- Record oil production of 285,000 Bbl, a sequential quarterly increase of 43% from 200,000 Bbl produced in the first quarter of 2012 and a year-over-year increase of almost six-fold from 51,000 Bbl produced in the second quarter of 2011.
- Record average daily oil equivalent production of 8,740 BOE per day, including 3,130 Bbl of oil per day and 33.6 MMcf of natural gas per day.
- Record total realized revenues of $40.8 million including $4.7 million in realized gain on derivatives, a year-over-year increase of 87% from total realized revenues of $21.8 million including $1.0 million in realized gain on derivatives reported for the second quarter of 2011.
- Record oil and natural gas revenues of $36.1 million, a year-over-year increase of 73% from $20.9 million reported for the second quarter of 2011.
- Record Adjusted EBITDA of $27.9 million, a year-over-year increase of 82% from $15.3 million reported for the second quarter of 2011.
- Revised 2012 annual oil production guidance downward to 1.2 to 1.4 million barrels from 1.4 to 1.5 million barrels, effective as of the date of this release, but otherwise reaffirmed previous guidance.
- Acquired approximately 2,800 gross and net acres prospective for the Eagle Ford shale play and other targets near existing leasehold in LaSalle, Gonzales and Wilson Counties.
- Acquired approximately 4,900 gross and 2,900 net acres prospective for the Wolfbone play in the Delaware Basin in Loving County, Texas on August 10, 2012.
Production and RevenuesThree Months Ended June 30, 2012 Compared to Three Months Ended June 30, 2011 Oil production increased almost six-fold to approximately 285,000 Bbl of oil, or about 3,130 Bbl of oil per day, during the second quarter of 2012 as compared to approximately 51,000 Bbl of oil, or about 560 Bbl of oil per day, in the second 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 8,740 BOE per day (36% oil) in the second quarter of 2012 from 8,004 BOE per day (7% oil) during the comparable period of 2011. Total realized revenues, including realized gain on derivatives, increased 87% to $40.8 million for the three months ended June 30, 2012 as compared to $21.8 million for the three months ended June 30, 2011. Oil and natural gas revenues increased 73% to $36.1 million in the second quarter of 2012 from $20.9 million during the comparable period in 2011. This increase in oil and natural gas revenues reflects an increase in oil revenues of $24.3 million and a decrease in natural gas revenues of $9.1 million between the respective periods. Oil revenues increased almost six-fold to $29.4 million for the three months ended June 30, 2012 as compared to $5.1 million for the three months ended June 30, 2011. A portion of this increase in oil revenue also reflects a higher weighted average oil price of $103.29 per Bbl realized during the three months ended June 30, 2012 as compared to a weighted average oil price of $99.72 per Bbl realized during the three months ended June 30, 2011. The decrease in natural gas revenues reflects a decline in natural gas production by about 25% to approximately 3.1 Bcf in the second quarter of 2012 as compared to approximately 4.1 Bcf in the second quarter of 2011. This decline in natural gas production results from several factors, two of which are the voluntary curtailment of natural gas production by the operators of some of Matador’s non-operated Haynesville shale wells in Northwest Louisiana and the flaring of a portion of the natural gas produced from newly drilled Eagle Ford shale wells in South Texas as a result of intermittent pipeline constraints and awaiting the completion of permanent production facilities. This decrease in natural gas revenues also results from a significantly lower weighted average natural gas price of $2.17 per Mcf realized during the three months ended June 30, 2012 as compared to a weighted average natural gas price of $3.88 per Mcf realized during the three months ended June 30, 2011.
Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011Oil production increased almost seven-fold to approximately 485,000 Bbl of oil, or about 2,670 Bbl of oil per day, during the first six months of 2012 as compared to approximately 70,000 Bbl of oil, or about 390 Bbl of oil per day, during the first six months 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 8,380 BOE per day (32% oil) during the first half of 2012 from approximately 7,160 BOE per day (5% oil) during the comparable period of 2011. Total realized revenues, including realized gain on derivatives, increased 95% to $73.0 million for the six months ended June 30, 2012 as compared to $37.4 million for the six months ended June 30, 2011. Oil and natural gas revenues increased 89% to $65.2 million during the first six months of 2012 from $34.6 million during the comparable period in 2011. This increase in oil and natural gas revenues reflects an increase in oil revenues of $44.2 million and a decrease in natural gas revenues of $13.5 million between the respective periods. Oil revenues increased almost eight-fold to $51.0 million for the six months ended June 30, 2012 as compared to $6.8 million for the six months ended June 30, 2011. Adjusted EBITDA Adjusted EBITDA, a non-GAAP financial measure, increased 82% to $27.9 million for the three months ended June 30, 2012 as compared to $15.3 million for the three months ended June 30, 2011. Sequentially, Adjusted EBITDA increased 31% to $27.9 million during the second quarter of 2012 from $21.3 million during the first quarter of 2012. Adjusted EBITDA increased 93% to $49.3 million for the six months ended June 30, 2012 from $25.5 million during the comparable period in 2011. Notably, the Adjusted EBITDA of $49.3 million reported for the first half of 2012 compares to an Adjusted EBITDA of $49.9 million reported for all of 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 increased almost eight-fold to approximately 6.7 million Bbl at June 30, 2012 from 0.9 million Bbl at June 30, 2011. Proved oil reserves at June 30, 2012 increased 77% from 3.8 million Bbl at December 31, 2011. At June 30, 2012, total proved reserves were approximately 19.1 million BOE, including approximately 6.7 million Bbl of oil (35% oil) and 73.9 Bcf of natural gas, with a PV-10 of $303.4 million (Standardized Measure of $281.5 million). At June 30, 2011, total proved reserves were approximately 26.3 million BOE, including approximately 0.9 million Bbl of oil (3% oil) and 152.5 Bcf of natural gas, with a PV-10 of $144.4 million (Standardized Measure of $134.2 million). At December 31, 2011, total proved reserves were approximately 32.2 million BOE, including approximately 3.8 million Bbl of oil (12% oil) and 170.4 Bcf of natural gas, with a PV-10 of $248.7 million (Standardized Measure of $215.5 million). 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. As a result of declining natural gas prices, at June 30, 2012, the Company removed almost all of its previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana from its estimated total proved reserves, most of which were associated with non-operated properties. As the leasehold acreage associated with these previously classified proved undeveloped natural gas reserves is held by production from existing Haynesville wells, however, these natural gas volumes remain available to be developed by the operator or Matador at a future time when natural gas prices improve, so long as the producing wells holding this acreage continue to produce as necessary to maintain held-by-production status.
Net Income (Loss)For the quarter ended June 30, 2012, Matador reported a net loss of approximately $6.7 million and a loss of $0.12 per common share compared to net income of approximately $7.2 million and earnings of $0.17 per Class A common share and $0.23 per Class B common share for the quarter ended June 30, 2011. The Company recorded a non-cash, net charge of $21.3 million to its consolidated statement of operations for the three months ended June 30, 2012 as a result of a full-cost ceiling impairment. For the six months ended June 30, 2012, Matador reported a net loss of approximately $2.9 million and a loss of $0.06 per common share compared to a net loss of approximately $20.4 million and a loss of $0.48 per Class A common share and $0.35 per Class B common share for the six months ended June 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 June 30, 2012. Sequential Financial Results
- Oil production increased 43% to approximately 285,000 Bbl, or about 3,130 Bbl of oil per day in the second quarter of 2012 from approximately 200,000 Bbl, or about 2,200 Bbl of oil per day, in the first quarter of 2012.
- Oil and natural gas revenues increased 24% to $36.1 million in the second quarter of 2012 from $29.2 million in the first quarter of 2012.
- Adjusted EBITDA increased 31% to $27.9 million in the second quarter of 2012 from $21.3 million in the first quarter of 2012.
