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AXAS > SEC Filings for AXAS > Form 10-Q on 9-May-2014All Recent SEC Filings

Show all filings for ABRAXAS PETROLEUM CORP

Form 10-Q for ABRAXAS PETROLEUM CORP


9-May-2014

Quarterly Report


Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following is a discussion of our financial condition, results of operations, liquidity and capital resources. This discussion should be read in conjunction with our consolidated financial statements and the notes thereto, included in our Annual Report on Form 10-K for the year ended December 31, 2013 filed with the SEC on March 17, 2014.

Except as otherwise noted, all tabular amounts are in thousands, except per unit values.

Critical Accounting Policies

There have been no changes from the Critical Accounting Policies described in our Annual Report on Form 10-K for the year ended December 31, 2013.

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. Factors Affecting Our Financial Results

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;

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 production. The prices we receive 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 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 production are dependent upon numerous factors beyond our control. Significant declines in commodity prices could have a material adverse effect on our financial condition, results of operations, cash flows and quantities of reserves recoverable on an economic basis.

During the three months ended March 31, 2014, the New York Mercantile (NYMEX) future price for oil averaged $98.61 per barrel as compared to $94.36 per barrel during the three months ended March 31, 2013. NYMEX future spot prices for gas averaged $4.72 per MMBtu for the three months ended March 31, 2014 compared to $3.48 for the same period of 2013. Prices closed on March 31, 2014 at $101.58 per Bbl of oil and $4.37 per MMBtu of gas, compared to closing on March 31, 2013 at $97.23 per Bbl of oil and $3.48 per MMBtu of gas. 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;

quality of the hydrocarbons; and


gathering, processing and transportation costs.

The following table sets forth our average differentials for the three months ended March 31, 2014 and 2013:

                                Oil - NYMEX            Gas - NYMEX
                                  Three months ended March 31,
                             2014        2013       2014       2013
Average realized price (1) $ 90.18     $ 90.62     $ 5.03    $  3.02
Average NYMEX price          98.61       94.36       4.72       3.48
Differential               $ (8.43 )   $ (3.74 )   $ 0.31    $ (0.46 )


_____________________________________


(1) Excludes the impact of derivative activities

Increases in the differential between the NYMEX price and the realized price we receive have in the past, and could in the future, significantly reduce our revenues and cash flow from operations. The decrease in the gas differential was primarily due to higher realized prices for Bakken gas due to its high BTU content. Our average price differentials relative to WTI increased due to increases in U.S. production growth constraining available pipeline takeaway and refining capacity in the regions in which we operate.

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. By removing a significant portion of price volatility on our future 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 sustained and, in the future, will sustain realized and unrealized losses on our derivative contracts when market prices are higher than our contract prices. Conversely, when prevailing market prices are lower than our contract prices, we will recognize realized and unrealized gains on our commodity derivative contracts. For the three months ended March 31, 2014, we recognized a realized loss of $0.7 million and an unrealized loss of $0.9 million on our commodity swaps. In the three months ended March 31, 2013, we recognized an unrealized loss $0.6 million and a realized loss of $0.9 million on our commodity swaps. 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 contracts at March 31, 2014:

                                                           Fixed Price Swap
                   Oil - WTI                   Oil - Brent                 Oil - LLS           Natural Gas - NYMEX
             Daily                        Daily                      Daily
Contract    Volume       Swap Price      Volume      Swap Price      Volume     Swap Price     Daily Volume     Swap Price
Periods      (Bbl)       (per Bbl)        (Bbl)       (per Bbl)      (Bbl)       (per Bbl)        (Mcf)         (per Mcf)
2014         1,510     $      92.75           -     $         -         98     $    101.26          3,167     $       4.06
2015           553     $      85.00         494     $     97.04          -     $         -          1,450     $       4.08
2016           948     $      84.10           -     $         -          -     $         -              -     $          -
2017           494     $      84.18           -     $         -          -     $         -              -     $          -

At March 31, 2014, the aggregate fair value of our oil and gas derivative contracts was a liability of approximately $4.6 million.

Production Volumes

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 in a timely manner. Based on the reserve information set forth in our reserve estimates as of December 31, 2013, the average annual estimated decline rate for our net proved developed producing reserves is 9% during the first five years, 9% in the next five years, and approximately 9% 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 prior property sales. Our ability to acquire or find additional reserves will be dependent, in part, upon the amount of available funds for acquisition, exploration and development projects.

We had capital expenditures of $36.7 million during the three months ended March 31, 2014. We have a capital expenditure budget for 2014 of $125.0 million. Approximately 94% of the 2014 budget will be spent on unconventional horizontal oil wells in the Bakken/Three Forks and Eagle Ford plays, with the remainder being utilized for leasehold acquisition. The 2014 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.

