UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of
the Securities Exchange Act of 1934
Date of Report (Date of Earliest Event Reported) March 11, 2013
Matador Resources Company
(Exact name of registrant as specified in its charter)
| Texas | 001-35410 | 27-4662601 | ||
| (State or other jurisdiction of incorporation) |
(Commission File Number) |
(IRS Employer Identification No.) |
| 5400 LBJ Freeway, Suite 1500, Dallas, Texas | 75240 | |
| (Address of principal executive offices) | (Zip Code) |
Registrant’s telephone number, including area code: (972) 371-5200
Not Applicable
(Former name or former address, if changed since last report)
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
| ¨ | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
| ¨ | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
| ¨ | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
| ¨ | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
| Item 1.01 | Entry into a Material Definitive Agreement. |
On September 28, 2012, Matador Resources Company (the “Company”), as a guarantor, and MRC Energy Company, its wholly-owned subsidiary, as borrower, entered into an amended and restated senior secured revolving credit agreement (the “Prior Credit Agreement”). For a summary of key terms of the Prior Credit Agreement, see Item 1.01 of the Company’s Current Report on Form 8-K filed on October 4, 2012, which description is incorporated herein by reference. On March 11, 2013, MRC Energy Company, as borrower, entered into an amendment (the “Amendment”) to the Prior Credit Agreement (as amended, the “Credit Agreement”) and the Company reaffirmed its guaranty of MRC Energy Company’s obligations under the Credit Agreement. The Amendment increased the borrowing base from $215 million to $255 million based on the lenders’ review of the Company’s proved oil and natural gas reserves at December 31, 2012. The conforming borrowing base was also increased from $180 million to $220 million. Among other things, the Amendment also provided for the inclusion of Capital One, N.A., BMO Harris Financing, Inc. (Bank of Montreal) and IBERIABANK in the Company’s lending group, joining Royal Bank of Canada, as administrative agent, Comerica Bank, Citibank, N.A., The Bank of Nova Scotia and SunTrust Bank. The Amendment also delayed the first measurement of the current ratio from March 31, 2013 to March 31, 2014.
In the ordinary course of their respective businesses, certain of the lenders or their affiliates have in the past performed, and may in the future from time to time perform, investment banking, advisory, lending and/or commercial banking or other financial services for the Company for which they received, or may receive, customary fees and reimbursement of expenses.
| Item 2.02 | Results of Operations and Financial Condition. |
Attached hereto as Exhibit 99.1 is a press release (the “Press Release”) issued by the Company on March 13, 2013, announcing its financial results for the three month and twelve month periods ended December 31, 2012. The Press Release includes an operational update for the first quarter of 2013. The Press Release is incorporated by reference into this Item 2.02, and the foregoing description of the Press Release is qualified in its entirety by reference to this exhibit.
The information furnished pursuant to this Item 2.02, including Exhibit 99.1, shall not be deemed to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and will not be incorporated by reference into any filing under the Securities Act of 1933, as amended (the “Securities Act”), unless specifically identified therein as being incorporated therein by reference.
In the Press Release, the Company has included as “non-GAAP financial measures,” as defined in Item 10 of Regulation S-K of the Exchange Act, (i) earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, certain other non-cash items and non-cash stock-based compensation expense, including stock option and grant expense and restricted stock and restricted stock unit expense, and net gain or loss on asset sales and inventory impairment (“Adjusted EBITDA”) and (ii) present value discounted at 10% (pre-tax) of estimated total proved reserves (“PV-10”). In the Press Release, the Company has provided reconciliations of the non-GAAP financial measures to the most directly comparable financial measures calculated and presented in accordance with generally-accepted accounting principles (“GAAP”) in the United States. In addition, in the Press Release, the Company has provided the reasons why the Company believes those non-GAAP financial measures provide useful information to investors.
| Item 2.03 | Creation of a Direct Financial Obligation or an Obligation under an Off-Balance Sheet Arrangement of a Registrant. |
Item 1.01 above is incorporated herein by reference.
| Item 7.01 | Regulation FD Disclosure. |
Item 2.02 above is incorporated herein by reference.
The information furnished pursuant to this Item 7.01, including Exhibit 99.1, shall not be deemed to be “filed” for the purposes of Section 18 of the Exchange Act and will not be incorporated by reference into any filing under the Securities Act unless specifically identified therein as being incorporated therein by reference.