Lease Operating Expenses (“LOE”)Lease operating expenses increased to $6.4 million (or $8.02 per BOE) from $2.0 million (or $2.70 per BOE) for the three months ended June 30, 2011. The increase in lease operating expenses was primarily attributable to the overall increase in oil production, as well as the costs associated with renting temporary production equipment monitored by 24-hour contract personnel in order to produce newly completed Eagle Ford shale wells while constructing new or additional production facilities on certain properties. Using these temporary test facilities resulted in higher operating costs from these properties than the Company anticipates going forward, now that the permanent production facilities, natural gas pipeline connections and other infrastructure on most of these recently drilled properties are complete. As new properties are drilled in the Eagle Ford shale throughout the remainder of 2012, however, initial wells on these properties are also expected to be produced through rental test equipment until more permanent facilities can be constructed and installed. Depletion, depreciation and amortization (“DD&A”) Depletion, depreciation and amortization expenses increased to $19.9 million (or $25.04 per BOE) for the three months ended June 30, 2012 from $8.2 million (or $11.23 per BOE) for the three months ended June 30, 2011. This increase in depletion, depreciation and amortization expense was attributable to the decrease in total proved oil and natural gas reserves at June 30, 2012. This increase was also due in part to the increase in total oil and natural gas production during the three months ended June 30, 2012, as well as to the higher drilling and completions costs on a per BOE basis associated with oil reserves added in the Eagle Ford shale in South Texas as compared with the Haynesville shale natural gas assets in Northwest Louisiana. Full-cost ceiling impairment At June 30, 2012, Matador recorded a non-cash, net charge to operations of $21.3 million resulting from a full-cost ceiling impairment, including a charge of $33.2 million to its net capitalized costs and a deferred income tax credit of $11.9 million. This impairment was primarily attributable to the continued decline in natural gas prices, resulting in the removal of almost all of the Company’s previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana from its estimated total proved reserves, most of which were associated with non-operated properties. As a non-cash item, the full-cost ceiling impairment has no impact on the Company’s net cash flows or Adjusted EBITDA as reported.
General and administrative (“G&A”)General and administrative expenses increased to $4.1 million (or $5.15 per BOE) for the three months ended June 30, 2012 as compared to $3.1 million (or $4.25 per BOE) for the three months ended June 30, 2011. The increase in general and administrative expenses was attributable primarily to 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 six months of 2012, Matador’s operations were focused on the exploration and development of its Eagle Ford shale properties in South Texas. In the second quarter of 2012 specifically, 6 gross/5.9 net operated and 1 gross/0.2 net non-operated Eagle Ford shale wells were completed and placed on production. Four of these operated wells were on the Danysh/Pawelek lease in Karnes County, one on the Northcut lease in LaSalle County and one on the Glasscock Ranch lease in Zavala County. Three of the wells on the Danysh/Pawelek lease began producing at various times during the month of June 2012, and the Glasscock Ranch #1H well began producing at the very end of June. As a result, these four wells did not contribute fully to the second quarter production volumes. Matador currently has two contracted drilling rigs operating in South Texas: one in LaSalle County and one in Karnes County. After focusing primarily on its Martin Ranch lease in LaSalle County during the first quarter of 2012, Matador turned its attention to drilling some of its other properties in both the eastern and western parts of the play during the second quarter of 2012, including starting to drill its first test wells in Zavala County during the second quarter of 2012. Matador drilled three of the Danysh/Pawelek wells in Karnes County back-to-back to save drilling costs, but also delayed the completion of the first two wells until all three could be completed back-to-back. This enabled the Company to test different stimulation treatments and flow back operations on three similar Eagle Ford wells in essentially the same location. Early results from these tests and others in LaSalle County indicate improved well performance as a result of recent fracture treatment modifications. Further, Matador’s operations group has begun flowing back wells on smaller chokes after stimulation, which appears to keep the wells flowing longer before experiencing liquid loading problems and may improve their long-term performance. Drilling and stimulating wells back-to-back reduces costs and flowing wells back on smaller chokes may lead to improved well performance, but such operations also lead to restricted production volumes in the short-term. As a result, oil production, although up 43% sequentially in the second quarter of 2012, has not grown quite as quickly as anticipated. Nevertheless, Matador believes these operational improvements should lead to better results in the long run and will continue to direct its operational decisions toward achieving better long-term well performance and lower costs.
