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MTDR > SEC Filings for MTDR > Form 10-K on 17-Mar-2014All Recent SEC Filings

Show all filings for MATADOR RESOURCES CO

Form 10-K for MATADOR RESOURCES CO


17-Mar-2014

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 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, availability of acquisitions, 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 an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Eagle Ford shale play in South Texas and the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas. We also operate in the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. In addition, we have a large exploratory leasehold position in Southwest Wyoming and adjacent areas of 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.


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On September 10, 2013, we completed an underwritten public offering of 9,775,000 shares of our common stock, including 1,275,000 shares issued pursuant to the underwriters' exercise of their option to purchase additional shares. After deducting underwriting discounts, commissions and direct offering costs totaling approximately $7.4 million, we received net proceeds of approximately $141.7 million. We are using the net proceeds from this offering primarily to fund a portion of our capital expenditures, including for the addition of the third rig to our drilling program. We are also using the net proceeds from this offering to fund the acquisition of additional acreage in the Eagle Ford shale, the Permian Basin and the Haynesville shale and for other general working capital needs. Pending such uses, we used a portion of the net proceeds to repay $130.0 million in outstanding borrowings under our Credit Agreement in September 2013, which amounts may be reborrowed in accordance with the terms of that facility for, among other items, the uses contemplated above.
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. Commodity price volatility, in particular, is a significant risk factor for us. Commodity prices are affected by changes in market supply and demand, which are 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.
In 2013, almost all of our operated drilling activities and approximately 70% of our total capital expenditures of $373.5 million were directed to our operations in South Texas, primarily in the Eagle Ford shale, as we continued to increase our oil production and oil reserves. We also increased our leasehold position significantly in the Permian Basin in Southeast New Mexico and West Texas during 2013. At December 31, 2013, we held approximately 70,800 gross (44,800 net) acres in the Permian Basin, as compared to approximately 15,900 gross (7,600 net) acres at December 31, 2012. We also initiated our exploratory drilling activities in the Permian Basin during 2013 to begin the evaluation and delineation of our acreage position. Approximately 27% of our 2013 capital expenditures were directed to our three-well exploration program testing portions of our leasehold position in the Permian Basin and to the acquisition of additional interests prospective for the Wolfcamp, Bone Spring and other oil and liquids-rich plays in the Permian Basin. For the year ended December 31, 2013, approximately 50% of our total production by volume (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) and almost 80% of our total oil and natural gas revenues were attributable to oil production, primarily in the Eagle Ford shale.
During the first quarter of 2013, we had two contracted drilling rigs operating full-time in South Texas and all of our operated drilling and completion activities were focused on the Eagle Ford shale. In late April 2013, we moved one of these contracted drilling rigs to Southeast New Mexico to begin a three-well exploration program testing portions of our leasehold acreage in the Permian Basin, while the second contracted drilling rig continued to operate in the Eagle Ford shale. In mid-August 2013, we added a third contracted drilling rig to our drilling program and returned to operating two contracted drilling rigs in the Eagle Ford shale. We expect to operate two contracted drilling rigs in the Eagle Ford shale and one rig in the Permian Basin throughout 2014. At March 13, 2014, our two Eagle Ford rigs were operating in La Salle and Wilson Counties, Texas, respectively, and our Permian Basin rig was operating in Lea County, New Mexico.
During the year ended December 31, 2013, we completed and began producing oil and natural gas from 25 gross (25.0 net) operated and seven gross (2.6 net) non-operated Eagle Ford shale wells. We also participated in 11 gross (0.4 net) non-operated Haynesville shale wells in Northwest Louisiana and one non-operated test of the Buda formation in South Texas (approximately 21% working interest). During 2013, we also initiated an exploration program testing portions of our growing leasehold position in the Permian Basin. We drilled three wells on this acreage in 2013, including one vertical data well, where we collected extensive well log and whole core data, and one horizontal well testing the Second Bone Spring formation, both in Lea County, New Mexico. We began producing oil and natural gas from the Second Bone Spring horizontal well in late October 2013. We also drilled a horizontal well testing the Wolfcamp "A" formation in Loving County, Texas. This well was completed and began producing oil and natural gas in January 2014.