| Item 9.01 | Financial Statements and Exhibits. |
(d) Exhibits
| Exhibit |
Description of Exhibit | |
| 99.1 | Press Release, dated March 13, 2013. |
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| MATADOR RESOURCES COMPANY | ||||
| Date: March 13, 2013 | By: | /s/ David E. Lancaster | ||
| Name: David E. Lancaster | ||||
| Title: Executive Vice President | ||||
Exhibit Index
| Exhibit |
Description of Exhibit | |
| 99.1 | Press Release, dated March 13, 2013. |
Exhibit 99.1
MATADOR RESOURCES COMPANY REPORTS FOURTH QUARTER AND FULL YEAR 2012 RESULTS
AND PROVIDES OPERATIONAL UPDATE
DALLAS, Texas, March 13, 2013 — Matador Resources Company (NYSE: MTDR) (“Matador” or the “Company”), an independent energy company currently focused on the oil and liquids rich portion of the Eagle Ford shale play in South Texas, today reported financial and operating results for the three months and year ended December 31, 2012. Headlines, all of which represent record results for the Company, include the following:
| • | Oil production of 1,214,000 Bbl for the year ended December 31, 2012, a year-over-year increase of almost eight-fold from 154,000 Bbl produced in 2011. |
| • | Average daily oil equivalent production of 9,000 BOE per day for the year ended December 31, 2012, consisting of 3,317 Bbl of oil per day and 34.1 MMcf of natural gas per day, a year-over-year BOE increase of 28% from 7,049 BOE per day, consisting of 422 Bbl of oil per day and 39.8 MMcf of natural gas per day, produced in 2011. |
| • | Total realized revenues of $170.0 million in 2012, including $14.0 million in realized gain on derivatives, a year-over-year increase of 129% from total realized revenues of $74.1 million, including $7.1 million in realized gain on derivatives, reported for the year ended December 31, 2011. |
| • | Oil and natural gas revenues of $156.0 million in 2012, a year-over-year increase of 133% from $67.0 million reported for the year ended December 31, 2011. |
| • | Adjusted EBITDA of $115.9 million for the year ended December 31, 2012, a year-over-year increase of 132% from $49.9 million reported for the year ended December 31, 2011. |
| • | Oil production of 426,000 Bbl for the fourth quarter of 2012, a sequential quarterly increase of 41% from 303,000 Bbl produced in the third quarter of 2012 and a ten-fold year-over-year increase from 41,000 Bbl produced in the fourth quarter of 2011. |
| • | Adjusted EBITDA of $38.0 million for the fourth quarter of 2012, a sequential quarterly increase of 33% from $28.6 million reported in the third quarter of 2012 and a three-fold year-over-year increase from $12.4 million reported during the fourth quarter of 2011. |
Year End 2012 Financial Results
Joseph Wm. Foran, Matador’s Chairman, President and CEO, commented, “We are very pleased with our 2012 operating and financial results and our early 2013 results which reflect the execution of our strategy to significantly increase our oil production and reserves through our drilling operations in the Eagle Ford shale. During 2012, we grew our oil production almost eight-fold to just over 1.2 million Bbl from just 154,000 Bbl in 2011 and 33,000 Bbl in 2010. Oil production in 2012 constituted 37% of our total production by volume as compared to only 6% in 2011 and 2% in 2010, and oil revenues constituted 79% of our total oil and natural gas revenues as compared to only 22% in 2011. Our proved oil reserves increased 176% from 3.8 million Bbl (12% by volume) at December 31, 2011 to 10.5 million Bbl (44% by volume) at December 31, 2012. Adjusted EBITDA grew to $115.9 million in 2012, an increase of 132% from $49.9 million in 2011. Our total oil and natural gas production, total oil production, proved oil reserves, oil and natural gas revenues, total realized revenues and Adjusted
EBITDA at and for the year ended December 31, 2012 were all the best in our Company’s history. Throughout 2012, we reduced our drilling and completion costs and steadily improved our drilling, completion and production techniques on our Eagle Ford wells, which we believe will lead to improved rates of return and long-term value for our shareholders going forward. In fact, our December 2012 average oil production rate was a little more than 5,800 Bbl of oil per day, about 10% above the midpoint of our exit rate guidance.
“Matador enjoyed a particularly strong fourth quarter. During the fourth quarter of 2012, our average daily oil equivalent production was approximately 10,400 BOE per day, including 4,630 Bbl of oil per day and 34.5 MMcf of natural gas per day, a sequential quarterly increase of 40% in our average daily oil production from approximately 3,300 Bbl of oil per day in the third quarter of 2012. Oil production in the fourth quarter of 2012 comprised 45% of our total production volume and 81% of our total oil and natural gas revenues. Adjusted EBITDA in the fourth quarter of 2012 was $38.0 million, a sequential increase of 33% from $28.6 million in the third quarter of 2012 and a three-fold year-over-year increase from $12.4 million in the fourth quarter of 2011.
“Matador is also off to a strong start in 2013. Our average daily production for the first sixty days of 2013 is running ahead of our expectations, averaging approximately 5,000 Bbl of oil per day and 34 MMcf of natural gas per day compared to our December 6, 2012 Analyst Day guidance of approximately 4,000 Bbl of oil per day and 31 MMcf of natural gas per day expected for the first quarter of the year. We have been particularly encouraged by the production performance of a number of our recent wells and believe these results reflect the progress we continue to make in the design of our fracture treatments and the implementation of ‘zipper’ or simultaneous fracs as well as our practice to flow back wells on smaller chokes following stimulation. These results have been achieved while we continue to follow our drilling schedule and operational plans, including drilling multiple wells from the same pad prior to completing them and shutting in producing wells while newly drilled offset wells are hydraulically fractured. In addition, we believe our artificial lift program is resulting in higher volumes of oil being produced from existing wells where artificial lift has been installed.
“We are also pleased to report that on March 11, 2013 we closed an amendment to our credit agreement which increased our bank group from five banks to eight banks and increased our borrowing base to $255 million, based on our lenders’ review of our December 31, 2012 oil and natural gas reserves, an increase of $40 million from the previous borrowing base of $215 million. We will use this additional borrowing capacity, along with our cash flows from operations, to continue to fund our ongoing operations. We anticipate further upward redeterminations to our borrowing base throughout the year.
“Finally, we wish to reaffirm our 2013 guidance metrics previously announced at Analyst Day on December 6, 2012. Although we are encouraged by current results, we recognize this year’s production may still be uneven and subject to various changes in operating conditions.”
2
Production and Revenues
Year Ended December 31, 2012 Compared to Year Ended December 31, 2011
Oil production in 2012 increased almost eight-fold to approximately 1,214,000 Bbl of oil, or about 3,317 Bbl of oil per day, as compared to approximately 154,000 Bbl of oil, or about 422 Bbl of oil per day, in 2011. This increase in oil production is a direct result of the Company’s ongoing drilling operations in the Eagle Ford shale. Average daily oil equivalent production increased to approximately 9,000 BOE per day (37% oil by volume) for the year ended December 31, 2012 from approximately 7,049 BOE per day (6% oil by volume) for the year ended December 31, 2011.
Total realized revenues, including realized gain on derivatives, increased 129% to $170.0 million for the year ended December 31, 2012 as compared to $74.1 million for the year ended December 31, 2011. Oil and natural gas revenues increased 133% to $156.0 million for the year ended December 31, 2012 from $67.0 million during the comparable period in 2011. 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. Natural gas revenues decreased about 38% to $32.3 million for the year ended December 31, 2012 from $52.5 million for the year ended December 31, 2011.