Matador is also currently testing 80-acre spacing on one of its Eagle Ford properties and plans additional 80-acre tests on other properties before the end of 2012. If successful, closer well spacing would increase the number of Eagle Ford locations that can be drilled. In addition, Matador is negotiating a natural gas gathering, transportation and processing agreement, including firm transportation and processing, for most of its operated natural gas production in South Texas. The Company expects to complete this agreement during the third quarter of 2012.Results from the Company’s first Eagle Ford shale test in Zavala County, Texas, the Glasscock Ranch #1H well, have been disappointing thus far, although the well is producing and the installation of artificial lift has helped stabilize the well’s oil production rate. Two additional wells have been drilled on the Zavala acreage, one in the lower Austin Chalk/upper Eagle Ford (“Chalkleford”) and a second infill location in the upper Austin Chalk. Both of these wells have just been placed on production, and there is not sufficient production history available at this time to provide a clear assessment of the long-term performance of these wells or how they may respond to artificial lift. In addition, the Company has just completed and placed on production two wells on its Love lease in DeWitt County, Texas. To enhance well productivity and to save drilling and completion costs, these wells were drilled back-to-back and stimulated together using the “zipper-frac” technique. Early results from these wells suggest that they may be the best two Eagle Ford wells the Company has drilled to date. Haynesville Shale – Northwest Louisiana Matador has no plans to drill any operated Haynesville shale wells in 2012, but is participating in several non-operated Haynesville wells where it has small 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 six 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)Matador and its partner are currently finalizing commercial arrangements under which a horizontal test of the Meade Peak Shale would be drilled later this year. This test is anticipated to be a horizontal lateral drilled out of the Crawford Federal #1 vertical wellbore that was drilled and cored through the Meade Peak shale and then suspended in December 2011 for further evaluation. Subject to final terms of the agreement, 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 in early 2013. During the second quarter of 2012, Matador also replaced its 2012 Eagle Ford shale drilling inventory with acquisitions of approximately 2,800 gross and net acres, including approximately 1,500 net acres in LaSalle County, 400 net acres in Gonzales County and 900 net acres in Wilson County, Texas. This acreage is prospective for the Eagle Ford and other targets and is located near the Company’s existing leasehold in South Texas. Liquidity Update At June 30, 2012, the Company’s borrowing base under its senior secured revolving credit agreement was $125.0 million, with $60.0 million of outstanding long-term borrowings and approximately $1.3 million in outstanding letters of credit. These borrowings bore interest at approximately 3.3% per annum. In July and August 2012, Matador borrowed an additional $30.0 million under its credit agreement to finance a portion of its working capital requirements and capital expenditures. At June 30, 2012, Matador has incurred approximately $146.7 million or about 47% of its anticipated 2012 capital expenditures budget of $313.0 million. This includes approximately $12.3 million incurred to acquire additional leasehold acreage primarily in the Eagle Ford shale, but not including its recent acquisition of acreage in the Wolfbone play. Overall, as of June 30, 2012, the Company is executing its 2012 drilling program largely as planned and remains within its anticipated capital expenditure budget for 2012.
Matador is currently negotiating an amended and restated credit facility that may increase the Company’s borrowing capacity to up to $200 million primarily as a result of its increased oil reserves at June 30, 2012. The Company expects the amended and restated credit facility to close during the third quarter of 2012 and to include an expanded bank group.Hedging Positions For the remainder of 2012, Matador has hedged 720,000 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 remainder of 2012, Matador has hedged 4.6 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. 2012 Guidance Update Matador is revising its expected 2012 annual oil production downward to 1.2 to 1.4 million barrels from its previous guidance of 1.4 to 1.5 million barrels. Matador reaffirms its previous 2012 guidance announced on March 7, 2012 and May 14, 2012 for (1) estimated capital spending of $313.0 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 billion cubic feet. It is important to note that Matador believes its previous oil production guidance is still achievable at the lower end of the range, or 1.4 million barrels, but achieving this production target may not be the right thing to do. Rather than focusing on the 1.4 to 1.5 million barrel oil production target for the remainder of 2012, Matador intends to emphasize opportunities, as explained in the Operations Update, to reduce costs and implement certain production practices and techniques that may help maximize long-term well performance and shareholder value.
Conference Call InformationThe Company will host a conference call on Wednesday, August 15, 2012, at 9:00 a.m. Central Time to discuss the second quarter 2012 financial and operational results. To access the conference call, domestic participants should dial (800) 299-9086 and international participants should dial (617) 786-2903. The participant passcode is 28020411. 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. Domestic participants accessing the telephonic replay should dial (888) 286-8010 and international participants should dial (617) 801-6888. The participant passcode is 45702537. The replay for the event will also be available on the Company’s website at www.matadorresources.com through Wednesday, August 22, 2012. 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.