Our average daily oil equivalent production for the year ended December 31, 2013 was the best in Matador's history at 11,740 BOE per day, including 5,843 Bbl of oil per day and 35.4 MMcf of natural gas per day, an increase of 30% as compared to 9,000 BOE per day, including 3,317 Bbl of oil per day and 34.1 MMcf of natural gas per day, for the year ended December 31, 2012. Our average daily oil production of 5,843 Bbl of oil per day was an increase of 76%, as compared to an average daily oil production of 3,317 Bbl of oil per day during the year ended December 31, 2012. This increase in oil production was a direct result of our drilling operations in the Eagle Ford shale. Oil production comprised 50% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2013, as compared to 37% for the year ended December 31, 2012 and only 6% for the year ended December 31, 2011.


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Our oil and natural gas revenues and Adjusted EBITDA for the year ended December 31, 2013 were also the highest achieved for any year in our history. For the year ended December 31, 2013, our oil and natural gas revenues were $269.0 million, an increase of 72% from oil and natural gas revenues of $156.0 million for the year ended December 31, 2012. Our oil revenues and natural gas revenues increased 72% and 74% to approximately $212.8 million and $56.2 million, respectively, for the year ended December 31, 2013, as compared to $123.7 million and $32.3 million, respectively, for the year ended December 31, 2012. Adjusted EBITDA for the year ended December 31, 2013 was $191.8 million, an increase of 65% from an Adjusted EBITDA of $115.9 million reported for the year ended December 31, 2012. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see "Selected Financial Data - Non-GAAP Financial Measures."

At December 31, 2013, our estimated total proved oil and natural gas reserves were 51.7 million BOE, including 16.4 million Bbl of oil and 212.2 Bcf of natural gas, with a PV-10 of $655.2 million and a Standardized Measure of $578.7 million. At December 31, 2012, our estimated proved oil and natural gas reserves were 23.8 million BOE, including 10.5 million Bbl of oil and 80.0 Bcf of natural gas, with a PV-10 of $423.2 million and a Standardized Measure of $394.6 million. Our estimated proved oil reserves of 16.4 million Bbl at December 31, 2013 increased 56%, as compared to 10.5 million Bbl at December 31, 2012. These reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see "Business - Estimated Proved Reserves."

The unweighted arithmetic average of the first-day-of-the-month natural gas price used to estimate natural gas reserves at December 31, 2013 increased to $3.670 per MMBtu, as compared to $2.757 per MMBtu for 2012. Primarily as a result of continued improvement in natural gas prices over the past year, we added approximately 134.2 Bcf (22.4 million BOE) of proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana to our estimated total proved reserves in the second, third and fourth quarters of 2013, which are reflected in our estimated total proved reserves at December 31, 2013. We had removed 97.8 Bcf (16.3 million BOE) of previously classified proved undeveloped natural gas reserves from our estimated total proved reserves at June 30, 2012 because the natural gas price used to estimate natural gas reserves at June 30, 2012 had declined to $3.146 per MMBtu, a price at which the natural gas volumes associated with almost all of our identified Haynesville shale well locations could no longer be classified as proved undeveloped reserves.
As we continue to explore and develop our leasehold positions in the Eagle Ford shale and as we continue to explore and develop our leasehold positions in the Wolfcamp and Bone Spring plays in the Permian Basin, 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 years ended December 31, 2013 or 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 the Permian Basin. 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."
In the past, we have experienced pipeline and natural gas processing interruptions and capacity and infrastructure constraints associated with natural gas production, which have, among other things, required us to flare natural gas occasionally. To alleviate a portion of such interruptions and processing capacity constraints, 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 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 or flare our 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