Adjusted EBITDA
Adjusted EBITDA, a non-GAAP financial measure, increased 132% to $115.9 million for the year ended December 31, 2012 as compared to $49.9 million for the year ended December 31, 2011. Adjusted EBITDA increased over three-fold from $12.4 million in the fourth quarter of 2011 to $38.0 million during the fourth quarter of 2012 and increased 33% sequentially from $28.6 million during the third quarter of 2012. For a definition of Adjusted EBITDA and a reconciliation of net income (GAAP) and net cash provided by operating activities (GAAP) to Adjusted EBITDA (non-GAAP), please see “Supplemental Non-GAAP Financial Measures” below.
Proved Reserves and PV-10
Proved oil reserves at December 31, 2012 increased 176% to 10.5 million Bbl from 3.8 million Bbl at December 31, 2011. At December 31, 2012, total proved oil and natural gas reserves were approximately 23.8 million BOE, including 10.5 million Bbl of oil (44% oil by volume) and 80.0 Bcf of natural gas, with a present value of estimated future net cash flows discounted at 10%, or PV-10, of $423.2 million (Standardized Measure of $394.6 million). This compares to total proved oil and natural gas reserves at December 31, 2011 of approximately 32.2 million BOE, including approximately 3.8 million Bbl of oil (12% oil by volume) and 170.4 Bcf of natural gas, with a PV-10 of $248.7 million (Standardized Measure of $215.5 million). As a result of substantially lower natural gas prices in 2012, the Company previously removed 97.8 Bcf (or approximately 16.3 million BOE) in proved undeveloped Haynesville shale natural gas reserves from its total proved reserves at June 30, 2012, and these proved reserves are likewise not included in the Company’s estimated total proved reserves at December 31, 2012. As long as the leasehold acreage associated with these previously classified proved undeveloped reserves is held by production from existing wells, however, these natural gas volumes remain available to be developed at a future time should natural gas prices improve. The reserves estimates for all periods presented were prepared by the Company’s engineering staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), please see “Supplemental Non-GAAP Financial Measures” below.
3
Net (Loss) Income
For the year ended December 31, 2012, Matador reported a net loss of approximately $33.3 million and a loss of $(0.62) per class A common share and $(0.35) per Class B common share compared to a net loss of approximately $10.3 million and a loss of $(0.25) per Class A common share and earnings of $0.02 per Class B common share for the year ended December 31, 2011. All Class B shares were converted to Class A shares upon completion of the Company’s initial public offering in February 2012; there was only one class of common shares outstanding at December 31, 2012. For the year ended December 31, 2012, the net loss was entirely attributable to total full-cost ceiling impairment charges of $63.5 million during the year. These impairment charges resulted primarily from the decline in the value of the Company’s natural gas reserves during 2012 as a result of significantly lower natural gas prices and the removal of approximately 97.8 Bcf (or approximately 16.3 million BOE) in proved undeveloped natural gas reserves in the Haynesville shale.
Three Months Ended December 31, 2012 Compared to Three Months Ended December 31, 2011
Oil production increased over ten-fold to 426,000 Bbl of oil, or about 4,630 Bbl of oil per day, during the fourth quarter of 2012 as compared to approximately 41,000 Bbl of oil, or 448 Bbl of oil per day, in the fourth quarter of 2011. This increase in oil production is a direct result of ongoing drilling operations in the Eagle Ford shale. Average daily oil equivalent production increased to approximately 10,400 BOE per day (45% oil by volume) in the fourth quarter of 2012 as compared to 6,950 BOE per day (6% oil by volume) during the fourth quarter of 2011.
Total realized revenues, including realized gain on derivatives, increased three-fold to $55.6 million for the three months ended December 31, 2012 as compared to $17.9 million for the three months ended December 31, 2011. Oil and natural gas revenues in the fourth quarter of 2012 increased 3.5-fold to $52.7 million as compared to $15.0 million during the fourth quarter of 2011. This increase in oil and natural gas revenues reflects an increase in oil revenues of $38.6 million coupled with a decrease in natural gas revenues of $0.9 million between the respective periods. Oil revenues for the three months ended December 31, 2012 increased over ten-fold to $42.6 million as compared to $4.0 million in oil revenues for the three months ended December 31, 2011, reflecting the large increase in average daily oil production between the respective periods.
Sequential Operating and Financial Results
| • | Oil production increased 41% from approximately 303,000 Bbl, or 3,291 Bbl of oil per day, in the third quarter of 2012, to approximately 426,000 Bbl, or 4,630 Bbl of oil per day, in the fourth quarter of 2012. |
| • | Total proved oil and natural gas reserves increased approximately 14% from 20.9 million BOE at September 30, 2012 to 23.8 million BOE at December 31, 2012. |
4
| • | Oil and natural gas revenues increased 39% from $38.0 million in the third quarter of 2012 to $52.7 million in the fourth quarter of 2012. |
| • | Adjusted EBITDA increased 33% from $28.6 million in the third quarter of 2012 to $38.0 million in the fourth quarter of 2012. |
Operating Expenses Update
Production Taxes and Marketing
Production taxes and marketing expenses increased to $11.7 million (or $3.54 per BOE) for the year ended December 31, 2012 from $6.3 million (or $2.44 per BOE) for the year ended December 31, 2011. The increase in production taxes and marketing expenses reflects the increase in total oil and natural gas revenues by 133% during the year ended December 31, 2012 as compared to the year ended December 31, 2011. The majority of this increase was attributable to additional production taxes associated with the large increase in oil production and oil revenues resulting from drilling operations in the Eagle Ford shale in South Texas.