Matador Resources Company and SubsidiariesCONDENSED CONSOLIDATED BALANCE SHEETS – UNAUDITED
|(In thousands, except par value and share data)|
|June 30,||December 31,|
|Cash and cash equivalents||$||9,432||$||10,284|
|Certificates of deposit||266||1,335|
|Oil and natural gas revenues||11,898||9,237|
|Joint interest billings||2,378||2,488|
|Lease and well equipment inventory||1,381||1,343|
|Total current assets||44,582||36,276|
|Property and equipment, at cost|
|Oil and natural gas properties, full-cost method|
|Unproved and unevaluated||166,230||162,598|
|Other property and equipment||22,102||18,764|
|Less accumulated depletion, depreciation and amortization||(269,766||)||(205,442||)|
|Net property and equipment||482,592||399,865|
|Deferred income taxes||4,594||1,594|
|Total other assets||10,515||3,328|
|LIABILITIES AND SHAREHOLDERS' EQUITY|
|Borrowings under Credit Agreement||-||25,000|
|Deferred income taxes||5,376||3,024|
|Dividends payable - Class B||-||69|
|Other current liabilities||56||177|
|Total current liabilities||64,062||74,576|
|Borrowings under Credit Agreement||60,000||88,000|
|Asset retirement obligations||4,363||3,935|
|Other long-term liabilities||1,487||1,060|
|Total long-term liabilities||65,850||93,378|
|Common stock - Class A, $0.01 par value, 80,000,000 shares|
|authorized; 56,691,718 and 42,916,668 shares issued;|
|55,502,543 and 41,737,493 shares outstanding, respectively||566||429|
|Common stock - Class B, $0.01 par value, zero and 2,000,000 shares|
|authorized; zero and 1,030,700 shares issued and outstanding, respectively||-||10|
|Additional paid-in capital||402,622||263,562|
|Treasury stock, at cost, 1,189,175 and 1,179,175 shares, respectively||(10,787||)||(10,765||)|
|Total shareholders' equity||407,777||271,515|
|Total liabilities and shareholders' equity||$||537,689||$||439,469|
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS – UNAUDITED
|(In thousands, except per share data)|
|Three Months Ended June 30,||Six Months Ended June 30,|
|Oil and natural gas revenues||$||36,078||$||20,864||$||65,242||$||34,562|
|Realized gain on derivatives||4,713||952||7,776||2,802|
|Unrealized gain (loss) on derivatives||15,114||332||11,844||(1,336||)|
|Production taxes and marketing||2,619||1,654||4,783||2,954|
|Depletion, depreciation and amortization||19,913||8,179||31,119||15,290|
|Accretion of asset retirement obligations||58||57||111||96|
|Full-cost ceiling impairment||33,205||-||33,205||35,673|
|General and administrative||4,093||3,094||7,882||5,712|
|Operating (loss) income||(10,358||)||7,195||(3,258||)||(27,271||)|
|Other income (expense)|
|Net loss on asset sales and inventory impairment||(60||)||-||(60||)||-|
|Interest and other income||30||94||103||166|
|Total other expense||(31||)||(89||)||(266||)||(124||)|
|(Loss) income before income taxes||(10,389||)||7,106||(3,524||)||(27,395||)|
|Income tax provision (benefit)|
|Total income tax benefit||(3,713||)||(46||)||(649||)||(6,952||)|
|Net (loss) income||$||(6,676||)||$||7,152||$||(2,875||)||$||(20,443||)|
|Earnings (loss) per common share|
|Weighted average common shares outstanding|
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – UNAUDITED
|Six Months Ended June 30,|
|Adjustments to reconcile net loss to net cash|
|provided by operating activities|
|Unrealized (gain) loss on derivatives||(11,844||)||1,336|
|Depletion, depreciation and amortization||31,119||15,290|
|Accretion of asset retirement obligations||111||96|
|Full-cost ceiling impairment||33,205||35,673|
|Stock option and grant expense||(333||)||159|
|Restricted stock and restricted stock units expense||161||22|
|Deferred income tax benefit||(649||)||(6,906||)|
|Loss on asset sales and inventory impairment||60||-|
|Changes in operating assets and liabilities|
|Lease and well equipment inventory||(98||)||(1||)|
|Accounts payable, accrued liabilities and other liabilities||1,687||(3,330||)|
|Advances from joint interest owners||-||(723||)|
|Other long-term liabilities||427||(125||)|
|Net cash provided by operating activities||51,526||19,531|
