following table sets forth operating data for the periods presented.

                                                      Year Ended December 31,
                                               (In thousands, except per unit data)
                                               2010               2011           2012
Operating revenue (1):
Oil sales                                  $     35,935       $     48,080     $  54,770
Gas sales                                        21,729             15,127         9,679
NGL sales                                           386              1,408         4,050
Total operating revenues                   $     58,050       $     64,615     $  68,499

Operating income (loss) (2)                $      2,807       $     11,648     $ (16,348 )

Oil sales (MBbls)                                 498.7              539.9         643.5
Gas sales (MMcf)                                5,478.9            4,221.8       4,097.1
NGL sales (MBbls)                                  10.2               28.1         110.8
Oil equivalents (MBoe)                          1,422.1            1,271.6       1,437.1

Average oil sales price (per Bbl)(1)       $      71.37       $      89.05     $   85.11
Average gas sales price (per Mcf)(1)       $       3.97       $       3.58     $    2.36
Average NGL sales price (per Bbl)          $      37.81       $      50.07     $   36.57
Average oil equivalent sales price (Boe)   $      40.82       $      50.81     $   47.67


___________________


(1) Revenue and average sales prices are before the impact of hedging activities.

(2) Operating income includes a proved property impairment of $4.8 million and $19.8 million in 2010 and 2012, respectively related to our Canadian properties.


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Comparison of Year Ended December 31, 2012 to Year Ended December 31, 2011

Operating Revenue. During the year ended December 31, 2012, operating revenue increased to $68.5 million from $64.6 million in 2011. The increase in revenue was due to higher oil and NGL sales volumes in 2012 as compared to 2011, which were partially offset by lower gas sales volumes and lower realized commodity prices. Overall BOE sales in 2012 increased approximately 12% as compared to 2011. Increased oil and NGL sales volumes contributed $11.8 million to operating revenue while decreased gas sales volumes had a negative impact of $0.3 million. Lower commodity prices had a negative impact on operating revenue of $7.7 million.

Oil sales volumes increased to 643.5 MBbls for the year ended December 31, 2012 from 539.9 MBbls for the same period of 2011. The increase in oil sales volumes was due to new production brought on line in 2012. New wells brought onto production in 2012 contributed 129.2 MBbls to production for the year ended December 31, 2012, offset by natural field declines. Gas sales volumes decreased to 4,097.1 MMcf for the year ended December 31 2012 from 4,221.8 MMcf for the year ended December 31, 2011. The decrease in gas production was due to natural field declines and the timing of new wells being brought on line, as well as our emphasis on drilling oil wells as opposed to gas wells. New wells brought onto production during 2012 contributed 361.7 MMcf to production for the year ended December 31, 2012. Due to weak gas prices, our focus was primarily on oil projects during 2012. NGL sales increased to 110.8 MBbls for the year ended December 31, 2012 from 28.1 MBbls for the same period of 2011. The increase in NGL sales was primarily due to increased gas production in West Texas, Wyoming and North Dakota that has a higher NGL content than our historical gas production.

Lease Operating Expenses ("LOE"). LOE for the year ended December 31, 2012 increased to $24.8 million from $21.6 million in 2011. The increase in LOE was primarily due to increased cost of services, and significant non-recurring LOE related to our Canadian operations. LOE per Boe for the year ended December 31, 2012 was $17.26 compared to $16.97 for the same period of 2011. The increase in LOE per Boe was attributable to higher LOE in 2012, partially offset by higher sales volumes in 2012 as compared to 2011.

Production and Ad Valorem Taxes. Production and ad valorem taxes for the year ended December 31, 2012 increased to $6.6 million from $5.8 million in 2011. The increase was primarily due to increased production, particularly in the Rocky Mountain region where production tax rates are higher. Production and ad valorem taxes as a percentage of oil and gas revenue increased to 10% for the year ended December 31, 2012 from 9% in 2011.

General and Administrative ("G&A") Expense. G&A expense, excluding stock-based compensation, increased to $8.6 million for the year ended December 31, 2012 from $7.4 million in 2011. The increase in G&A expense was primarily related to higher salaries and bonuses paid in 2012. G&A expense per Boe was $6.00 for the year ended December 31, 2012 compared to $5.85 for the same period of 2011. The increase in G&A expense per Boe was primarily due to higher production volumes in 2012 compared to 2011.

Stock-Based Compensation. Options granted to employees and directors are valued at the date of grant and expense is recognized over the options vesting period. In addition to options, restricted shares of common stock have been granted and are valued at the date of grant and expense is recognized over their vesting period. Stock-based compensation for the year ended December 31, 2012 increased to $2.1 million from $2.0 million in 2011. The increase in 2012 as compared to 2011 was due to higher values of grants made during 2012 as compared to 2011, and to additional grants during the third quarter of 2012.

Depreciation, Depletion, and Amortization ("DD&A") Expenses. DD&A expense increased to $23.0 million for the year ended December 31, 2012 from $16.2 million in 2011. Our DD&A rate increased due to higher future development cost in the 2012 year end reserve report. DD&A per Boe for 2012 was $16.02 compared to $12.73 in 2011. The increase in DD&A per BOE was due to higher future development cost offset by higher sales volumes in 2012 as compared to 2011.

