Halcón Resources Gives Update on Utica Shale Operations
Halcón Resources has issued a press release detailing their 2012 fourth quarter and full year financial results as well as operational updates. Here is the portion related to the Utica shale:
HOUSTON, TEXAS , Feb. 27, 2013 (GLOBE NEWSWIRE) -- Halcón Resources Corporation (NYSE:HK) ("Halcón" or the "Company") today announced its fourth quarter and full year 2012 financial results and provided an operational update.
Floyd C. Wilson , Chairman and Chief Executive Officer, stated, "Halcón has been public for about a year now and we have built an oil company with core assets in some of the most prolific established and emerging unconventional resource plays in the lower 48. Our balance sheet is healthy and we are well positioned to execute on our business plan. We are in the early innings of implementing efficiencies and performance enhancements in our core areas with a focus on growing production, reserves and cash flow."
Utica /Point Pleasant
Tuscaloosa Marine Shale ("TMS")
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Utica /Point Pleasant
The Company currently has approximately 130,000 net acres leased or under contract in the play and expects to spud 20 to 25 gross wells on its operated acreage in 2013 with an average working interest of approximately 91% and a drilling and completions budget of approximately$200 million . The first ten wells will be drilled to delineate acreage, which will allow for a more focused approach to wells drilled in the second half of 2013. Halcón currently operates two rigs in the play and expects to add one to two additional rigs by year end.
TheAllam 1H (TMD 14,300', 5,580' lateral) inVenango County, Pennsylvania and thePhillips 1H (TMD 12,411', 5,360' lateral) inMercer County, Pennsylvania have each been drilled and completed with a 21 stage and 20 stage frac, respectively, and are currently resting for 60 days. Production tests are expected to occur on these two wells in the second quarter of 2013.
The full release is viewable after the jump.There are currently two wells resting after completion, two wells being completed or waiting on completion and two wells being drilled. HFS continues to identify and implement infrastructure solutions in the play. Third party infrastructure solutions will be utilized if available and competitive; however, consistent with the HFS strategy, a multi-modal approach to building and owning infrastructure is underway.
February 28, 2013
Halcón Resources Announces Fourth Quarter and Full Year 2012 Financial Results and Provides Operational Update
2012 Average Net Daily Production Increases by 128%
Proved Reserves Grow by 417%
Bakken/Three Forks and Woodbine Well Results Continue to Improve
Fourth Quarter and Full Year 2012 Financial Results
Halcón generated revenues of $124.7 million for the quarter ended December 31, 2012 , compared to $25.6 million for the quarter ended December 31, 2011 . Revenues for the full year 2012 were $247.9 million , compared to $103.7 million for the full year 2011. The increases were primarily attributable to incremental production volumes related to the acquisitions of GeoResources, Inc. ("GeoResources"), certain producing and undeveloped assets in East Texas ("East Texas Assets") and two entities owning certain producing and undeveloped assets in the Williston Basin ("Williston Basin Assets").
Production for the three months and full year ended December 31, 2012 increased by 349% and 128% to 18,348 barrels of oil equivalent per day (Boe/d) and 9,404 Boe/d, respectively, compared to the same periods of 2011. Fourth quarter 2012 production was comprised of 75% oil, 6% natural gas liquids (NGLs) and 19% natural gas. The Company divested approximately 500 Boe/d of certain conventional assets in South Louisiana inNovember 2012 , which impacted quarterly production by approximately 150 Boe/d. In addition, due to gas infrastructure constraints, approximately 6 million cubic feet per day of net gas production (primarily related to the recently acquired Williston Basin Assets) is currently being flared. The gas flaring impacted production in the fourth quarter 2012 by approximately 300 Boe/d.
Taking into account the effect of hedges, Halcón realized 104% of the average NYMEX oil price, 44% of the average NYMEX oil price for NGLs and 102% of the average NYMEX natural gas price during the fourth quarter 2012. Similarly, for the full year 2012, the Company realized 99% of the averageNYMEX oil price, 44% of the average NYMEX oil price for NGLs and 129% of the average NYMEX natural gas price.