|Oil and natural gas properties capital expenditures||(134,425||)||(89,632||)|
|Expenditures for other property and equipment||(3,521||)||(1,722||)|
|Purchases of certificates of deposit||(266||)||(2,663||)|
|Maturities of certificates of deposit||1,335||2,928|
|Net cash used in investing activities||(136,877||)||(91,089||)|
|Repayments of borrowings under Credit Agreement||(123,000||)||-|
|Borrowings under Credit Agreement||70,000||60,000|
|Proceeds from issuance of common stock||146,510||592|
|Swing sale profit contribution||24||-|
|Cost to issue equity||(11,599||)||(758||)|
|Proceeds from stock options exercised||2,660||725|
|Payment of dividends - Class B||(96||)||(137||)|
|Net cash provided by financing activities||84,499||60,422|
|Decrease in cash and cash equivalents||(852||)||(11,136||)|
|Cash and cash equivalents at beginning of period||10,284||21,059|
|Cash and cash equivalents at end of period||$||9,432||$||9,923|
SELECTED OPERATING DATA – UNAUDITED
|Three Months Ended June 30,||Six Months Ended June 30,|
|Net Production Volumes:|
|Natural gas (Bcf)||3.1||4.1||6.2||7.4|
|Total oil equivalents (MBOE) (1),(2)||795||728||1,525||1,295|
|Average net daily production (BOE/d) (2)||8,738||8,004||8,380||7,157|
|Average Sales Prices:|
|Oil, with realized derivatives (per Bbl)||$||105.82||$||99.72||$||106.54||$||96.86|
|Oil, without realized derivatives (per Bbl)||$||103.29||$||99.72||$||105.06||$||96.86|
|Natural gas, with realized derivatives (per Mcf)||$||3.48||$||4.11||$||3.42||$||4.16|
|Natural gas, without realized derivatives (per Mcf)||$||2.17||$||3.88||$||2.29||$||3.78|
|Operating Expenses per BOE:|
|Production taxes and marketing||$||3.29||$||2.27||$||3.14||$||2.28|
|Depletion, depreciation and amortization||$||25.04||$||11.23||$||20.40||$||11.80|
|General and administrative||$||5.15||$||4.25||$||5.17||$||4.41|
|(1) Thousands of barrels of oil equivalent.|
|(2) Estimated using a conversion ratio of one Bbl per six Mcf.|
|At June 30, (1)||At December 31, (1)|
|Estimated proved reserves:|
|Natural Gas (Bcf)||73.9||152.5||170.4|
|Total (MBOE) (2)||19,052||26,294||32,194|
|Estimated proved developed reserves:|
|Natural Gas (Bcf)||54.0||51.1||56.5|
|Estimated proved undeveloped reserves:|
|Natural Gas (Bcf)||20.0||101.4||113.9|
|PV-10 (in millions)||$||303.4||$||144.4||$||248.7|
|Standardized Measure (in millions)||$||281.5||$||134.2||$||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.|
Adjusted EBITDAThe 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 net 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. 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 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.
|Three Months Ended||Six Months Ended||Three Months Ended||Three Months Ended|
|June 30,||June 30,||June 30,||June 30,||March 31,||December 31,|
|Unaudited Adjusted EBITDA reconciliation to Net Income (Loss):|
|Net (loss) income||$||(6,676||)||$||7,153||$||(2,875||)||$||(20,443||)||$||3,801||$||3,416|
|Total income tax benefit||(3,713||)||(46||)||(649||)||(6,952||)||3,064||1,430|
|Depletion, depreciation and amortization||19,914||8,180||31,119||15,291||11,205||9,175|
|Accretion of asset retirement obligations||58||57||111||96||53||51|
|Full-cost ceiling impairment||33,205||-||33,205||35,673||-||-|
|Unrealized (gain) loss on derivatives||(15,114||)||(332||)||(11,844||)||1,336||3,270||(3,604||)|
|Stock option and grant expense||41||117||(333||)||159||(374||)||1,507|
|Restricted stock and restricted stock units expense||150||11||161||22||11||8|
|Net loss on asset sales and inventory impairment||60||-||60||-||-||154|
|Three Months Ended||Six Months Ended||Three Months Ended||Three Months Ended|
|June 30,||June 30,||June 30,||June 30,||March 31,||December 31,|
|Unaudited Adjusted EBITDA reconciliation to Net Cash Provided by|
|Net cash provided by operating activities||$||46,416||$||6,799||$||51,526||$||19,531||$||5,110||$||27,425|
|Net change in operating assets and liabilities||(18,491||)||8,387||(2,571||)||5,697||15,920||(15,288||)|
|Current income tax (benefit) provision||-||(46||)||-||(46||)||-||-|