DALLAS--(BUSINESS WIRE)--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 and nine months ended September 30, 2012. Headlines include the following:
- Record oil production of 303,000 Bbl for the third quarter of 2012, a sequential quarterly increase of 6.3% from 285,000 Bbl produced in the second quarter of 2012 and a year-over-year increase of over seven-fold from 43,000 Bbl produced in the third quarter of 2011.
- Record average daily oil equivalent production of 8,838 BOE per day for the third quarter of 2012, including 3,291 Bbl of oil per day and 33.3 MMcf of natural gas per day; a year-over-year increase of 28% from the third quarter of 2011.
- Record total realized revenues of $41.4 million for the third quarter of 2012, including $3.4 million in realized gain on derivatives, a year-over-year increase of 119% from total realized revenues of $18.9 million, including $1.4 million in realized gain on derivatives, reported for the third quarter of 2011.
- Record oil and natural gas revenues of $38.0 million, for a year-over-year increase of 118% from $17.4 million reported for the third quarter of 2011.
- Record Adjusted EBITDA of $28.6 million, a year-over-year increase of 137% from $12.1 million reported for the third quarter of 2011.
- The Company will hold an Analyst Day in Dallas, Texas, on December 6 at 10:00 a.m. Central Time to review its 2013 operational plan and forecasts.
- Matador’s 2013 capital expenditures budget anticipated to be modestly lower than the 2012 level of $313 million.
Third Quarter 2012 Financial Results
Joseph Wm. Foran, Matador’s Chairman, President and CEO, commented, “The third quarter saw continued strong growth in EBITDA as our drilling program in our Eagle Ford shale acreage continues to drive important growth in oil production and reserve values. To that end it is a pleasure to report that Matador produced more oil in the final six weeks of the third quarter of 2012 than we did in all of 2011. We continue to see improvements in our drilling and completion costs, even as production grows, and we continue to improve our drilling and completion techniques, which should lead to improvements in cash flow, rates of return and long-term asset value for our shareholders. Matador’s budget for 2013 capital expenditures is anticipated to be modestly lower than the $313 million in capital expenditures budgeted for 2012. This budget reflects our rich opportunity set in the Eagle Ford shale and our opportunity for exploration in the Delaware Basin and potentially even the Pearsall shale, balanced with our assessment that the pricing and operating environment may be softening to the point where maintaining financial discipline and flexibility will become increasingly important.”
Production and Revenues
Three Months Ended September 30, 2012 Compared to Three Months Ended September 30, 2011
Oil production increased over seven-fold to approximately 303,000 Bbl of oil, or about 3,291 Bbl of oil per day, during the third quarter of 2012 as compared to approximately 43,000 Bbl of oil, or about 465 Bbl of oil per day, in the third 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 8,838 BOE per day (37% oil by volume) in the third quarter of 2012 as compared to 6,931 BOE per day (7% oil by volume) during the third quarter of 2011.
Total realized revenues, including realized gain on derivatives, increased 119% to $41.4 million for the three months ended September 30, 2012 as compared to $18.9 million for the three months ended September 30, 2011. Oil and natural gas revenues increased 118% to $38.0 million in the third quarter of 2012 as compared to $17.4 million during the third quarter of 2011. This increase in oil and natural gas revenues reflects an increase in oil revenues of $26.4 million coupled with a decrease in natural gas revenues of $5.8 million between the respective periods. Oil revenues increased over eight-fold to $30.1 million for the three months ended September 30, 2012 as compared to $3.7 million in oil revenues for the three months ended September 30, 2011. A portion of this increase in oil revenues also reflects a higher weighted average oil price of $99.33 per Bbl realized during the three months ended September 30, 2012 as compared to a weighted average oil price of $85.92 per Bbl realized during the three months ended September 30, 2011. The decrease in natural gas revenues reflects a decline in natural gas production by about 14% to approximately 3.1 Bcf in the third quarter of 2012 as compared to approximately 3.6 Bcf in the third quarter of 2011. This decline in natural gas production is due to several factors, including (i) the natural decline in natural gas production primarily from existing Cotton Valley and Haynesville shale wells in Northwest Louisiana and East Texas, coupled with the decision not to drill any operated Haynesville shale wells in 2012, (ii) the voluntary curtailment of natural gas production from certain non-operated Haynesville shale wells in Northwest Louisiana and (iii) the flaring of a portion of the natural gas produced from newly completed Eagle Ford shale wells in South Texas as a result of gas pipeline constraints and awaiting the installation of permanent production facilities. 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 three months ended September 30, 2012 as compared to a weighted average natural gas price of $3.86 per Mcf realized during the three months ended September 30, 2011.
Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011
Oil production increased almost seven-fold to approximately 788,000 Bbl of oil, or about 2,876 Bbl of oil per day, during the first nine months of 2012 as compared to approximately 113,000 Bbl of oil, or about 414 Bbl of oil per day, during the first nine months of 2011. This increase in oil production is a direct result of ongoing drilling and completion operations in the Eagle Ford shale during which time Matador also benefited from declining drilling and completion costs of approximately 10% to 15% per well on average. Average daily oil equivalent production increased to approximately 8,534 BOE per day (34% oil by volume) during the first nine months of 2012 from approximately 7,081 BOE per day (6% oil by volume) during the first nine months of 2011.