Lease Operating Expenses (“LOE”)
Lease operating expenses increased to $28.2 million (or $8.56 per BOE) for the year ended December 31, 2012 from $7.2 million (or $2.82 per BOE) for the year ended December 31, 2011. The increase in lease operating expenses was primarily attributable to increased costs associated with operating high volume oil production resulting from drilling operations in the Eagle Ford shale in 2012, as compared to the lower lease operating expenses associated with operating primarily dry gas production from the Haynesville shale and Cotton Valley in 2011. Oil production comprised 37% of total production by volume during the year ended December 31, 2012, as compared to only 6% of total production by volume during the same period in 2011. During 2012, the Company initiated oil and natural gas production from a number of new properties where production facilities and pipelines were being installed and tested at the same time. While these new facilities were being completed, oil and natural gas were produced through rental test equipment monitored by 24-hour contract personnel, resulting in higher operating costs from these properties during the year ended December 31, 2012 than anticipated going forward. Approximately one-third of the Company’s total lease operating expenses in 2012 was attributable to these extended flowback operations. The Company has only one property where these temporary production facilities are still being used and anticipates permanent facilities will be operational on that property by March 15, 2013.
Depletion, depreciation and amortization (“DD&A”)
Depletion, depreciation and amortization expenses increased to $80.5 million (or $24.43 per BOE) for the year ended December 31, 2012 from $31.8 million (or $12.34 per BOE) for the year ended December 31, 2011. This increase in depletion, depreciation and amortization expense was primarily attributable to the decrease in the Company’s total proved oil and natural gas reserves to 23.8 million BOE at December 31, 2012 as compared to 32.2 million BOE at December 31, 2011. As noted previously, as a result of substantially lower natural gas prices during 2012, the Company removed 97.8 Bcf (or
5
approximately 16.3 million BOE) in proved undeveloped Haynesville shale natural gas reserves from its total proved reserves during 2012. The increase in depletion, depreciation and amortization expense was also partially attributable to the increase of approximately 28% in the Company’s oil and natural gas production to approximately 3.3 million BOE for the year ended December 31, 2012 as compared to approximately 2.6 million BOE for the year ended December 31, 2011, as well as to the higher drilling and completion costs on a per BOE basis associated with oil reserves added in the Eagle Ford shale in South Texas as compared with the Company’s Haynesville shale natural gas assets in Northwest Louisiana.
General and administrative (“G&A”)
General and administrative expenses increased to $14.5 million for the year ended December 31, 2012 as compared to $13.4 million for the year ended December 31, 2011. On a unit-of-production basis, however, general and administrative expenses decreased by 15% to $4.42 per BOE for the year ended December 31, 2012 as compared to $5.21 per BOE for the year ended December 31, 2011. The increase in general and administrative expenses was attributable to increased compensation, accounting, legal and other administrative expenses, most of which was associated with becoming a public company in February 2012, partially offset by a net decrease in non-cash stock compensation expense of $2.3 million for the year ended December 31, 2012 as compared to the year ended December 31, 2011.
2013 Operations Update
Matador is pleased to report that its average daily production for the first sixty days of 2013 is running ahead of its expectations, averaging approximately 5,000 Bbl of oil per day and 34 MMcf of natural gas per day compared to production guidance of approximately 4,000 Bbl of oil per day and 31 MMcf of natural gas per day as announced at Analyst Day on December 6, 2012. As previously reported in its January 7, 2013 operations update, Matador averaged approximately 5,800 Bbl of oil per day during the month of December 2012 or about 10% above the midpoint of its 2012 projected exit rate of 5,000 to 5,500 Bbl of oil per day. The Company attributes its December 2012 and early 2013 production performance to better-than-expected results from several recent wells drilled and placed on production during the past three months in both the eastern and western portions of its Eagle Ford acreage. These results have been achieved while the Company continues to follow its drilling schedule and operational plans, including flowing back wells on smaller choke sizes to better manage bottomhole pressure and shutting in producing wells while newly drilled offset wells are hydraulically fractured. Shutting in these wells has resulted in approximately 10% of production capacity being shut-in at any given time. Matador has collected and analyzed bottomhole pressure data on several recent shut-in wells in an effort to optimize and reduce the number of wells shut-in and the duration of the shut-in periods for any given hydraulic fracturing operation. The Company believes the results of this analysis will help to minimize the impact of these shut-in periods on its overall production volumes in 2013.
As of March 13, 2013, Matador is executing its 2013 drilling and well operations plans as outlined in its Analyst Day presentation on December 6, 2012. During the first quarter of 2013 to date, the Company completed and began producing oil and natural gas from 4 gross/4.0 net Eagle Ford shale wells, all in LaSalle County. Matador is currently drilling three wells from a single pad on its Cowey lease in DeWitt
6
County and three wells from a single pad on its Martin Ranch lease in LaSalle County. All three wells on each pad will be completed and hydraulically fractured at the same time once drilling operations are concluded. As a result, none of these wells are anticipated to be placed on production until the second quarter of 2013, which may cause second quarter production to be uneven.
At March 13, 2013, almost all of the Company’s drilling activities were focused on the Eagle Ford shale. The Company expects to allocate approximately 82% of its estimated 2013 capital expenditures budget of $310 million to its operations in South Texas and approximately 98% of its budget to opportunities prospective for oil and liquids production. Although the Company has no immediate plans to do so, Matador would consider increasing its 2013 capital expenditures for special drilling, acreage or acquisition opportunities should they arise.
At March 13, 2013, Matador had two contracted drilling rigs operating in South Texas: one in LaSalle County and one in DeWitt County. The Company plans to run two rigs in the Eagle Ford play throughout most of 2013, except for a brief period starting in the second quarter when it plans to drill three test wells on its acreage prospective for the Wolfcamp and Bone Spring plays in Loving County, Texas and Lea County, New Mexico. At this time, the Company does not plan to drill any operated Haynesville shale wells during 2013.
During the year ended December 31, 2012, Matador’s operations were primarily focused on the exploration and development of its Eagle Ford shale properties in South Texas. Matador 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. The Company 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, Matador also participated in 28 gross/1.1 net non-operated Haynesville shale wells. Matador and its partners also re-entered and drilled an approximately 2,500-ft horizontal lateral in the Meade Peak shale from the previously suspended Crawford Federal #1 vertical wellbore in Southwest Wyoming. The Company plans to complete this well during the third quarter of 2013. Matador’s capital expenditures in 2012 totaled approximately $335 million, about 7% higher than its projected expenditures of $313 million, with the additional capital being used primarily for production facilities and additional drilling opportunities in the Eagle Ford. Approximately 90% of the Company’s 2012 capital expenditures were directed to the Eagle Ford shale.