After adjusting for selected items primarily related to the non-cash impact of derivatives and acquisition and merger transaction costs (see Selected Item Review and Reconciliation table for additional information), Halcón reported net income of $10.5 million , or $0.02 per diluted share, and a net loss of $4.0 million , or $0.03 per diluted share, for the three months and full year ended December 31, 2012 , respectively. Before adjusting for selected items, the Company reported a net loss available to common stockholders of $8.0 million , or $0.04 per diluted share for the quarter and $142.3 million , or $0.91 per diluted share for the year.
Cash flow from operations before changes in working capital, after adjusting for selected items (see Consolidated Statements of Cash Flows and Selected Item Review and Reconciliation table for additional information), was $55.5 million , or $0.17 per diluted share, and $91.2 million , or $0.38 per diluted share, for the fourth quarter and full year 2012, respectively. Prior to adjusting for selected items, Halcón reported cash flow from operations before changes in working capital (see Consolidated Statements of Cash Flows for a reconciliation to net cash provided by operating activities) of$42.6 million , or $0.13 per diluted share, and $54.9 million , or $0.23 per diluted share, for the three months and twelve months ended December 31, 2012 , respectively.
After adjusting for selected items (see Selected Operating Data table for additional information), lease operating expense for the three month and twelve month periods ending December 31, 2012 decreased by 45% and 28% to $11.75 per Boe and $14.36 per Boe, respectively, versus the three month and twelve month periods ending December 31 , 2011. During the fourth quarter, total operating costs per unit (including lease operating expense, workover and other expense, taxes other than income and general and administrative expense), after adjusting for selected items (see Selected Operating Data table for additional information), decreased by 27% to $33.12 per Boe, compared to the same period of 2011. After adjusting for selected items (see Selected Operating Data table for additional information), total operating costs per unit for 2012 and 2011 were $37.05 per Boe and $37.41 per Boe, respectively.
Liquidity
The Company recently closed an additional $600 million in aggregate principal amount of its 8.875% senior unsecured notes due 2021 in a private offering at an issue price of 105% of par, which yielded net proceeds to Halcón of approximately $619.5 million . A portion of the proceeds were used to repay outstanding indebtedness under the Company's senior secured revolving credit facility.
As of December 31, 2012 , and pro forma for the January 2013 notes offering, Halcón had liquidity of approximately $1.2 billion , which consisted of$324.0 million in cash and $850.0 million of borrowing capacity available on its $1.5 billion senior secured revolving credit facility.
Proved Reserves
The Company's estimated proved reserves as of December 31, 2012 were 108.8 million barrels of oil equivalent (MMBoe), which represents an increase of 417% over the prior year. Year-end 2012 estimated proved reserves were 80% oil, 5% NGLs and 15% natural gas on an equivalent basis.
The present value of Halcón's estimated future oil and gas revenues, net of estimated expenses, discounted at an annual rate of 10% (PV10) is approximately $2.3 billion . In comparison, the standardized measure is approximately $1.95 billion ; the difference is attributed to the estimated future income tax expense discounted at 10%. Proved developed reserves account for 47% of total estimated proved reserves. A summary of year-over-year changes in estimated proved reserves is as follows:
| Proved Reserve Reconciliation | Oil (MBbls) | Gas (MMCf) | NGL (MBbls) | Total MBoe |
| As of | 12,371 | 40,054 | 2,010 | 21,057 |
| Extensions, discoveries and additions | 11,691 | 6,742 | 352 | 13,167 |
| Purchases | 66,240 | 71,560 | 3,433 | 81,600 |
| Sales | (1,789) | (2,025) | -- | (2,127) |
| Production | (2,415) | (4,554) | (268) | (3,442) |
| Revisions of previous estimates and pricing | 1,280 | (15,632) | (144) | (1,470) |
| As of | 87,378 | 96,145 | 5,383 | 108,785 |
The Company's estimated proved reserves at December 31, 2012 were prepared by the independent reserve engineering firm Netherland, Sewell and Associates, Inc. (NSA) in accordance with Securities and Exchange Commission guidelines.