Total realized revenues, including realized gain on derivatives, increased 103% to $114.4 million for the nine months ended September 30, 2012 as compared to $56.2 million for the nine months ended September 30, 2011. Oil and natural gas revenues increased 99% to $103.3 million during the first nine months of 2012 from $52.0 million during the comparable period in 2011. This increase in oil and natural gas revenues reflects an increase in oil revenues of $70.6 million and a decrease in natural gas revenues of $19.3 million between the respective periods. Oil revenues increased almost eight-fold to $81.0 million for the nine months ended September 30, 2012 as compared to $10.5 million for the nine months ended September 30, 2011.
Adjusted EBITDA
Adjusted EBITDA, a non-GAAP financial measure, increased 137% to $28.6 million for the three months ended September 30, 2012 as compared to $12.1 million for the three months ended September 30, 2011. Sequentially, Adjusted EBITDA increased 3% to $28.6 million during the third quarter of 2012 from $27.9 million during the second quarter of 2012.
Adjusted EBITDA increased 107% to $77.9 million for the nine months ended September 30, 2012 as compared to $37.6 million during the first nine months of 2011. Notably, the Adjusted EBITDA of $77.9 million reported for the first nine months of 2012 compares to an Adjusted EBITDA of $49.9 million reported for all of last year (2011). 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 September 30, 2012 increased almost eight-fold to approximately 8.4 million Bbl as compared to 1.1 million Bbl at September 30, 2011. At September 30, 2012, total proved reserves were approximately 20.9 million BOE, including approximately 8.4 million Bbl of oil (40% oil by volume) and 74.9 Bcf of natural gas, with a present value of estimated future net cash flows discounted at 10%, or PV-10, of $363.6 million (Standardized Measure of $333.9 million) as compared to total proved reserves at September 30, 2011 of approximately 27.0 million BOE, including approximately 1.1 million Bbl of oil (4% oil by volume) and 155.3 Bcf of natural gas, with a PV-10 of $155.2 million (Standardized Measure of $143.4 million). As a result of declines in natural gas prices, the Company previously removed approximately 16.3 million BOE in proved undeveloped Haynesville shale natural gas reserves from its total proved reserves at June 30, 2012. The reserves estimates in 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.
Net (Loss) Income
For the quarter ended September 30, 2012, Matador reported a net loss of approximately $9.2 million and a loss of $0.17 per common share compared to net income of approximately $6.2 million and earnings of $0.14 per Class A common share and $0.21 per Class B common share for the quarter ended September 30, 2011. All Class B shares were converted to Class A shares upon completion of the Company’s initial public offering in February 2012; there is only one class of common shares outstanding at September 30, 2012.
The net loss reported for the third quarter of 2012 is primarily attributable to non-cash charges, principally an unrealized loss on derivatives of approximately $13.0 million and a full-cost ceiling impairment charge to operations of $3.6 million recorded in the quarter. The unrealized loss on derivatives is attributable to a change in the net fair value of the Company’s commodity derivatives during the period primarily as a result of increases in oil and natural gas prices between June 30 and September 30, 2012. The change in the net fair value of the Company’s commodity derivatives can be volatile from period to period, and in fact, this unrealized loss of approximately $13.0 million compares to and partially offsets the unrealized gain on derivatives of approximately $15.1 million reported for the second quarter of 2012. The full-cost ceiling impairment was primarily attributable to the continued decline in the average natural gas price the Company is required to use to estimate its natural gas reserves, as well as smaller than anticipated reserves additions from the two Austin Chalk/“Chalkleford” wells drilled and completed in Zavala County, Texas during the quarter.
Sequential Financial Results
- Oil production increased 6% to approximately 303,000 Bbl, or 3,291 Bbl of oil per day in the third quarter of 2012 from approximately 285,000 Bbl, or 3,131 Bbl of oil per day, in the second quarter of 2012. Total proved oil and natural gas reserves increased approximately 10% to 20.9 MMBOE at September 30, 2012 from 19.1 MMBOE at June 30, 2012.
- Oil and natural gas revenues increased 5% to $38.0 million in the third quarter of 2012 from $36.1 million in the second quarter of 2012.
- The present value of estimated future net cash flows from proved oil and natural gas reserves discounted at 10%, or PV-10, increased 20% to $363.6 million at September 30, 2012 from $303.4 million at June 30, 2012.
- Adjusted EBITDA increased 3% to $28.6 million in the third quarter of 2012 from $27.9 million in the second quarter of 2012.
Operating Expenses Update
Production Taxes and Marketing
Production taxes and marketing expenses increased to $2.8 million (or $3.47 per BOE) for the three months ended September 30, 2012 from $1.8 million (or $2.90 per BOE) for the three months ended September 30, 2011. The increase in production taxes and marketing expenses reflects the increase in total oil and natural gas revenues by 118% during the three months ended September 30, 2012 as compared to the three months ended September 30, 2011. The majority of this increase was attributable to production taxes and marketing expenses associated with the large increase in oil production resulting from drilling operations in the Eagle Ford shale in South Texas.