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capacity constraints as we explore and develop our leasehold position in the Permian Basin in 2014, although we experienced no material issues 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." About one-third of our acreage in the core area of the Haynesville shale play in Northwest Louisiana is operated by a subsidiary of Chesapeake Energy Corporation. During the fourth quarter of 2013, we notified Chesapeake that we would be electing to take in kind the anticipated natural gas production from most of the wells operated by Chesapeake effective January 1, 2014. In addition, in December 2013, we entered into a five-year natural gas gathering agreement effective January 1, 2014 for this anticipated natural gas production. This agreement has no firm transportation commitments and no natural gas volume commitments. We believe that taking our natural gas production in kind and transporting through this gathering agreement will improve our natural gas price realizations and reduce marketing and transportation fees and other costs associated with this natural gas production by an average of approximately $0.70 or more per MMBtu. 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." Our estimated capital expenditure budget for 2014 is $440 million, and 97% is expected to be directed towards oil and liquids-rich opportunities. Development of our Eagle Ford shale assets will continue to be the primary driver of our growth in 2014 and approximately $318 million, or 72%, of our estimated 2014 capital expenditures will be directed to increasing our oil production and oil reserves in South Texas. Approximately $109 million, or 25%, of our 2014 estimated capital expenditures will be allocated to further exploration of our growing leasehold position in the Permian Basin. The objective of our Permian Basin drilling program in 2014 is to further evaluate and delineate our acreage, both geographically and geologically, in order to better define an expanded development plan for this acreage in 2015 and beyond. Although we do not plan to drill any operated Haynesville shale natural gas wells during 2014, approximately $12 million, or 3%, of our 2014 estimated capital expenditures will be allocated to participation in non-operated Haynesville shale wells in Northwest Louisiana. We believe that we should be able to fund our 2014 drilling program through operating cash flows and borrowings under our Credit Agreement. We anticipate that our borrowing capacity will continue to increase during 2014 as a result of the addition of proved reserves resulting from our drilling activities, particularly in the Eagle Ford shale and the Permian Basin. While we have budgeted approximately $440 million for 2014, the aggregate amount of capital we expend may fluctuate materially based on market conditions, the actual costs to drill scheduled wells, wells drilled on properties we do not operate, our drilling results, other opportunities that may become available to us and our ability to obtain capital.


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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.
The following table summarizes our revenues and production data for the periods
indicated:
                                                             Year Ended December 31,
                                                         2013          2012         2011
Operating Data:
Revenues (in thousands): (1)
Oil                                                   $ 212,833     $ 123,654     $ 14,457
Natural gas                                              56,197        32,344       52,543
Total oil and natural gas revenues                      269,030       155,998       67,000
Realized (loss) gain on derivatives                        (909 )      13,960        7,106
Unrealized (loss) gain on derivatives                    (7,232 )      (4,802 )      5,138
Total revenues                                        $ 260,889     $ 165,156     $ 79,244
Net Production Volumes: (1)
Oil (MBbl)                                                2,133         1,214          154
Natural gas (Bcf)                                          12.9          12.5         14.5
Total oil equivalent (MBOE) (2)                           4,285         3,294        2,573
Average daily production (BOE/d) (2)                     11,740         9,000        7,049
Average Sales Prices:
Oil, with realized derivatives (per Bbl)              $   98.67     $  103.55     $  93.80
Oil, without realized derivatives (per Bbl)           $   99.79     $  101.86     $  93.80
Natural gas, with realized derivatives (per Mcf)      $    4.47     $    3.55     $   4.11
Natural gas, without realized derivatives (per Mcf)   $    4.35     $    2.59     $   3.62


________________


(1) We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with natural gas liquids are included with our natural gas revenues.

