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

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Form 10-K for MATADOR RESOURCES CO


18-Mar-2013

Annual Report


Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K. The following discussion contains "forward-looking statements" that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors which could cause actual results to vary from our expectations include changes in oil or natural gas prices, the timing of planned capital expenditures, availability of acquisitions, availability under our Credit Agreement borrowing base, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of gathering, processing and transportation facilities, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See "Cautionary Note Regarding Forward-Looking Statements."

Overview

We are an independent energy company founded in July 2003 and engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with a particular emphasis on oil and natural gas shale plays and other unconventional resource plays. Our current operations are focused primarily on the oil and liquids rich portion of the Eagle Ford shale play in South Texas and in the Haynesville shale play in Northwest Louisiana. In 2012, more than 90% of our total capital expenditures of $334.6 million were directed to our operations in South Texas, primarily in the Eagle Ford shale, as we sought to transition to a more balanced commodity portfolio through the drilling of wells that were prospective for oil and liquids. For the year ended December 31, 2012, approximately 37% of our total production by volume (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) and 79% of our total oil and natural gas revenues were attributable to oil production, primarily from the Eagle Ford shale. In 2013, we expect that approximately 82% of our estimated capital expenditures of $310.0 million will be directed to increasing our oil production and oil reserves in South Texas, primarily in the Eagle Ford shale play. Although we did not drill any operated Haynesville shale natural gas wells during 2012, we directed approximately 3% of our capital expenditures to the Haynesville play in 2012 to participate in several non-operated wells. In addition to these primary operating areas, we have a growing acreage position in Southeast New Mexico and West Texas where we plan to drill three exploratory wells to test the Wolfcamp and Bone Spring plays during 2013. We also have a large exploratory leasehold position in Southwest Wyoming and adjacent areas in Utah and Idaho where we are testing the Meade Peak shale.

On February 2, 2012, our common stock began trading on the NYSE under the symbol "MTDR." On February 7, 2012, we completed our initial public offering of 14,883,334 shares of common stock at $12.00 per share (the "Initial Public Offering"). We sold 12,209,167 shares of common stock in this offering and certain selling shareholders sold 2,674,167 shares of common stock, including shares sold pursuant to the partial exercise of the underwriters' over-allotment option on March 7, 2012. Prior to trading on the NYSE, there was no established public trading market for our common stock.

Our business success and financial results are dependent on many factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy.


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Commodity price volatility, in particular, is a significant risk factor for us. Commodity prices are affected by changes in market supply and demand, which is impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, oil and natural gas price differentials and other factors. Prices for oil, natural gas and natural gas liquids will affect the cash flows available to us for capital expenditures and our ability to borrow and raise additional capital. Declines in oil, natural gas or natural gas liquids prices would not only reduce our revenues, but could also reduce the amount of oil, natural gas and/or natural gas liquids that we can produce economically, and as a result, could have an adverse effect on our financial condition, results of operations, cash flows and reserves.

During 2012, natural gas prices declined to their lowest levels in many years, ranging from a low of approximately $1.91 per MMBtu in mid-April to a high of approximately $3.90 per MMBtu in late November, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. Natural gas prices had declined again since late November 2012, before increasing to $3.81 per MMBtu at March 14, 2013, based upon the NYMEX Henry Hub natural gas futures contract for the earliest delivery date. We would not expect to drill any operated natural gas wells in either our Haynesville or Cotton Valley properties until natural gas prices improve further from these levels or unless the costs to drill and complete these wells decline further from their recent levels or new technologies are developed that increase expected recoveries. See "Risk Factors - Our Identified Drilling Locations Are Scheduled out over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling."