Interest Expense. Interest expense increased to $5.5 million in 2012 from $4.9 million for 2011. The increase was primarily due to higher levels of debt during 2012 as compared to 2011

Income Taxes. An income tax expense of $0.3 million was recognized in 2012 as a result of an ongoing audit of our 2009 Federal income tax return. We do not agree with the findings of the audit and it is currently under appeal.


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Loss (Gain) on Derivative Contracts. 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. We have elected not to apply hedge accounting to our derivative contracts as prescribed by ASC 815; therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period. Our derivative contracts consist of commodity swaps and interest rate swaps. The net estimated value of our commodity derivative contracts was a liability of approximately $6.4 million as of December 31, 2012. When our derivative contract prices are higher than prevailing market prices, we incur realized and unrealized gains and conversely, when our derivative contract prices are lower than prevailing market prices, we incur realized and unrealized losses. For the year ended December 31, 2012, we realized a loss on our derivative contracts of approximately $0.5 million, which included a realized loss of approximately $0.3 million on our commodity swaps and a realized loss of approximately $0.2 million on our interest rate swap. For the year-ended December 31, 2012, we incurred an unrealized gain of $2.7 million on our commodity swaps. We monetized our gas derivative contracts in March 2012 for $12.4 million. Our interest rate swap expired in August 2012. The estimated value of our derivative contracts was an asset of approximately $1.9 million as of December 31, 2011. For the year ended December 31, 2011, we realized a loss on our derivative contracts of approximately $0.7 million, which included a realized gain of $1.7 million on our commodity swaps and a realized loss of $2.4 million on our interest rate swap. For the year-ended December 31, 2011, we incurred an unrealized gain of $7.5 million on our derivative contracts, which included an unrealized gain of $5.7 million on our commodity swaps and $1.8 million on our interest rate swap.

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 and reported earnings. As of December 31, 2011, our net capitalized costs of oil and gas properties in the United States and Canada did not exceed the present value of our estimated proved reserves. As of December 31, 2012, the net capitalized cost of our oil and gas properties in the United States did not exceed the present value of our estimated proved reserves, however in Canada, the net capitalized cost exceeded the present value of our estimated proved reserves by $19.8 million, resulting in a write down of $19.8 million. There were write downs in the second, third and fourth quarters of 2012 of $1.3 million, $11.8 million and $6.7 million respectively. The year-end amount was calculated in accordance with SEC rules utilizing the twelve month first-day-of-the-month average oil and gas prices for the year ended 2012 which were $95.14 per Bbl for oil and $2.86 per Mcf for gas as adjusted to reflect the expected realized prices for our oil and gas reserves.

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. 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.

Equity in (Income) Loss of Joint Venture. We accounted for Blue Eagle under the equity method of accounting. Under this method, Abraxas' share of net income
(loss) from the joint venture was reflected as an increase (decrease) in its investment account in "Investment in joint venture" and is also recorded as equity investment income (loss) in "Equity in loss (income) of joint venture." For the year ended December 31, 2011, our net share of the joint venture's income was $2.2 million. The joint venture was dissolved on September 4, 2012, effective August 31, 2012, with the assets being distributed to the joint venture partners. The dissolution of the joint venture was accounted for with the net investment in the joint venture being added to our full cost pool. For the year ended December 31, 2012 (through August 31, 2012), we reported income of $2.2 million related to Blue Eagle. See Note 2 of the Notes to Consolidated Financial Statements.


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Comparison of Year Ended December 31, 2011 to Year Ended December 31, 2010

Operating Revenue. During the year ended December 31, 2011, operating revenue increased to $64.6 million from $58.1 million in 2010. The increase in revenue was due to higher realized oil and NGL prices in 2011 as compared to 2010 which were partially offset by decreased prices for gas. Increased oil and NGL prices contributed $8.6 million to operating revenue while decreased gas prices had a negative impact of $2.1 million. Increased sales volumes of oil and NGLs were offset by a decrease in gas sales. Increased oil and NGL sales contributed $4.6 million to operating revenue. Decreased gas sales had a negative impact of $4.5 million on operating revenue.

Oil sales volumes increased to 539.9 MBbls for the year ended December 31, 2011 from 498.7 MBbls for the same period of 2010. The increase in oil sales volumes was due to new production brought on line in 2011. New wells brought onto production in 2011 contributed 94.3 MBbls to production for the year ended December 31, 2011, offset by sales of non-core properties during 2010 and natural field declines. The divested properties produced 29.5 MBbls during 2010. Gas sales volumes decreased to 4,221.8 MMcf for the year ended December 31 2011 from 5,478.9 MMcf for the year ended December 31, 2010. The decrease in gas production was due to sales of non-core properties during 2010, natural field declines and the timing of new wells being brought on line. The divested properties produced 754.9 MMcf in 2010. New wells brought onto production during 2011 contributed 148.7 MMcf to production for the year ended December 31, 2011. Due to weak gas prices, our focus was primarily on oil projects during 2011. NGL sales increased to 28.1 MBbls in for the year ended December 31, 2011 from 10.2 MBbls for the same period of 2010. The increase in NGL sales was primarily due to increased gas production in West Texas and North Dakota that has a higher NGL content than our historical gas production.

Lease Operating Expenses ("LOE"). LOE for the year ended December 31, 2011 increased to $21.6 million from $19.5 million in 2010. The increase in LOE was primarily due to increased cost of services. LOE per Boe for the year ended December 31, 2011 was $16.97 compared to $13.69 for the same period of 2010. The . . .

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