Lease Operating Expenses (“LOE”)
Lease operating expenses increased to $6.5 million (or $7.98 per BOE) for the three months ended September 30, 2012 from $2.1 million (or $3.24 per BOE) for the three months ended September 30, 2011. The increase in lease operating expenses was primarily attributable to increased costs associated with operating high volume oil production as a result of ongoing drilling and completion operations in the Eagle Ford shale in 2012, as compared to the lower lease operating expenses associated with dry gas production. In addition, oil production comprised 37% of total production by volume during the three months ended September 30, 2012 as compared to only 7% of total production by volume during the same period in 2011, resulting in these higher overall lease operating expenses during the third quarter of 2012.
Depletion, depreciation and amortization (“DD&A”)
Depletion, depreciation and amortization expenses increased to $21.7 million (or $26.66 per BOE) for the three months ended September 30, 2012 from $7.3 million (or $11.43 per BOE) for the three months ended September 30, 2011. This increase in depletion, depreciation and amortization expense was attributable to the decrease in total proved oil and natural gas reserves to 20.9 million BOE at September 30, 2012 as compared to 27.0 million BOE at September 30, 2011. As noted above, as a result of declines in natural gas prices, the Company previously removed approximately 16.3 million BOE in proved undeveloped Haynesville shale natural gas reserves from its total proved reserves at June 30, 2012. This increase in depletion, depreciation and amortization expense was also partially due to the increase of approximately 28% in total oil and natural gas production to approximately 813,000 BOE during the three months ended September 30, 2012 as compared to approximately 638,000 BOE during the three months ended September 30, 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 and other gas assets in Northwest Louisiana.
General and administrative (“G&A”)
General and administrative expenses decreased to $3.4 million (or $4.23 per BOE) for the three months ended September 30, 2012 as compared to $4.2 million (or $6.60 per BOE) for the three months ended September 30, 2011. The decrease in general and administrative expenses was attributable primarily to decreased stock based compensation expense, partially offset by increased compensation, accounting, legal and other administrative expenses, much of which is associated with becoming a public company in February 2012.
Operations Update
Eagle Ford Shale – South Texas
During the first nine months of 2012, Matador’s operations were focused on the exploration and development of its Eagle Ford shale properties in South Texas. In the third quarter of 2012 specifically, 6 gross/5.3 net operated and 1 gross/0.2 net non-operated Eagle Ford shale wells were completed and placed on production along with 2 gross/2 net operated Austin Chalk/“Chalkleford” wells. Two of these Eagle Ford operated wells were on the Love lease in DeWitt County, two on the Northcut lease in LaSalle County, one on the Martin Ranch lease in LaSalle County, and one on the Sickenius lease in Karnes County. One upper Austin Chalk well and one lower Austin Chalk/upper Eagle Ford, or “Chalkleford,” well were drilled and completed on the Glasscock Ranch lease in Zavala County. The two wells on the Love lease began producing during August 2012; the two wells on the Northcut lease and the well drilled on the Sickenius lease began producing in September. The well drilled on the Martin Ranch lease did not begin producing until late September. As a result, these six wells did not contribute fully to the third quarter production volumes. Matador currently has two contracted drilling rigs operating in South Texas: one in LaSalle County and one in DeWitt County.
During the third quarter of 2012, Matador drilled the two wells on the Love lease back to back and performed “zipper-frac” operations on those two wells. The two wells on the Northcut lease were also drilled back to back with “zipper-fracs” pumped on the wells. The decision to drill wells back to back and to utilize “zipper-frac” techniques did result in a delay of first production from these wells of approximately 30 to 60 days compared to the typical time frame for independently drilled and fracture stimulated wells. While it is early in the production life of these two sets of “zipper-frac” wells, the results look favorable enough to warrant further tests and study. Matador is continuing to improve its drilling and completion techniques for these Eagle Ford wells and is encouraged by the results of these latest stimulation changes as well as the reductions being achieved in drilling and completion times and costs. Early results from these tests in DeWitt, Karnes and LaSalle counties indicate improved well performance as a result of recent fracture treatment modifications and operational practices such as restricting choke sizes. Matador continues to see benefits in flowing back the wells on restricted chokes and will continue to utilize this practice in the foreseeable future to maintain bottomhole pressure and to reduce stress on the rock and the proppant, even though such practices may result in smaller volumes of oil in the short term. Matador believes these operational improvements will extend the periods these wells can flow without artificial lift, thereby reducing LOE expenses in the short term and increasing ultimate recoveries in the long run.
Matador continues to evaluate results from recent wells drilled on 80-acre spacing on two of its Eagle Ford properties and, based on this early evaluation, Matador plans to continue drilling offset wells on 80-acre spacing on some of its other Eagle Ford acreage. Matador has also finalized a natural gas gathering, transportation and processing agreement, including firm transportation and processing, for most of its operated natural gas production in South Texas. This agreement will ensure that Matador has access to the market for the natural gas and natural gas liquids produced from its Eagle Ford properties.
Matador has recently begun placing some of its more mature producing wells on artificial lift. While still in the early stages, it appears as though this program should be successful in sustaining production volumes from wells that are in need of assistance in order to optimize production. While most of the current installations of artificial lift are in the form of pumping units and rod pumps, Matador is evaluating other possible artificial lift methods to maximize production from these wells.