In 2012, our operations were primarily focused on the exploration and development of our Eagle Ford shale properties in South Texas, as we continued to execute our strategy to significantly increase our oil production and oil reserves during 2012. During the year ended December 31, 2012, we completed and began producing oil and natural gas from 28 gross/24.5 net Eagle Ford shale wells, including 25 gross/23.7 net operated and 3 gross/0.8 net non-operated Eagle Ford shale wells. We also completed and began producing oil and natural gas from 2 gross/2.0 net wells in the upper Austin Chalk and the lower Austin Chalk/upper Eagle Ford, or "Chalkleford," intervals in 2012. In addition, during 2012, we completed and began producing natural gas from 28 gross/1.1 net non-operated Haynesville shale wells. We also re-entered and drilled a horizontal lateral from the previously suspended Crawford Federal #1 vertical well in Southwest Wyoming; we plan to complete this well in the third quarter of 2013.

We had two contracted drilling rigs operating in South Texas throughout 2012 (except for a brief period near the end of the second quarter when we added a third rig to execute a two-well contract), and almost all of our operated drilling and completion activities were focused on the Eagle Ford shale. We did not drill any operated wells in the Haynesville shale play in Northwest Louisiana during 2012 as a result of the decline in natural gas prices compared to recent years. At March 14, 2013, we continued to have two contracted drilling rigs operating in South Texas: one in LaSalle County and one in DeWitt County.

Our average daily production for the year ended December 31, 2012 was approximately 9,000 BOE per day, including 3,317 Bbl of oil per day and 34.1 MMcf of natural gas per day, as compared to 7,049 BOE per day, including 422 Bbl of oil per day and 39.8 MMcf of natural gas per day for the year ended December 31, 2011. Our total oil production increased almost eight-fold to just over 1.2 million Bbl of oil during the year ended December 31, 2012, from approximately 154,000 Bbl of oil during the year ended December 31, 2011. This increased oil production is a direct result of our drilling operations in the Eagle Ford shale. Oil production comprised approximately 37% of our total production for the year ended December 31, 2012, as compared to only 6% of our total production for the year ended December 31, 2011.


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During the three months ended December 31, 2012 specifically, our average daily production was 10,385 BOE per day, including 4,630 Bbl of oil per day and 34.5 MMcf of natural gas per day. This was an increase of almost 50% compared to our average daily production for the three months ended December 31, 2011 of 6,953 BOE per day, including 448 Bbl of oil per day and 39.0 MMcf of natural gas per day. Our total oil production increased ten-fold to 426,000 Bbl of oil during the three months ended December 31, 2012, as compared to total oil production of 41,000 Bbl of oil during the three months ended December 31, 2011. Our average daily production for the fourth quarter of 2012 was a sequential increase of 18% from the average daily production of 8,838 BOE per day, including 3,291 Bbl of oil per day and 33.3 MMcf of natural gas per day, achieved during the third quarter of 2012. For the three months ended December 31, 2012, our oil production grew 41% sequentially, as compared to the three months ended September 30, 2012.

At December 31, 2012, our estimated total proved reserves were 23.8 million BOE, including 10.5 million Bbl of oil and 80.0 Bcf of natural gas (13.3 million BOE). At December 31, 2012, 58% of our total proved reserves were proved developed reserves compared to 34% at December 31, 2011. At December 31, 2012, 44% of our total proved reserves were oil and 56% of our total proved reserves were natural gas, as compared to 12% oil and 88% natural gas at December 31, 2011. Our proved oil reserves grew 176% (almost three-fold) from 3.8 million Bbl at December 31, 2011 to 10.5 million Bbl at December 31, 2012. This growth in oil reserves was attributable to our drilling program in the Eagle Ford shale during 2012. Our proved natural gas reserves declined to 80.0 Bcf at December 31, 2012 from 170.4 Bcf at December 31, 2011. As a result of substantially lower natural gas prices in 2012, we removed 97.8 Bcf (16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana from our total proved reserves at June 30, 2012, and these proved undeveloped reserves were likewise not included in our estimated total proved reserves at December 31, 2012. As long as the leasehold acreage associated with these previously classified proved undeveloped natural gas reserves is held by production from existing Haynesville wells, however, these natural gas volumes remain available to be developed by us or the operator at a future time should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries.