Liquidity Update
On March 11, 2013, the Company closed an amendment to its senior secured revolving credit agreement. As part of the amendment, the borrowing base was increased to $255 million, based on the lenders’ review of the Company’s proved oil and natural gas reserves at December 31, 2012, an increase of $40 million from its previous borrowing base of $215 million based on the lenders’ review of the Company’s proved oil and natural gas reserves at September 30, 2012. The amendment also provided for the addition of Capital One, N.A., BMO Harris Financing, Inc. (Bank of Montreal) and IBERIABANK to the Company’s lending group, which already includes Royal Bank of Canada, as administrative agent, Comerica Bank, Citibank, N.A., The Bank of Nova Scotia and SunTrust Bank. At March 13, 2013, Matador had $180 million in borrowings and $1.3 million in letters of credit outstanding under its credit agreement.
7
Hedging Positions
From time to time, Matador uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices and to protect its cash flows and borrowing capacity. At March 13, 2013, Matador had the following hedges in place, primarily in the form of costless collars and swaps, for the remainder of 2013.
| • | Approximately 1.3 million Bbl of oil at a weighted average floor price of $88/Bbl and a weighted average ceiling price of $107/Bbl. |
| • | Approximately 6.0 Bcf of natural gas at a weighted average floor price of $3.23/MMBtu and a weighted average ceiling price of $4.60/MMBtu. |
| • | Approximately 7.4 million gallons of natural gas liquids at a weighted average price of $1.25/gallon. |
At March 13, 2013, Matador also had the following hedges in place, primarily in the form of costless collars and swaps, for 2014.
| • | Approximately 1.4 million Bbl of oil at a weighted average floor price of $88/Bbl and a weighted average ceiling price of $99/Bbl. |
| • | Approximately 6.0 Bcf of natural gas at a weighted average floor price of $3.20/MMBtu and a weighted average ceiling price of $5.27/MMBtu. |
| • | Approximately 2.3 million gallons of natural gas liquids at a weighted average price of $1.74/gallon. |
2013 Guidance Affirmation
Matador affirms the guidance metrics for 2013 previously announced at its Analyst Day presentation on December 6, 2012, including (1) estimated capital spending of $310 million, (2) estimated total oil production of 1.6 to 1.8 million Bbl, (3) estimated total natural gas production of 11.0 to 12.0 billion cubic feet, (4) estimated oil and natural gas revenues of $200 to $220 million and (5) estimated Adjusted EBITDA of $140 to $160 million.
Conference Call Information and Investor Presentation
The Company will host a conference call on Thursday, March 14, 2013, at 9:00 a.m. Central Time to discuss its fourth quarter and year end 2012 financial and operational results. To access the conference call, domestic participants should dial (866) 383-8119 and international participants should dial (617) 597-5344. The participant passcode is 89728201. The conference call will also be available through the Company’s website at www.matadorresources.com on the Presentations & Webcasts page under the Investors tab. The replay for the event will also be available on the Company’s website at www.matadorresources.com through Thursday, March 28, 2013. To access the replay, domestic participants should dial (888) 286-8010 and international participants should dial (617) 801-6888. The participant passcode is 77646485. In addition, the Company’s Investor Presentation is available on the Presentations & Webcasts page under the Investors tab of the Company’s website at www.matadorresources.com.
8
About Matador Resources Company
Matador is an independent energy company 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. Its current operations are focused primarily on the oil and liquids rich portion of the Eagle Ford shale play in South Texas and the Haynesville shale play in Northwest Louisiana.
For more information, visit Matador Resources Company at www.matadorresources.com.
Forward-Looking Statements
This press release includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. “Forward-looking statements” are statements related to future, not past, events. Forward-looking statements are based on current expectations and include any statement that does not directly relate to a current or historical fact. In this context, forward-looking statements often address expected future business and financial performance, and often contain words such as “could,” “believe,” “would,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “should,” “continue,” “plan,” “predict,” “potential,” “project” and similar expressions that are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Actual results and future events could differ materially from those anticipated in such statements, and such forward-looking statements may not prove to be accurate. These forward-looking statements involve certain risks and uncertainties, including, but not limited to, the following risks related to financial and operational performance: general economic conditions; the Company’s ability to execute its business plan, including whether its drilling program is successful; changes in oil, natural gas and natural gas liquids prices and the demand for oil, natural gas and natural gas liquids; ability to replace reserves and efficiently develop current reserves; costs of operations; delays and other difficulties related to producing oil, natural gas and natural gas liquids; ability to make acquisitions on economically acceptable terms; availability of sufficient capital to execute the Company’s business plan, including from future cash flows, increases in borrowing base and otherwise; weather and environmental concerns; and other important factors which could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. For further discussions of risks and uncertainties, you should refer to Matador’s SEC filings, including the “Risk Factors” section of Matador’s Annual Report on Form 10-K for the year ended December 31, 2011. Matador undertakes no obligation and does not intend to update these forward-looking statements to reflect events or circumstances occurring after this press release, except as required by law. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this press release. All forward-looking statements are qualified in their entirety by this cautionary statement.