Matador has drilled three wells on its 9,000 acre block in Zavala County, Texas. The three wells included an Eagle Ford test, an upper Austin Chalk test, and a lower Austin Chalk/Upper Eagle Ford, or “Chalkleford,” test. None of these wells were particularly strong, but all three wells continue to produce oil with the assistance of artificial lift. Matador will continue to evaluate the performance of all three wells while studying other potential formations on the acreage block, including the Pearsall shale, and studying offset well performance from wells completed in other zones. Matador remains optimistic that this acreage block may yield favorable results with further study and technical progress.
Haynesville Shale – Northwest Louisiana
Matador has no plans to drill any operated Haynesville shale wells for the remainder of 2012, but is participating in several non-operated Haynesville wells where it has working interests throughout 2012. As a result of low natural gas prices, several non-operated Haynesville shale wells were shut in for brief periods or produced less natural gas than anticipated during the first nine months of 2012 as the operators voluntarily curtailed a portion of the natural gas production from these wells.
Meade Peak Shale – Wyoming, Utah and Idaho
During the third quarter, Matador and its partner finalized commercial arrangements related to the ongoing exploration of the Meade Peak shale. Operations are scheduled to begin in the fourth quarter of 2012 to conduct a horizontal test of the Meade Peak shale. A rig is on location. The existing Crawford Federal #1 vertical wellbore was drilled and cored through the Meade Peak shale and then suspended in December 2011. Plans are to re-enter this existing wellbore, plug back to a sufficient depth to sidetrack and drill a horizontal lateral to test the Meade Peak formation. Matador’s share of the anticipated costs of this operation will be carried by its partner. Matador and its partner also intend to renew leases that may be available for renewal and may acquire additional leasehold within their area of mutual interest.
Acreage Acquisitions
On August 10, 2012, Matador added to its existing acreage position in the Delaware Basin with the acquisition of approximately 4,900 gross and 2,900 net acres in the heart of the Wolfbone play in Loving County, Texas. The Company expects to begin testing this acreage as well as to add to its other acreage positions in the next twelve months.
Liquidity Update
On September 28, 2012, the Company closed an amended and restated senior secured revolving credit agreement. Under the credit agreement, the borrowing base was increased to $200 million, up from the previous borrowing base of $125 million based on June 30, 2012 reserves estimates. The amendment increased the maximum facility size from $400 million to $500 million and named Royal Bank of Canada as Administrative Agent.
At September 30, 2012, the Company had cash and cash equivalents and certificates of deposits totaling approximately $4.4 million, approximately $106.0 million of outstanding long-term borrowings and approximately $1.1 million in outstanding letters of credit. In early October, the borrowings were converted to a Eurodollar-based rate advance and bore interest at an effective rate of approximately 3.3%. In October 2012 and November 2012, Matador borrowed an additional $14.0 million and $15.0 million, respectively, under its credit agreement to finance a portion of working capital requirements and capital expenditures. As of November 12, 2012, the Company had $135.0 million in outstanding long-term borrowings and approximately $1.1 million in outstanding letters of credit. The borrowing base will be redetermined based upon December 31, 2012 reserves estimates, although Matador may also request a redetermination based on its reserves growth at September 30, 2012.
Capital Spending
At September 30, 2012, Matador has incurred approximately $237.6 million or about 76% of its anticipated 2012 capital expenditures budget of $313 million. This includes approximately $21.2 million incurred to acquire additional leasehold acreage primarily in the Eagle Ford shale near the Company’s existing properties and in the Delaware Basin in West Texas. As of September 30, 2012, Matador is executing its 2012 capital expenditures program as planned and remains within its anticipated capital expenditures budget for 2012.
Hedging Positions
For the fourth quarter of 2012, Matador has hedged 360,000 Bbl of its anticipated oil production using costless collars having a weighted average floor price of $90.83 per Bbl and a weighted average ceiling price of $110.31 per Bbl.
For the fourth quarter of 2012, Matador has hedged 2.31 Bcf of its anticipated natural gas production using costless collars having a weighted average floor price of $4.07 per MMBtu and a weighted average ceiling price of $5.30 per MMBtu.
For the fourth quarter of 2012, Matador has hedged 625,200 gallons of its anticipated natural gas liquids production using swaps having a weighted average price of $0.81 per gallon.
2012 Guidance Update
Matador anticipates its 2012 annual oil production will be near the lower end of its previously announced guidance of 1.2 to 1.4 million barrels. The Company reaffirms its previous 2012 guidance announced on March 7, 2012 and May 14, 2012 for (1) estimated capital spending of $313 million, (2) an estimated exit rate for oil production of 5,000 to 5,500 Bbl per day and (3) estimated total natural gas production of 12.5 to 13.5 Bcf.
2013 Guidance Announcement
Matador’s budget for 2013 capital expenditures is anticipated to be modestly lower than the $313 million in capital expenditures budgeted for 2012. This preliminary budget estimate reflects the Company’s rich opportunity set in the Eagle Ford shale and its opportunity for exploration in the Delaware Basin in West Texas and potentially the Pearsall shale and Buda in South Texas, balanced with its assessment that the pricing environment may be softening and maintaining financial discipline is key. Additional elements of the Company’s 2013 plan will be discussed in detail during its upcoming Analyst Day on Thursday, December 6, 2012.