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, 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 March 31, 2014, we had $70.0 million of availability under our credit facility.

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, 2013, we operated properties accounting for approximately 94% 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, 2013, we drilled or participated in 142 gross (40.0 net) wells of which 96% 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 56% of our estimated proved reserves at December 31, 2013 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.

Operational Update

In the following discussion, production rates do not include the impact of NGL production and shrinkage from processing including the flaring of gas. The following provides an overview of our present activities by region:

Eagle Ford

At Abraxas' Jourdanton prospect in Atascosa County, Texas, the Snake Eyes 1H averaged 531 boepd (493 barrels of oil per day, 232 mcf of natural gas per day) over the well's first 23 full days of production flowing naturally. After loading up after 23 days, the well was placed on sub-pump. Since being placed on sub-pump, the well produced 729 boepd (703 barrels of oil per day, 158 mcf of natural gas per day) in its first full production day. Abraxas recently completed the Spanish Eyes 1H with a 19 stage completion. The well has been flowing to sales for approximately 19 days and is expected to be placed on sub-pump this week. Abraxas also recently completed the Eagle Eyes 1H with an 18 stage completion and the well just began flowback. Abraxas owns a 100% working interest across the Jourdanton prospect. Total acreage at Jourdanton now consists of approximately 7,142 net acres.

At Abraxas' Cave prospect, in McMullen County, Texas, the company shut in the Dutch 2H on April 14 to begin drilling operations on the Dutch 1H. The Dutch 1H is currently drilling at 16,583 feet and is expected to be fracture stimulated and turned to sales in mid-June. Abraxas holds a 100% working interest in the Dutch 1H and 2H.


At Abraxas' Dilworth East prospect, in McMullen County, Texas the company plans to complete the R. Henry 2H with a 19 stage fracture stimulation in late May. The well is currently anticipated to be turned over to sales in early June when gas takeaway is available at the lease. Abraxas holds a 100% working interest in the R. Henry 2H.

Williston Basin

In McKenzie County, North Dakota, the Jore 1H, 2H and 4H are currently being fracture stimulated. On the Ravin West pad, Abraxas recently reached TD on the lateral of the Ravin 4H at 20,754 feet. After casing the lateral on the Ravin 4H, the company will drill the laterals of the Ravin 5H, Ravin 6H and Ravin 7H. Abraxas owns a working interest of approximately 76% and 51% in the Jore and Ravin West pads, respectively.

Results of Operations

The following table sets forth certain of our consolidated operating data for
the periods presented:


                                            Three Months Ended
                                                  March 31,
                                              2014           2013
Operating revenue: (1)
Oil sales                               $    20,935        $ 17,184
Gas sales                                     3,250           2,852
NGL sales                                     1,665           1,127
Other                                            43              33
                                        $    25,893        $ 21,196

Operating income                              7,339           3,768

Oil sales (MBbl)                                232             190
Gas sales (MMcf)                                646             945
NGL sales (MBbl)                                 37              32
Boe sales                                       377             379
Average oil sales price (per Bbl) (1)   $     90.18        $  90.62
Average gas sales price (per Mcf) (1)   $      5.03        $   3.02
Average NGL sales price (per Bbl)       $     44.85        $  34.88
Average oil equivalent price (Boe)      $     68.57        $  55.77

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

Comparison of Three Months Ended March 31, 2014 to Three Months Ended March 31, 2013
Operating Revenue. During the three months ended March 31, 2014 operating revenue increased to $25.9 million from $21.2 million for the same period of 2013. The increase in revenue was primarily due to higher oil and NGL production as well as higher realized commodity prices. Increased oil and NGL sales volumes contributed $4.1 million to operating revenue for the three months ended March 31, 2014, partially offset by lower gas sales volumes. Decreased oil prices had a negative impact of $0.08 million and increased NGL prices contributed $0.3 million. Lower gas sales volumes negatively impacted revenue by $1.5 million. Increased gas prices contributed $1.9 million to revenue.

Oil sales volumes increased to 232 MBbl during the three months ended March 31, 2014 from 190 MBbl for the same period of 2013. The increase in oil sales was due to new wells brought on line, offset by natural field declines and sales of non-core properties. New wells brought on production contributed 133 MBbl for the three months ended March 31, 2014. Properties sold during 2013 contributed
76.7 MBbl during the first quarter of 2013. Gas sales volumes decreased to 646 MMcf for the three months ended March 31, 2014 from 945 MMcf for the same period of 2013. The decrease in gas production was due to natural field declines; the timing of new wells being brought on line and property sales, as well as our emphasis on drilling oil wells as opposed to gas wells. New wells brought on production contributed 75.9 MMcf for the three months ended March 31, 2014. Properties sold during 2013 contributed 115.0 MMcf in the first quarter of 2013. NGL sales volumes increased to 37 MBbl for


the three months ended March 31, 2014 from 32 MBbl for the same period of 2013. 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 three months ended March 31, 2014 decreased to $5.9 million from $6.5 million for the same period in 2013. The decrease in LOE was partially due to the disposition of high cost properties during 2013. LOE per Boe for the three months ended March 31, 2014 was $15.63 compared to $17.03 for the same period of 2013. The decrease per Boe was due to lower costs and higher sales volumes for the three months ended March 31, 2014 as compared to the same period of 2013.