Operational Update
The drill-bit continues to spin to the right in all of the Company's core plays, plus a few others. Halcón currently has 15 operated rigs running and expects to add several operated rigs by year-end 2013.
Bakken/Three Forks
The Company currently has working interests in approximately 130,000 net acres prospective for the Bakken and Three Forks formations in theWilliston Basin . Halcón plans to operate 6 to 8 rigs and spud 65 to 75 gross operated wells with an average working interest of approximately 63% in 2013. The Company also expects to participate in 90 to 100 gross non-operated wells in 2013 with an average working interest of 10% to 12%. Halcón is focused on the higher internal rate of return (IRR) areas and anticipates spending approximately $475 million on drilling and completions in theWilliston Basin in 2013.
Pro forma for the Williston Basin Assets acquisition that closed on December 6, 2013 , 31 wells have been put online in the play since October 1, 2012 (17 wells in the Fort Berthold area, 2 wells in the Marmon area, 10 wells in the New Home II area and 2 wells in E. Montana ).
Of the 17 wells put online in the Fort Berthold area, 8 of them were Bakken completions and 9 of them were Three Forks completions. The average initial and 30 day rates for the applicable Bakken wells were 1,544 Boe/d (83% oil) and 780 Boe/d (84% oil), respectively. These eight Bakken wells have an average effective lateral length of 10,020 feet and were completed with an average of 26 frac stages. Similarly, the average initial and 30 day rates for the applicable Three Forks wells were 1,472 Boe/d (84% oil) and 823 Boe/d (82% oil), respectively. These nine Three Forks wells have an average effective lateral length of 9,987 feet and were completed with an average of 25 frac stages.
One Bakken well and one Three Forks well was put online in the Marmon area. The initial and 30 day rates for the Bakken well were 836 Boe/d (91% oil) and 505 Boe/d (96% oil), respectively. This Bakken well had an effective lateral length of 10,023 feet and was completed with 25 frac stages. The initial and 30 day rates for the Three Forks well were 531 Boe/d (100% oil) and 245 Boe/d (90% oil), respectively. This Three Forks well had an effective lateral length of 9,872 feet and was completed with 25 frac stages.
All ten wells put online in the New Home II area were Bakken completions. The average initial and 30 day rates for the applicable wells were 646 Boe/d (90% oil) and 282 Boe/d (88% oil), respectively. These Bakken wells have an average effective lateral length of 9,742 feet and were completed with an average of 30 frac stages.
The Company does not plan to drill any wells in Eastern Montana in 2013, but the average initial and 30 day rates for the applicable Bakken wells inEastern Montana put online since October 1, 2012 were 408 Boe/d (88% oil) and 193 Boe/d (79% oil), respectively.
There are currently 95 Bakken wells producing, 6 Bakken wells being completed or waiting on completion and 5 Bakken wells being drilled on Halcón's operated acreage. Similarly, there are currently 28 Three Forks wells producing, 2 Three Forks wells being completed or waiting on completion and 3 Three Forks wells being drilled on the Company's operated acreage.
Halcón is in the process of optimizing all of its Williston Basin activities. Numerous drilling and completion modifications intended to improve economics are being implemented and should begin to yield benefits in the second quarter of 2013. Specifically, on the drilling side, the Company has begun full scale pad drilling and plans to preset surface casing, implement batch drilling on intermediate and production intervals, modify motor/bit configurations in curves and laterals, utilize a combination of geosteering tools/practices and mudlogging and incorporate new high efficiency skid capable AC rigs. On the completion side, Halcón expects to utilize core and log analysis in all areas to develop a petrophysical model, geomechanics and integrated reservoir simulation to design and optimize its completion techniques. Increasing proppant per stage to 120,000 pounds from 100,000 pounds, changing the fluid design to 28 pound from 35 pound XL gels, increasing stage density to 30 from 25, eliminating blast joints in favor of swell packers for positive isolation, conducting perf and plug completion projects in the Fort Berthold and Marmon areas and incorporating frac strings for improved safety and flow back operations are examples of other measures being taken to increase recoveries.