Matador Analyst Day
Matador will be hosting an Analyst Day on Thursday, December 6, 2012 at 10:00 a.m. Central Time at the Company’s headquarters in Dallas, Texas. The meeting will include an overview of its 2013 operational plan, capital budget and forecasts, plus an update on geology and drilling and completion techniques in its areas of operation. The call will be available via webcast and details will be released closer to the date.
Conference Call Information and Investor Presentation
The Company will host a conference call on Monday, November 12, 2012, at 9:00 a.m. Central Time to discuss its third quarter 2012 financial and operational results. To access the conference call, domestic participants should dial (866) 314-5050 and international participants should dial (617) 213-8051. The participant passcode is 73985344. 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. To access the conference call, domestic participants should dial (866) 314-5050 and international participants should dial (617) 213-8051. The participant passcode is 73985344. The replay for the event will also be available on the Company’s website at www.matadorresources.com through Wednesday, November 21, 2012. In addition, the Company’s updated Investor Presentation is available on the Presentations & Webcasts page under the Investors tab of the Company’s website at www.matadorresources.com.
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 located primarily in the Eagle Ford shale play in South Texas and the Haynesville shale play in Northwest Louisiana and East Texas.
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. These forward-looking statements involve certain risks and uncertainties and ultimately may not prove to be accurate, including, but not limited to, the following risks related to financial and operational performance: general economic conditions; ability for Matador to execute its business plan, including the success of its drilling program; 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 Matador to execute its 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.
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Matador Resources Company and Subsidiaries
CONDENSED CONSOLIDATED BALANCE SHEETS – UNAUDITED |
||||||||||
| (In thousands, except par value and share data) | ||||||||||
| September 30, | December 31, | |||||||||
| 2012 | 2011 | |||||||||
| ASSETS | ||||||||||
| Current assets | ||||||||||
| Cash and cash equivalents | $ | 4,178 | $ | 10,284 | ||||||
| Certificates of deposit | 266 | 1,335 | ||||||||
| Accounts receivable | ||||||||||
| Oil and natural gas revenues | 17,046 | 9,237 | ||||||||
| Joint interest billings | 4,252 | 2,488 | ||||||||
| Other | 591 | 1,447 | ||||||||
| Derivative instruments | 6,395 | 8,989 | ||||||||
| Lease and well equipment inventory | 1,478 | 1,343 | ||||||||
| Prepaid expenses | 974 | 1,153 | ||||||||
| Total current assets | 35,180 | 36,276 | ||||||||
| Property and equipment, at cost | ||||||||||
| Oil and natural gas properties, full-cost method | ||||||||||
| Evaluated | 654,292 | 423,945 | ||||||||
| Unproved and unevaluated | 164,514 | 162,598 | ||||||||
| Other property and equipment | 24,597 | 18,764 | ||||||||
| Less accumulated depletion, depreciation and amortization | (295,042 | ) | (205,442 | ) | ||||||
| Net property and equipment | 548,361 | 399,865 | ||||||||
| Other assets | ||||||||||
| Derivative instruments | 1,880 | 847 | ||||||||
| Deferred income taxes | 1,878 | 1,594 | ||||||||
| Other assets | 1,537 | 887 | ||||||||
| Total other assets | 5,295 | 3,328 | ||||||||
| Total assets | $ | 588,836 | $ | 439,469 | ||||||
| LIABILITIES AND SHAREHOLDERS' EQUITY | ||||||||||
| Current liabilities | ||||||||||
| Accounts payable | $ | 17,364 | $ | 18,841 | ||||||
| Accrued liabilities | 50,262 | 25,439 | ||||||||
| Royalties payable | 5,920 | 1,855 | ||||||||
| Borrowings under Credit Agreement | - | 25,000 | ||||||||
| Derivative instruments | - | 171 | ||||||||
| Advances from joint interest owners | 1,782 | - | ||||||||
| Income taxes payable | 188 | - | ||||||||
| Deferred income taxes | 1,878 | 3,024 | ||||||||
| Dividends payable - Class B | - | 69 | ||||||||
| Other current liabilities | 56 | 177 | ||||||||
| Total current liabilities | 77,450 | 74,576 | ||||||||
| Long-term liabilities | ||||||||||
| Borrowings under Credit Agreement | 106,000 | 88,000 | ||||||||
| Asset retirement obligations | 4,551 | 3,935 | ||||||||
| Derivative instruments | 142 | 383 | ||||||||
| Other long-term liabilities | 1,465 | 1,060 | ||||||||
| Total long-term liabilities | 112,158 | 93,378 | ||||||||
| Shareholders' equity | ||||||||||