The PV-10 of our estimated total proved reserves was $423.2 million at December 31, 2012 compared to a PV-10 of $248.7 million at December 31, 2011, an increase of 70% despite lower commodity prices used to estimate PV-10 in 2012 compared to 2011. The PV-10 at December 31, 2012 was determined using the 12-month unweighted average of first-day-of-the-month oil and natural gas prices for 2012 of $91.21 per barrel and $2.757 per MMBtu, respectively, adjusted by lease for quality, energy content, regional price differentials and other expenses as needed compared to average oil and natural gas prices of $92.71 per barrel and $4.118 per MMBtu, respectively, adjusted as further described above, used to determine PV-10 at December 31, 2011. The Standardized Measure of estimated future net cash flows from our total proved reserves, including estimated future income tax expenses, was $394.6 million at December 31, 2012 and $215.5 million at December 31, 2011, respectively. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see "Business - Estimated Proved Reserves."

For the year ended December 31, 2012, our oil and natural gas revenues were approximately $156.0 million, or an increase of about 133%, as compared to approximately $67.0 million for the year ended December 31, 2011. Our oil revenues increased over eight-fold to approximately $123.7 million for the year ended December 31, 2012, as compared to $14.5 million for the year ended December 31, 2011. Our total realized revenues for 2012, including realized gain on derivatives, were approximately $170.0 million, or an increase of about 129%, as compared to $74.1 million for 2011. For the year ended December 31, 2012, our Adjusted EBITDA was approximately $115.9 million, or an increase of about 132%, as compared to an


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Adjusted EBITDA of approximately $49.9 million for the year ended December 31, 2011. For a reconciliation of Adjusted EBITDA to net income (loss) and net cash provided by operating activities, see "Selected Financial Data - Non-GAAP Financial Measures."

We currently intend to allocate approximately 82% of our 2013 capital expenditure budget to the exploration, development and acquisition of additional interests in South Texas, primarily in the Eagle Ford shale play. We also plan to allocate about 16% of our 2013 capital expenditure budget to the exploration and acquisition of additional interests in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. As a result of these anticipated capital expenditures in South Texas and in Southeast New Mexico and West Texas, we plan to dedicate approximately 98% of our 2013 anticipated capital expenditure budget to opportunities prospective for oil and liquids production. While we have budgeted capital expenditures of approximately $310.0 million for 2013, the aggregate amount we will expend may fluctuate materially based on market conditions, the actual costs to drill scheduled wells, our drilling results and our ability to obtain additional capital. Since approximately 84% of our Eagle Ford acreage was either held by production or not burdened by lease expirations before 2014, 79% of our Wolfcamp and Bone Spring acreage was either held by production or not burdened by lease expirations before 2014 and almost all of our Haynesville acreage was held by production at December 31, 2012, we possess the financial flexibility to allocate our capital when and where we believe it is economical and justified.

As we continue to explore and develop our leasehold positions in the Eagle Ford shale in South Texas and as we begin to explore and develop our leasehold positions in the Wolfcamp and Bone Spring plays in Southeast New Mexico and West Texas, we may face various challenges in establishing operations in new areas, including securing the necessary services to drill and complete wells and securing the necessary facilities to gather, process, transport and market the oil and natural gas that we produce. We may also incur higher than anticipated costs associated with establishing new operating infrastructure on our leases throughout the area. We believe that we have successfully secured the necessary drilling and completion services for our current Eagle Ford operations. We did not experience difficulties in securing completion, and in particular hydraulic fracturing, services for our newly drilled wells during the year ended December 31, 2012, although we experienced these problems at various times during 2011 in South Texas and may have such difficulties again in the future. We believe that maintaining reliable and timely drilling and completion services and reducing drilling and completion costs will be essential to the successful development and profitability of the Eagle Ford shale play, as well as the Wolfcamp and Bone Spring plays in Southeast New Mexico and West Texas. See "Risk Factors - The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows."