9
Contact Information
Mac Schmitz
Investor Relations
(972) 371-5225
mschmitz@matadorresources.com
10
Matador Resources Company and Subsidiaries
CONSOLIDATED BALANCE SHEETS – UNAUDITED
| (In thousands, except par value and share data) | December 31, | |||||||
| 2012 | 2011 | |||||||
| ASSETS |
||||||||
| Current assets |
||||||||
| Cash |
$ | 2,095 | $ | 10,284 | ||||
| Certificates of deposit |
230 | 1,335 | ||||||
| Accounts receivable |
||||||||
| Oil and natural gas revenues |
24,422 | 9,237 | ||||||
| Joint interest billings |
4,118 | 2,488 | ||||||
| Other |
974 | 1,447 | ||||||
| Derivative instruments |
4,378 | 8,989 | ||||||
| Lease and well equipment inventory |
877 | 1,343 | ||||||
| Prepaid expenses |
1,103 | 1,153 | ||||||
|
|
|
|
|
|||||
| Total current assets |
38,197 | 36,276 | ||||||
| Property and equipment, at cost |
||||||||
| Oil and natural gas properties, full-cost method |
||||||||
| Evaluated |
763,527 | 423,945 | ||||||
| Unproved and unevaluated |
149,675 | 162,598 | ||||||
| Other property and equipment |
27,258 | 18,764 | ||||||
| Less accumulated depletion, depreciation and amortization |
(349,370 | ) | (205,442 | ) | ||||
|
|
|
|
|
|||||
| Net property and equipment |
591,090 | 399,865 | ||||||
| Other assets |
||||||||
| Derivative instruments |
771 | 847 | ||||||
| Deferred income taxes |
411 | 1,594 | ||||||
| Other assets |
1,560 | 887 | ||||||
|
|
|
|
|
|||||
| Total other assets |
2,742 | 3,328 | ||||||
|
|
|
|
|
|||||
| Total assets |
$ | 632,029 | $ | 439,469 | ||||
|
|
|
|
|
|||||
| LIABILITIES AND SHAREHOLDERS’ EQUITY |
||||||||
| Current liabilities |
||||||||
| Accounts payable |
$ | 28,120 | $ | 18,841 | ||||
| Accrued liabilities |
59,179 | 25,439 | ||||||
| Royalties payable |
6,541 | 1,855 | ||||||
| Borrowings under Credit Agreement |
— | 25,000 | ||||||
| Derivative instruments |
670 | 171 | ||||||
| Advances from joint interest owners |
1,515 | — | ||||||
| Deferred income taxes |
411 | 3,024 | ||||||
| Dividends payable - Class B |
— | 69 | ||||||
| Other current liabilities |
56 | 177 | ||||||
|
|
|
|
|
|||||
| Total current liabilities |
96,492 | 74,576 | ||||||
| Long-term liabilities |
||||||||
| Borrowings under Credit Agreement |
150,000 | 88,000 | ||||||
| Asset retirement obligations |
5,109 | 3,935 | ||||||
| Derivative instruments |
— | 383 | ||||||
| Other long-term liabilities |
1,324 | 1,060 | ||||||
|
|
|
|
|
|||||
| Total long-term liabilities |
156,433 | 93,378 | ||||||
| Shareholders’ equity |
||||||||
| Common stock—Class A, $0.01 par value, 80,000,000 shares authorized; 56,778,718 and 42,916,668 shares issued; and 55,577,667 and 41,737,493 shares outstanding, respectively |
568 | 429 | ||||||
| Common stock—Class B, $0.01 par value, zero and 2,000,000 shares authorized; zero and 1,030,700 shares issued and outstanding, respectively |
— | 10 | ||||||
| Additional paid-in capital |
404,311 | 263,562 | ||||||
| Retained (deficit) earnings |
(15,010 | ) | 18,279 | |||||
| Treasury stock, at cost, 1,201,051 and 1,179,175 shares, respectively |
(10,765 | ) | (10,765 | ) | ||||
|
|
|
|
|
|||||
| Total shareholders’ equity |
379,104 | 271,515 | ||||||
|
|
|
|
|
|||||
| Total liabilities and shareholders’ equity |
$ | 632,029 | $ | 439,469 | ||||
|
|
|
|
|
|||||
11
Matador Resources Company and Subsidiaries
CONSOLIDATED STATEMENTS OF OPERATIONS – UNAUDITED
| (In thousands, except per share data) | Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| Revenues |
||||||||||||||||
| Oil and natural gas revenues |
$ | 52,748 | $ | 14,991 | $ | 155,998 | $ | 67,000 | ||||||||
| Realized gain on derivatives |
2,813 | 2,869 | 13,960 | 7,106 | ||||||||||||
| Unrealized (loss) gain on derivatives |
(3,653 | ) | 3,604 | (4,802 | ) | 5,138 | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total revenues |
51,908 | 21,464 | 165,156 | 79,244 | ||||||||||||
| Expenses |
||||||||||||||||
| Production taxes and marketing |
4,067 | 1,477 | 11,672 | 6,278 | ||||||||||||
| Lease operating |
10,673 | 1,606 | 28,184 | 7,244 | ||||||||||||
| Depletion, depreciation and amortization |
27,655 | 9,175 | 80,454 | 31,754 | ||||||||||||
| Accretion of asset retirement obligations |
86 | 51 | 256 | 209 | ||||||||||||
| Full-cost ceiling impairment |
26,674 | — | 63,475 | 35,673 | ||||||||||||
| General and administrative |
3,222 | 3,475 | 14,543 | 13,394 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total expenses |
72,377 | 15,784 | 198,584 | 94,552 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Operating (loss) income |
(20,469 | ) | 5,680 | (33,428 | ) | (15,308 | ) | |||||||||
| Other income (expense) |
||||||||||||||||
| Net loss on asset sales and inventory impairment |
(425 | ) | (154 | ) | (485 | ) | (154 | ) | ||||||||
| Interest expense |
(549 | ) | (222 | ) | (1,002 | ) | (683 | ) | ||||||||
| Interest and other income |
67 | 67 | 224 | 315 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total other (expense) income |
(907 | ) | (309 | ) | (1,263 | ) | (522 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| (Loss) income before income taxes |
(21,376 | ) | 5,371 | (34,691 | ) | (15,830 | ) | |||||||||
| Income tax (benefit) provision |
||||||||||||||||
| Current |
(188 | ) | — | — | (46 | ) | ||||||||||
| Deferred |
— | 1,430 | (1,430 | ) | (5,475 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total income tax (benefit) provision |