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Common stock - Class A, $0.01 par value, 80,000,000 shares authorized; 56,697,718 and 42,916,668 shares issued; 55,505,209 and 41,737,493 shares outstanding, respectively |
567 | 429 | ||||||||
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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 | 403,248 | 263,562 | ||||||||
| Retained earnings | 6,178 | 18,279 | ||||||||
| Treasury stock, at cost, 1,192,509 and 1,179,175, respectively | (10,765 | ) | (10,765 | ) | ||||||
| Total shareholders' equity | 399,228 | 271,515 | ||||||||
| Total liabilities and shareholders' equity | $ | 588,836 | $ | 439,469 | ||||||
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Matador Resources Company and Subsidiaries
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS – UNAUDITED |
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| (In thousands, except per share data) | ||||||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||||||
| Revenues | ||||||||||||||||||||
| Oil and natural gas revenues | $ | 38,008 | $ | 17,447 | $ | 103,250 | $ | 52,009 | ||||||||||||
| Realized gain on derivatives | 3,371 | 1,435 | 11,147 | 4,237 | ||||||||||||||||
| Unrealized (loss) gain on derivatives | (12,993 | ) | 2,870 | (1,149 | ) | 1,534 | ||||||||||||||
| Total revenues | 28,386 | 21,752 | 113,248 | 57,780 | ||||||||||||||||
| Expenses | ||||||||||||||||||||
| Production taxes and marketing | 2,822 | 1,848 | 7,605 | 4,801 | ||||||||||||||||
| Lease operating | 6,491 | 2,065 | 17,511 | 5,639 | ||||||||||||||||
| Depletion, depreciation and amortization | 21,680 | 7,288 | 52,799 | 22,578 | ||||||||||||||||
| Accretion of asset retirement obligations | 59 | 61 | 170 | 158 | ||||||||||||||||
| Full-cost ceiling impairment | 3,596 | - | 36,801 | 35,673 | ||||||||||||||||
| General and administrative | 3,439 | 4,207 | 11,321 | 9,919 | ||||||||||||||||
| Total expenses | 38,087 | 15,469 | 126,207 | 78,768 | ||||||||||||||||
| Operating (loss) income | (9,701 | ) | 6,283 | (12,959 | ) | (20,988 | ) | |||||||||||||
| Other income (expense) | ||||||||||||||||||||
| Net loss on asset sales and inventory impairment | - | - | (60 | ) | - | |||||||||||||||
| Interest expense | (144 | ) | (171 | ) | (453 | ) | (461 | ) | ||||||||||||
| Interest and other income | 55 | 82 | 157 | 248 | ||||||||||||||||
| Total other expense | (89 | ) | (89 | ) | (356 | ) | (213 | ) | ||||||||||||
| (Loss) income before income taxes | (9,790 | ) | 6,194 | (13,315 | ) | (21,201 | ) | |||||||||||||
| Income tax provision (benefit) | ||||||||||||||||||||
| Current | 188 | - | 188 | (46 | ) | |||||||||||||||
| Deferred | (781 | ) | - | (1,430 | ) | (6,906 | ) | |||||||||||||
| Total income tax benefit | (593 | ) | - | (1,242 | ) | (6,952 | ) | |||||||||||||
| Net (loss) income | $ | (9,197 | ) | $ | 6,194 | $ | (12,073 | ) | $ | (14,249 | ) | |||||||||
| Earnings (loss) per common share | ||||||||||||||||||||
| Basic | ||||||||||||||||||||
| Class A | $ | (0.17 | ) | $ | 0.14 | $ | (0.23 | ) | $ | (0.34 | ) | |||||||||
| Class B | $ | - | $ | 0.21 | $ | (0.03 | ) | $ | (0.14 | ) | ||||||||||
| Diluted | ||||||||||||||||||||
| Class A | $ | (0.17 | ) | $ | 0.14 | $ | (0.23 | ) | $ | (0.34 | ) | |||||||||
| Class B | $ | - | $ | 0.21 | $ | (0.03 | ) | $ | (0.14 | ) | ||||||||||
| Weighted average common shares outstanding | ||||||||||||||||||||
| Basic | ||||||||||||||||||||
| Class A | 55,271 | 41,720 | 53,379 | 41,671 | ||||||||||||||||
| Class B | - | 1,031 | 140 | 1,031 | ||||||||||||||||
| Total | 55,271 | 42,751 | 53,519 | 42,702 | ||||||||||||||||
| Diluted | ||||||||||||||||||||
| Class A | 55,271 | 41,848 | 53,379 | 41,671 | ||||||||||||||||
| Class B | - | 1,031 | 140 | 1,031 | ||||||||||||||||
| Total | 55,271 | 42,879 | 53,519 | 42,702 | ||||||||||||||||
|
Matador Resources Company and Subsidiaries
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – UNAUDITED |
||||||||||
| (In thousands) | ||||||||||
| Nine Months Ended September 30, | ||||||||||
| 2012 | 2011 | |||||||||
| Operating activities | ||||||||||
| Net loss | $ | (12,073 | ) | $ | (14,249 | ) | ||||
|
Adjustments to reconcile net loss to net cash provided by operating activities |
||||||||||
| Unrealized loss (gain) on derivatives | 1,149 | (1,534 | ) | |||||||
| Depletion, depreciation and amortization | 52,799 | 22,578 | ||||||||
| Accretion of asset retirement obligations | 170 | 158 | ||||||||
| Full-cost ceiling impairment | 36,801 | 35,673 | ||||||||
| Stock option and grant expense | (585 | ) | 1,379 | |||||||
| Restricted stock and restricted stock units expense | 362 | 36 | ||||||||
| Deferred income tax benefit | (1,430 | ) | (6,906 | ) | ||||||