Production and Ad Valorem Taxes. Production and ad valorem taxes for the three months ended March 31, 2014 increased to $2.2 million from $1.9 million for the same period of 2013. The increase was primarily due to higher realized commodity prices in the quarter ended March 31, 2014 as compared to the same period of 2013.
General and Administrative ("G&A") Expenses. G&A expenses, excluding stock-based compensation, for the three months ended March 31, 2014 increased to $2.4 million as compared to $2.1 million for the same period of 2013. The increase in G&A expense was primarily due to an increase in personnel and the corresponding increase in salary expense for the first quarter of 2014. G&A expense per Boe, excluding stock-based compensation, was $6.32 for the quarter ended March 31, 2014 compared to $5.42 for the same period of 2013. The increase per Boe was due to higher costs.
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 the Company's common stock have been granted and are valued at the date of grant and expense is recognized over their vesting period. For the three months ended March 31, 2014 stock-based compensation was $0.4 million compared to $0.5 million in 2013.
Depreciation, Depletion and Amortization ("DD&A") Expenses. DD&A expense for the three months ended March 31, 2014 increased to $7.6 million from $6.5 million for the same period of 2013. The increase was primarily the result of an increase in future development costs in our December 31, 2013 reserve report. DD&A expense per Boe for the three months ended March 31, 2014 was $20.25 compared to $17.15 in 2013.

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 March 31, 2014, 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.

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.
Interest Expense. Interest expense for the three months ended March 31, 2014 decreased to $0.6 million from $1.2 million for the same period of 2013. The decrease was primarily due to lower debt levels in 2014 as compared to the same period of 2013.

(Gain) loss on 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 contracts do not qualify for hedge accounting 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. The estimated value of our commodity derivative contracts was a liability of approximately $4.6 million as of March 31, 2014. 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 three months ended March 31, 2014, we realized a loss on our commodity derivative contracts of $0.7 million and we incurred an unrealized loss of


$0.9 million on our commodity derivative contracts. For the three months ended March 31, 2013, we realized a loss on our commodity derivative contracts of $0.9 million and we incurred an unrealized loss of $0.6 million on our commodity derivative contracts.

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:

the development and exploration 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 grow the business through the development of existing properties and the acquisition of new properties.

Our principal sources of capital are cash flow from operations, borrowings under our credit facility, cash on hand, proceeds from the sale of properties, and if an opportunity presents itself, the sale of debt or equity securities, although we may not be able to complete any financings on terms acceptable to us, if at all.

Capital expenditures. Capital expenditures during the three months ended March 31, 2014 were $36.7 million compared to $17.8 million during the same period of 2013.

The table below sets forth the components of these capital expenditures:

                              Three Months Ended March 31,
                                    2014                  2013
Expenditure category:
Development and land    $        35,802                 $ 17,410
Facilities and other                917                      363
Total                   $        36,719                 $ 17,773

During the three months ended March 31, 2014, capital expenditures were primarily for development of our existing oil and gas properties. During the three months ended March 31, 2013 capital expenditures were primarily for development of our existing oil and gas properties and the completion of the refurbishment of our drilling rig. We anticipate making capital expenditures in 2014 of $125.0 million. The 2014 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, and our ability to obtain permits for drilling locations. 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 economic and industry conditions and commodity prices. Should the prices of oil and gas decline and if our costs of operations increase or if our production volumes decrease, our cash flows will decrease which may result in a reduction of the capital expenditure budget. If we decrease our capital expenditure budget, we may not be able to offset oil and gas production decreases caused by natural field declines.

Sources of Capital. The net funds provided by and/or used in each of the operating, investing and financing activities are summarized in the following table and discussed in further detail below:


                                               Three Months Ended
                                                   March 31,
                                               2014          2013
Net cash provided by operating activities   $   2,424     $  9,913
Net cash used in investing activities         (33,937 )    (17,773 )
Net cash provided by financing activities      26,656        5,953
Total                                       $  (4,857 )   $ (1,907 )

Operating activities during the three months ended March 31, 2014 provided $2.4 million of cash compared to providing $9.9 million in the same period of 2013. For the three months ended March 31, 2014 and 2013, net income plus non-cash expense items accounted for most of these funds. Investing activities . . .

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