(188 | ) | 1,430 | (1,430 | ) | (5,521 | ) | |||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net (loss) income |
$ | (21,188 | ) | $ | 3,941 | $ | (33,261 | ) | $ | (10,309 | ) | |||||
|
|
|
|
|
|
|
|
|
|||||||||
| Earnings (loss) per common share |
||||||||||||||||
| Basic |
||||||||||||||||
| Class A |
$ | (0.38 | ) | $ | 0.09 | $ | (0.62 | ) | $ | (0.25 | ) | |||||
|
|
|
|
|
|
|
|
|
|||||||||
| Class B |
$ | — | $ | 0.16 | $ | (0.35 | ) | $ | 0.02 | |||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Diluted |
||||||||||||||||
| Class A |
$ | (0.38 | ) | $ | 0.09 | $ | (0.62 | ) | $ | (0.25 | ) | |||||
|
|
|
|
|
|
|
|
|
|||||||||
| Class B |
$ | — | $ | 0.16 | $ | (0.35 | ) | $ | 0.02 | |||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Weighted average common shares outstanding |
||||||||||||||||
| Basic |
||||||||||||||||
| Class A |
55,272 | 41,735 | 53,852 | 41,687 | ||||||||||||
| Class B |
— | 1,031 | 105 | 1,031 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total |
55,272 | 42,766 | 53,957 | 42,718 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Diluted |
||||||||||||||||
| Class A |
55,272 | 41,896 | 53,852 | 41,687 | ||||||||||||
| Class B |
— | 1,031 | 105 | 1,031 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total |
55,272 | 42,927 | 53,957 | 42,718 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
12
Matador Resources Company and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS – UNAUDITED
| (In thousands) | Year Ended December 31, | |||||||
| 2012 | 2011 | |||||||
| Operating activities |
||||||||
| Net loss |
$ | (33,261 | ) | $ | (10,309 | ) | ||
| Adjustments to reconcile net loss to net cash provided by operating activities |
||||||||
| Unrealized loss (gain) on derivatives |
4,802 | (5,138 | ) | |||||
| Depletion, depreciation and amortization |
80,454 | 31,754 | ||||||
| Accretion of asset retirement obligations |
256 | 209 | ||||||
| Full-cost ceiling impairment |
63,475 | 35,673 | ||||||
| Stock option and grant expense |
(589 | ) | 2,362 | |||||
| Restricted stock grants |
729 | 44 | ||||||
| Deferred income tax benefit |
(1,430 | ) | (5,476 | ) | ||||
| Loss on asset sales and inventory impairment |
485 | 154 | ||||||
| Changes in operating assets and liabilities |
||||||||
| Accounts receivable |
(16,342 | ) | (1,523 | ) | ||||
| Lease and well equipment inventory |
50 | 22 | ||||||
| Prepaid expenses |
50 | 650 | ||||||
| Other assets |
(673 | ) | (814 | ) | ||||
| Accounts payable, accrued liabilities and other current liabilities |
19,740 | 13,497 | ||||||
| Royalties payable |
4,685 | 873 | ||||||
| Advances from joint interest owners |
1,515 | (723 | ) | |||||
| Other long-term liabilities |
282 | 613 | ||||||
|
|
|
|
|
|||||
| Net cash provided by operating activities |
124,228 | 61,868 | ||||||
| Investing activities |
||||||||
| Oil and natural gas properties capital expenditures |
(300,689 | ) | (156,431 | ) | ||||
| Expenditures for other property and equipment |
(7,332 | ) | (4,671 | ) | ||||
| Purchases of certificates of deposit |
(496 | ) | (4,298 | ) | ||||
| Sales of certificates of deposit |
1,601 | 5,312 | ||||||
|
|
|
|
|
|||||
| Net cash used in investing activities |
(306,916 | ) | (160,088 | ) | ||||
| Financing activities |
||||||||
| Repayments of borrowings under Credit Agreement |
(123,000 | ) | (103,000 | ) | ||||
| Borrowings under Credit Agreement |
160,000 | 191,000 | ||||||
| Proceeds from issuance of common stock |
146,510 | 592 | ||||||
| Swing sale profit contribution |
24 | — | ||||||
| Cost to issue equity |
(11,599 | ) | (1,710 | ) | ||||
| Proceeds from stock options exercised |
2,660 | 837 | ||||||
| Payment of dividends—Class B |
(96 | ) | (275 | ) | ||||
|
|
|
|
|
|||||
| Net cash provided by financing activities |
174,499 | 87,444 | ||||||
|
|
|
|
|
|||||
| Decrease in cash and cash equivalents |
(8,189 | ) | (10,776 | ) | ||||
| Cash at beginning of year |
10,284 | 21,060 | ||||||
|
|
|
|
|
|||||
| Cash at end of year |
$ | 2,095 | $ | 10,284 | ||||
|
|
|
|
|
|||||
13
Matador Resources Company and Subsidiaries
SELECTED OPERATING DATA – UNAUDITED
| Year Ended December 31, | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
| Net Production Volumes: |
||||||||||||
| Oil (MBbl) |
1,214 | 154 | 33 | |||||||||
| Natural gas (Bcf) |
12.5 | 14.5 | 8.4 | |||||||||
| Total oil equivalent (MBOE)(1),(2) |
3,294 | 2,573 | 1,433 | |||||||||
| Average daily production (BOE/d)(2) |
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 | ||||||
| Operating Expenses per BOE: |
||||||||||||
| Production taxes and marketing |
$ | 3.54 | $ | 2.44 | $ | 1.38 | ||||||
| Lease operating |
$ | 8.56 | $ | 2.82 | $ | 3.69 | ||||||
| Depletion, depreciation and amortization |
$ | 24.43 | $ | 12.34 | $ | 10.89 | ||||||
| General and administrative |
$ | 4.42 | $ | 5.21 | $ | 6.77 | ||||||
| (1) | Thousands of barrels of oil equivalent. |
| (2) | Estimated using a conversion ratio of one Bbl per six Mcf. |
SELECTED ESTIMATED PROVED RESERVES DATA – UNAUDITED
| At December 31,(1) | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
| Estimated proved reserves: |
||||||||||||
| Oil (MBbl) |
10,485 | 3,794 | 152 | |||||||||
| Natural Gas (Bcf) |
80.0 | 170.4 | 127.4 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total (MBOE)(2) |
23,819 | 32,196 | 21,387 | |||||||||
|
|
|
|
|
|
|
|||||||
| Estimated proved developed reserves: |
||||||||||||
| Oil (MBbl) |