We did experience temporary pipeline and natural gas processing interruptions from time to time during the year ended December 31, 2012 associated with natural gas production from our Eagle Ford shale wells. To alleviate most of the interruptions and processing capacity constraints we experienced during 2012, effective September 1, 2012, we entered into a firm five-year natural gas processing and transportation agreement whereby we committed to transport the anticipated natural gas production from a significant portion of our Eagle Ford acreage in South Texas through the counterparty's system for processing at the counterparty's facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the counterparty's processing plant downstream for fractionation. No assurance can be made that this agreement will alleviate these issues completely, and if we were required to shut in our


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production for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of these facilities, it would have a material adverse effect on our business, financial condition, results of operations and cash flows. We may experience similar interruptions and processing capacity constraints as we begin to explore and develop our Wolfcamp and Bone Spring plays in Southeast New Mexico and West Texas in 2013. See "Risk Factors - The Marketability of Our Production Is Dependent Upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue."

Revenues

Our revenues are derived primarily from the sale of oil, natural gas and natural gas liquids production. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in oil, natural gas or natural gas liquids prices.

Realized gain on derivatives. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and natural gas liquids prices. This revenue item includes the net realized cash gains and losses associated with the settlement of these derivative financial instruments for a given reporting period.

Unrealized gain (loss) on derivatives. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and natural gas liquids prices. This revenue item recognizes the non-cash change in the fair value of our open derivative contracts between reporting periods.

The following table summarizes our revenues and production data for the periods indicated:

                                                                Year Ended December 31,
                                                          2012             2011           2010
Operating Results:
Revenues (in thousands):
Oil                                                     $ 123,654        $ 14,457       $  2,507
Natural gas                                                32,344          52,543         31,535

Total oil and natural gas revenues                        155,998          67,000         34,042
Realized gain on derivatives                               13,960           7,106          5,299
Unrealized (loss) gain on derivatives                      (4,802 )         5,138          3,139

Total revenues                                          $ 165,156        $ 79,244       $ 42,480
Net Production Volumes:
Oil (MBbl)                                                  1,214             154             33
Natural gas (Bcf)                                            12.5            14.5            8.4
Total oil equivalent (MBOE)(1)                              3,294           2,573          1,433
Average daily production (BOE/d)(1)                         9,000           7,049          3,926
Average Sales Prices:
Oil, with realized derivatives (per Bbl)                $  103.55        $  93.80       $  76.39
Oil, without realized derivatives (per Bbl)             $  101.86        $  93.80       $  76.39
Natural gas, with realized derivatives (per Mcf)        $    3.55        $   4.11       $   4.38
Natural gas, without realized derivatives (per Mcf)     $    2.59        $   3.62       $   3.75

(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

Year Ended December 31, 2012 as Compared to Year Ended December 31, 2011

Oil and natural gas revenues. Our oil and natural gas revenues increased by $89.0 million to $156.0 million, or an increase of about 133%, for the year ended December 31, 2012, as compared to the year ended


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December 31, 2011. This increase in oil and natural gas revenues reflects an increase in our oil revenues of $109.2 million and a decrease in our natural gas revenues of $20.2 million for the year ended December 31, 2012, as compared to the year ended December 31, 2011. Our oil revenues increased over eight-fold to $123.7 million for the year ended December 31, 2012, as compared to $14.5 million for the year ended December 31, 2011. Our oil production also increased almost eight-fold to just over 1.2 million Bbl of oil, or about 3,317 Bbl of oil per day, from approximately 154,000 Bbl of oil, or about 422 Bbl of oil per day, during the comparable periods due to our drilling operations in the Eagle Ford shale. A portion of this increase in oil revenue also reflects a higher weighted average oil price of $101.86 per Bbl realized during the year ended December 31, 2012, as compared to a weighted average oil price of $93.80 per Bbl realized during the year ended December 31, 2011. The decrease in our natural gas revenues reflects a decline in our natural gas production by about 14% to approximately 12.5 Bcf for the year ended December 31, 2012, as compared to approximately 14.5 Bcf for the year ended December 31, 2011. This decline in natural gas production is due to several factors, including (i) the natural decline in natural gas production primarily from our existing Haynesville shale and Cotton Valley wells in Northwest Louisiana and East Texas, coupled with our decision not to drill any operated Haynesville shale or Cotton Valley wells in 2012, (ii) the voluntary curtailment by the operators of natural gas production from some of our non-operated Haynesville shale wells in Northwest Louisiana at various times during 2012 and (iii) delays in natural gas production from our newly completed Eagle Ford shale wells in South Texas as a result of natural gas pipeline and production facility constraints. This decrease in natural gas revenues also results from a significantly lower weighted average natural gas price of $2.59 per Mcf realized during the year ended December 31, 2012, as compared to a weighted average natural gas price of $3.62 per Mcf realized during the year ended December 31, 2011.