| Loss on asset sales and inventory impairment | 60 | - | ||||||||
| Changes in operating assets and liabilities | ||||||||||
| Accounts receivable | (8,718 | ) | (2,411 | ) | ||||||
| Lease and well equipment inventory | (285 | ) | (1 | ) | ||||||
| Prepaid expenses | 179 | 240 | ||||||||
| Other assets | (650 | ) | - | |||||||
| Accounts payable, accrued liabilities and other liabilities | 6,105 | (2,360 | ) | |||||||
| Income taxes payable | 188 | - | ||||||||
| Royalties payable | 4,065 | 2,548 | ||||||||
| Advances from joint interest owners | 1,782 | (723 | ) | |||||||
| Other long-term liabilities | 406 | 15 | ||||||||
| Net cash provided by operating activities | 80,325 | 34,443 | ||||||||
| Investing activities | ||||||||||
| Oil and natural gas properties capital expenditures | (212,702 | ) | (104,733 | ) | ||||||
| Expenditures for other property and equipment | (5,297 | ) | (3,303 | ) | ||||||
| Purchases of certificates of deposit | (416 | ) | (3,721 | ) | ||||||
| Maturities of certificates of deposit | 1,485 | 3,985 | ||||||||
| Net cash used in investing activities | (216,930 | ) | (107,772 | ) | ||||||
| Financing activities | ||||||||||
| Repayments of borrowings under Credit Agreement | (123,000 | ) | - | |||||||
| Borrowings under Credit Agreement | 116,000 | 60,000 | ||||||||
| Proceeds from issuance of common stock | 146,510 | 592 | ||||||||
| Swing sale profit contribution | 24 | - | ||||||||
| Cost to issue equity | (11,599 | ) | (1,185 | ) | ||||||
| Proceeds from stock options exercised | 2,660 | 837 | ||||||||
|
Payment of dividends - Class B |
(96 | ) | (206 | ) | ||||||
| Net cash provided by financing activities | 130,499 | 60,038 | ||||||||
| Decrease in cash and cash equivalents | (6,106 | ) | (13,291 | ) | ||||||
| Cash and cash equivalents at beginning of period | 10,284 | 21,059 | ||||||||
| Cash and cash equivalents at end of period | $ | 4,178 | $ | 7,768 | ||||||
|
Matador Resources Company and Subsidiaries
SELECTED OPERATING DATA – UNAUDITED |
||||||||||||||||
|
Three Months Ended
September 30, |
Nine Months Ended
September 30, |
|||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| Net Production Volumes: | ||||||||||||||||
| Oil (MBbl) | 303 | 43 | 788 | 113 | ||||||||||||
| Natural gas (Bcf) | 3.1 | 3.6 | 9.3 | 10.9 | ||||||||||||
| Total oil equivalents (MBOE)(1),(2) | 813 | 638 | 2,338 | 1,933 | ||||||||||||
| Average net daily production (BOE/d)(2) | 8,838 | 6,931 | 8,534 | 7,081 | ||||||||||||
| Average Sales Prices: | ||||||||||||||||
| Oil, with realized derivatives (per Bbl) | $ | 100.56 | $ | 85.92 | $ | 104.25 | $ | 92.71 | ||||||||
| Oil, without realized derivatives (per Bbl) | $ | 99.33 | $ | 85.92 | $ | 102.86 | $ | 92.71 | ||||||||
| Natural gas, with realized derivatives (per Mcf) | $ | 3.57 | $ | 4.26 | $ | 3.47 | $ | 4.19 | ||||||||
| Natural gas, without realized derivatives (per Mcf) | $ | 2.59 | $ | 3.86 | $ | 2.39 | $ | 3.80 | ||||||||
| Operating Expenses per BOE: | ||||||||||||||||
| Production taxes and marketing | $ | 3.47 | $ | 2.90 | $ | 3.25 | $ | 2.48 | ||||||||
| Lease operating | $ | 7.98 | $ | 3.24 | $ | 7.49 | $ | 2.92 | ||||||||
| Depletion, depreciation and amortization | $ | 26.66 | $ | 11.43 | $ | 22.58 | $ | 11.68 | ||||||||
| General and administrative | $ | 4.23 | $ | 6.60 | $ | 4.84 | $ | 5.13 | ||||||||
| (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 September 30,(1) | At December 31,(1) | ||||||||||||||
| 2012 | 2011 | 2011 | |||||||||||||
| Estimated proved reserves: | |||||||||||||||
| Oil (MBbl) | 8,411 | 1,083 | 3,794 | ||||||||||||
| Natural Gas (Bcf) | 74.9 | 155.3 | 170.4 | ||||||||||||
| Total (MBOE)(2) | 20,894 | 26,971 | 32,194 | ||||||||||||
| Estimated proved developed reserves: | |||||||||||||||
| Oil (MBbl) | 3,783 | 519 | 1,419 | ||||||||||||
| Natural Gas (Bcf) | 53.4 | 52.7 | 56.5 | ||||||||||||
| Total (MBOE) | 12,686 | 9,294 | 10,836 | ||||||||||||
| Percent developed | 60.7 | % | 34.5 | % | 33.7 | % | |||||||||
| Estimated proved undeveloped reserves: | |||||||||||||||
| Oil (MBbl) | 4,628 | 565 | 2,375 | ||||||||||||
| Natural Gas (Bcf) | 21.5 | 102.7 | 113.9 | ||||||||||||
| Total (MBOE) | 8,208 | 17,677 | 21,358 | ||||||||||||
| PV-10 (in millions) | $ | 363.6 | $ | 155.2 | $ | 248.7 | |||||||||
| Standardized Measure (in millions) | $ | 333.9 | $ | 143.4 | $ | 215.5 | |||||||||
| (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. | |||||||||||||||
Supplemental Non-GAAP Financial Measures
Adjusted EBITDA
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 income or cash flows as determined by GAAP. 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.