4,764 | 1,419 | 152 | |||||||||
| Natural Gas (Bcf) |
54.0 | 56.5 | 43.1 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total (MBOE) |
13,771 | 10,843 | 7,342 | |||||||||
|
|
|
|
|
|
|
|||||||
| Percent developed |
57.8 | % | 33.7 | % | 34.3 | % | ||||||
| Estimated proved undeveloped reserves: |
||||||||||||
| Oil (MBbl) |
5,721 | 2,375 | — | |||||||||
| Natural Gas (Bcf) |
26.0 | 113.9 | 84.3 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total (MBOE) |
10,048 | 21,353 | 14,045 | |||||||||
|
|
|
|
|
|
|
|||||||
| PV-10 (in millions) |
$ | 423.2 | $ | 248.7 | $ | 119.9 | ||||||
| Standardized Measure (in millions) |
$ | 394.6 | $ | 215.5 | $ | 111.1 | ||||||
| (1) | Numbers in table may not total due to rounding. |
| (2) | Thousands of barrels of oil equivalent, estimated using a conversion ratio of one Bbl per six Mcf. |
14
Supplemental Non-GAAP Financial Measures
Adjusted EBITDA
This press release includes the non-GAAP financial measure of Adjusted EBITDA. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. “GAAP” means Generally Accepted Accounting Principles in the United States of America. The Company believes Adjusted EBITDA helps it evaluate its operating performance and compares its results of operations from period to period without regard to its financing methods or capital structure. The Company defines Adjusted EBITDA as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, certain other non-cash items and non-cash stock-based compensation expense, including stock option and grant expense and restricted stock and restricted stock units expense, and net gain or loss on asset sales and inventory impairment. Adjusted EBITDA is not a measure of net (loss) income or net cash flow provided by operating activities as determined by GAAP.
Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of the Company’s operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. The following table presents the calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net (loss) income and net cash flow provided by operating activities, respectively, that are of a historical nature. Where references are forward-looking or prospective in nature, and not based on historical fact, the table does not provide a reconciliation. The Company could not provide such reconciliation without undue hardship because the forward-looking Adjusted EBITDA numbers included in this press release are estimations, approximations and/or ranges. In addition, it would be difficult for the Company to present a detailed reconciliation on account of many unknown variables for the reconciling items.
15
| Three Months Ended | Year Ended | Three Months Ended |
||||||||||||||||||
| (In thousands) | December 31, 2012 |
December 31, 2011 |
December 31, 2012 |
December 31, 2011 |
September 30, 2012 |
|||||||||||||||
| Unaudited Adjusted EBITDA reconciliation to Net Income (Loss): |
||||||||||||||||||||
| Net (loss) income |
$ | (21,188 | ) | $ | 3,941 | $ | (33,261 | ) | $ | (10,309 | ) | $ | (9,197 | ) | ||||||
| Interest expense |
549 | 222 | 1,002 | 683 | 144 | |||||||||||||||
| Total income tax (benefit) provision |
(188 | ) | 1,430 | (1,430 | ) | (5,521 | ) | (593 | ) | |||||||||||
| Depletion, depreciation and amortization |
27,655 | 9,176 | 80,454 | 31,754 | 21,680 | |||||||||||||||
| Accretion of asset retirement obligations |
86 | 51 | 256 | 209 | 59 | |||||||||||||||
| Full-cost ceiling impairment |
26,674 | — | 63,475 | 35,673 | 3,596 | |||||||||||||||
| Unrealized loss (gain) on derivatives |
3,653 | (3,604 | ) | 4,802 | (5,138 | ) | 12,993 | |||||||||||||
| Stock option and grant expense |
(4 | ) | 983 | (589 | ) | 2,362 | (252 | ) | ||||||||||||
| Restricted stock and restricted stock units expense |
367 | 8 | 729 | 44 | 201 | |||||||||||||||
| Net loss on asset sales and inventory impairment |
425 | 154 | 485 | 154 | — | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Adjusted EBITDA |
$ | 38,029 | $ | 12,361 | $ | 115,923 | $ | 49,911 | $ | 28,631 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Three Months Ended | Year Ended | Three Months Ended |
||||||||||||||||||
| December 31, 2012 |
December 31, 2011 |
December 31, 2012 |
December 31, 2011 |
September 30, 2012 |
||||||||||||||||
| Unaudited Adjusted EBITDA reconciliation to Net Cash Provided by Operating Activities: |
||||||||||||||||||||
| Net cash provided by operating activities |
$ | 43,903 | $ | 27,425 | $ | 124,228 | $ | 61,868 | $ | 28,799 | ||||||||||
| Net change in operating assets and liabilities |
(6,235 | ) | (15,286 | ) | (9,307 | ) | (12,594 | ) | (500 | ) | ||||||||||
| Interest expense |
549 | 222 | 1,002 | 683 | 144 | |||||||||||||||
| Current income tax (benefit) provision |
(188 | ) | — | — | (46 | ) | 188 | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Adjusted EBITDA |
$ | 38,029 | $ | 12,361 | $ | 115,923 | $ | 49,911 | $ | 28,631 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
16
PV-10
PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of the properties. Matador and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. The PV-10 at December 31, 2012, December 31, 2011 and December 31, 2010 may be reconciled to the Standardized Measure of discounted future net cash flows at such dates by reducing PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2012, December 31, 2011 and December 31, 2010 were, in millions, $28.6, $33.2 and $8.8, respectively.
17