Realized gain on derivatives. Our realized gain on derivatives increased by approximately $6.9 million to $14.0 million for the year ended December 31, 2012 from $7.1 million for the year ended December 31, 2011. For the year ended December 31, 2012, we realized a gain of approximately $11.9 million on our open natural gas derivative contracts and a gain of approximately $2.1 million on our open oil derivative contracts. As a result of declining natural gas prices between the comparable periods, we realized an average gain of approximately $1.45 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2012, as compared to $1.03 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2011. Our total natural gas volumes hedged for the year ended December 31, 2012 were also approximately 19% higher than the total natural gas volumes hedged for the year ended December 31, 2011. We realized an average gain of $1.74 per Bbl hedged on all of our open oil contracts during the year ended December 31, 2012. We had no open oil or NGL derivative contracts during the year ended December 31, 2011.

Unrealized gain (loss) on derivatives. Our unrealized loss on derivatives was approximately $4.8 million for the year ended December 31, 2012, as compared to an unrealized gain of $5.1 million for the year ended December 31, 2011. During the period from December 31, 2011 to December 31, 2012, the net fair value of our open oil, natural gas and natural gas liquids derivative contracts decreased from approximately $9.3 million to approximately $4.5 million, resulting in an unrealized loss on derivatives of approximately $4.8 million for the year ended December 31, 2012. During the year ended December 31, 2012, the net fair value of our open natural gas costless collar contracts decreased by $8.7 million due primarily to the gains realized on these contracts during 2012. The net fair value of our open oil derivative contracts increased $3.7 million during the year ended December 31, 2012 as a result of a decrease in oil prices at December 31, 2012 compared to December 31, 2011 and also as a result of two additional oil derivatives contracts we entered into during 2012. During the year ended December 31, 2012, we also entered into various NGL swap contracts which had a net fair value of approximately $0.2 million at December 31, 2012. We had no open NGL swap contracts during the year ended December 31, 2011.


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Year Ended December 31, 2011 as Compared to Year Ended December 31, 2010

Oil and natural gas revenues. Our oil and natural gas revenues increased by $33.0 million to $67.0 million, or an increase of about 97%, for the year ended December 31, 2011, as compared to the year ended December 31, 2010. This increase in oil and natural gas revenues corresponds with an increase of about 79% in our oil and natural gas production to 2.6 million BOE for the year ended December 31, 2011 from 1.4 million BOE for the year ended December 31, 2010. This increased production was almost entirely due to drilling operations in the Eagle Ford and Haynesville shales. A portion of the increase in oil and natural gas revenues reflects the approximate five-fold increase in our oil production for the year ended December 31, 2011 as compared to the year ended December 31, 2010, as well as a higher average oil price of $93.80 per Bbl realized during 2011, as compared to an average oil price of $76.39 per Bbl realized during 2010.

Realized gain on derivatives. Our realized gain on derivatives increased by approximately $1.8 million to $7.1 million for the year ended December 31, 2011 from $5.3 million for the year ended December 31, 2010. The realized gain from our open natural gas costless collar contracts increased primarily as a result of the decline in natural gas prices during the comparable periods. We realized approximately $1.03 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2011 as compared to $0.89 per MMBtu hedged on all of our open natural gas costless collar contracts during . . .

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