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

Year Ended December 31, 2013 as Compared to Year Ended December 31, 2012 Oil and natural gas revenues. Our oil and natural gas revenues increased $113.0 million to $269.0 million, or an increase of 72% for the year ended December 31, 2013, as compared to $156.0 million for the year ended December 31, 2012. This increase in oil and natural gas revenues corresponds with an increase of 30% in our oil and natural gas production to 4.3 million BOE for the year ended December 31, 2013 from 3.3 million BOE for the year ended December 31, 2012. Our oil revenues increased $89.2 million, an increase of 72%, to $212.8 million for the year ended December 31, 2013, as compared to $123.7 million for the year ended December 31, 2012. Our oil production increased 76% to over 2.1 million Bbl of oil, or about 5,843 Bbl of oil per day, as compared to approximately 1.2 million Bbl of oil, or about 3,317 Bbl of oil per day, for the year ended December 31, 2013 due to our drilling operations in the Eagle Ford shale. The increase in our oil revenues in 2013 was mostly attributable to the increase in oil production, but was partially offset by a slightly lower oil price of $99.79 per Bbl realized for the year ended December 31, 2013, as compared to $101.86 per Bbl realized for the year ended December 31, 2012. Our natural gas revenues increased $23.9 million, an increase of 74%, to $56.2 million for the year ended December 31, 2013, as compared to $32.3 million for the year ended December 31, 2012, due to higher prices and increased production. The vast majority of the increase in natural gas revenues, or $22.7 million, resulted from a significantly higher weighted average natural gas price of $4.35 per Mcf realized during the year ended December 31, 2013, as compared to a weighted average natural gas price of $2.59 per Mcf realized during the year ended December 31, 2012. The 3% increase in our natural gas production to approximately 12.9 Bcf for the year ended December 31, 2013, as compared to approximately 12.5 Bcf for the year ended December 31, 2012, resulted in an increase in natural gas revenues of $1.1 million during 2013, as compared to 2012. This slight increase in natural gas production is due to an increase in natural gas production from our Eagle Ford shale wells during 2013, which was sufficient to offset the decline in natural gas production for our Haynesville and Cotton Valley wells in Northwest Louisiana and East Texas.
Realized gain (loss) on derivatives. Our realized net loss on derivatives was approximately $0.9 million for the year ended December 31, 2013, as compared to a realized net gain of approximately $14.0 million for the year ended December 31, 2012. We realized a loss from our oil contracts of approximately $2.4 million for the year ended December 31, 2013 due to oil


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prices in excess of the ceiling price of some of our costless collar contracts and the fixed price of our swap contracts. This loss was partially offset by gains of approximately $0.8 million and $0.7 million on our natural gas and NGL derivatives contracts, respectively, due to the respective commodity prices being below the floor prices of our natural gas costless collars and the fixed prices of our NGL swap contracts. During the year ended December 31, 2012, we realized a gain of approximately $2.0 million, $11.9 million and $21,000 on our oil, natural gas and NGL derivative contracts, respectively. These gains were the result of the respective commodity prices being below the floor and fixed prices of our oil costless collar and swap contracts, natural gas costless collar contracts and NGL swap contracts. We realized an average loss of approximately $1.42 per Bbl hedged on all of our oil costless collar and swap contracts during the year ended December 31, 2013, as compared to an average gain of $1.74 per Bbl hedged for the year ended December 31, 2012. Our oil volumes hedged for the year ended December 31, 2013 were also 44% higher as compared to the year ended December 31, 2012. We realized an average gain of approximately $0.10 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2013, as compared to 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. Our total natural gas volumes hedged for the year ended December 31, 2013 were also 5% higher than the total natural gas volumes hedged for the year ended December 31, 2012.
Unrealized gain (loss) on derivatives. Our unrealized loss on derivatives was approximately $7.2 million for the year ended December 31, 2013, as compared to an unrealized loss of approximately $4.8 million for the year ended December 31, 2012. During the year ended December 31, 2013, the net fair value of our open oil, natural gas and natural gas liquids derivatives contracts decreased to approximately $(2.8) million, from $4.5 million for the year ended December 31, 2012, resulting in an unrealized loss on derivatives of approximately $7.2 million for the year ended December 31, 2013. During the year ended year ended December 31, 2013, the net fair value of our open oil, natural gas and NGL derivative contracts decreased by $5.3 million, $1.6 million and $0.3 million, respectively, due primarily to the increase in the underlying commodities' futures prices as compared to the year ended December 31, 2012. 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 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 . . .

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