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 tables present the calculation of Adjusted EBITDA and reconciliation of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively.
| (In thousands) | |||||||||||||||||||||||||||||
| Three Months Ended | Nine Months Ended |
Three Months |
Three Months |
Year Ended | |||||||||||||||||||||||||
| September 30, | September 30, | September 30, | September 30, | June 30, | December 31, | December 31, | |||||||||||||||||||||||
| 2012 | 2011 | 2012 | 2011 | 2012 | 2011 | 2011 | |||||||||||||||||||||||
| Unaudited Adjusted EBITDA reconciliation to | |||||||||||||||||||||||||||||
| Net Income (Loss): | |||||||||||||||||||||||||||||
| Net (loss) income | $ | (9,197 | ) | $ | 6,194 | $ | (12,073 | ) | $ | (14,249 | ) | $ | (6,676 | ) | $ | 3,941 | $ | (10,309 | ) | ||||||||||
| Interest expense | 144 | 171 | 453 | 461 | 1 | 222 | 683 | ||||||||||||||||||||||
| Total income tax (benefit) provision | (593 | ) | - | (1,242 | ) | (6,952 | ) | (3,713 | ) | 1,430 | (5,521 | ) | |||||||||||||||||
| Depletion, depreciation and amortization | 21,680 | 7,287 | 52,799 | 22,578 | 19,914 | 9,175 | 31,754 | ||||||||||||||||||||||
| Accretion of asset retirement obligations | 59 | 62 | 170 | 158 | 58 | 51 | 209 | ||||||||||||||||||||||
| Full-cost ceiling impairment | 3,596 | - | 36,801 | 35,673 | 33,205 | - | 35,673 | ||||||||||||||||||||||
| Unrealized loss (gain) on derivatives | 12,993 | (2,870 | ) | 1,149 | (1,534 | ) | (15,114 | ) | (3,604 | ) | (5,138 | ) | |||||||||||||||||
| Stock option and grant expense | (252 | ) | 1,220 | (585 | ) | 1,379 | 41 | 983 | 2,362 | ||||||||||||||||||||
| Restricted stock and restricted stock units expense | 201 | 14 | 362 | 36 | 150 | 8 | 44 | ||||||||||||||||||||||
| Net loss on asset sales and inventory impairment | - | - | 60 | - | 60 | 154 | 154 | ||||||||||||||||||||||
| Adjusted EBITDA | $ | 28,631 | $ | 12,078 | $ | 77,894 | $ | 37,550 | $ | 27,926 | $ | 12,360 | $ | 49,911 | |||||||||||||||
| Three Months Ended | Nine Months Ended |
Three Months |
Three Months |
Year Ended | |||||||||||||||||||||||||
| September 30, | September 30, | September 30, | September 30, | June 30, | December 31, | December 31, | |||||||||||||||||||||||
| 2012 | 2011 | 2012 | 2011 | 2012 | 2011 | 2011 | |||||||||||||||||||||||
|
Unaudited Adjusted EBITDA reconciliation to Net Cash Provided by Operating Activities: |
|||||||||||||||||||||||||||||
| Net cash provided by operating activities | $ | 28,799 | $ | 14,912 | $ | 80,325 | $ | 34,443 | $ | 46,416 | $ | 27,425 | $ | 61,868 | |||||||||||||||
| Net change in operating assets and liabilities | (500 | ) | (3,005 | ) | (3,072 | ) | 2,692 | (18,491 | ) | (15,287 | ) | (12,594 | ) | ||||||||||||||||
| Interest expense | 144 | 171 | 453 | 461 | 1 | 222 | 683 | ||||||||||||||||||||||
| Current income tax provision (benefit) | 188 | - | 188 | (46 | ) | - | - | (46 | ) | ||||||||||||||||||||
| Adjusted EBITDA | $ | 28,631 | $ | 12,078 | $ | 77,894 | $ | 37,550 | $ | 27,926 | $ | 12,360 | $ | 49,911 | |||||||||||||||
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 September 30, 2012, June 30, 2012 and September 30, 2011 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 September 30, 2012, June 30, 2012 and September 30, 2011 were, in millions, $29.7, $21.9 and $11.8, respectively.