Woodbine
The Company currently has approximately 235,000 net acres leased or under contract across East Texas that are prospective for the Woodbine, Eagle Ford and other formations. Expectations are to spud 75 to 85 gross operated wells in 2013 with an average working interest of approximately 90%. Halcón plans to operate five to seven rigs in the play throughout the year and anticipates spending approximately $490 million on drilling and completions. Efforts will be focused on developing acreage in Leon , N. Madison and Brazos Counties in 2013. However, a 330 square mile 3D seismic survey is underway and covers the more exploratory area of the play in Madison , Grimes and Walker Counties. In addition, the Company intends to spud its first horizontal Woodbine well in Polk County in the second quarter of 2013.
Halcón has put nine wells online in the play since October 1 , 2012. The natural gas being produced from all these wells is currently being flared. Based on the amount of natural gas being flared, the Company estimates that the oil being produced from each well accounts for more than 90% of the total hydrocarbon volume.
Six of the wells are located in Leon and Northern Madison Counties have an average effective lateral length of 6,246 feet and were completed with an average of 22 frac stages. The average initial and 30 day rates for the applicable wells were 948 Boe/d and 388 Boe/d, respectively. Of these six wells, the Keeling 1H in Leon County is performing the best and had an initial rate of 1,407 Boe/d and a 30 day rate of 749 Boe/d. This well was drilled to a total measured depth of 15,897 feet with a 6,300 foot effective lateral section and was completed with a 25 stage frac.
Of the three remaining wells, two are located in Brazos County and have an average initial rate of 1,463 Boe/d. These two wells have an average effective lateral length of 6,143 feet and were completed with an average of 31 frac stages. Only one of the wells in Brazos County has been producing for at least 30 days and has an average 30 day rate of 724 Boe/d. The most recent well completed in Brazos County , the Coyote 1H, had an initial rate of 1,230 Boe/d. This well was drilled to a total measured depth of 14,333 feet with a 5,944 foot effective lateral section and was completed with a 30 stage frac. The other well is located in the more exploratory area of the play where the 3D seismic survey in underway.
There are currently 29 wells producing, 11 wells being completed or waiting on completion and 5 wells being drilled across the Company's operated acreage.
Halcón continues to modify its Woodbine drilling and completion practices in an effort to increase recoveries while reducing costs. To date, the Company has reduced hole size in the curve to 8.75 inches from 9.875 inches and eliminated intermediate casing where applicable, which results in a well cost reduction of approximately 15%. In addition, Halcón has increased the amount of proppant placed while decreasing the total volume of fluid and the associated pump time. The Company also continues to adjust its cluster configuration and count by area. Initial results are encouraging with jet lift assemblies providing for higher initial flowback rates and additional flow control. Looking ahead, Halcón anticipates costs will decline further as it continues to exploit opportunities for batch drilling and brings electric power to new and existing locations.
Halcón Field Services (HFS) is in the process of building infrastructure in the play capable of handling gas, NGLs and produced water. More than 50 miles of pipeline are planned and a processing plant with residue gas and liquids takeaway capacity is expected to be in service by the end of the first quarter 2013.
The Company currently has approximately 130,000 net acres leased or under contract in the play and expects to spud 20 to 25 gross wells on its operated acreage in 2013 with an average working interest of approximately 91% and a drilling and completions budget of approximately $200 million . The first ten wells will be drilled to delineate acreage, which will allow for a more focused approach to wells drilled in the second half of 2013. Halcón currently operates two rigs in the play and expects to add one to two additional rigs by year end.
The Allam 1H (TMD 14,300', 5,580' lateral) in Venango County, Pennsylvania and the Phillips 1H (TMD 12,411', 5,360' lateral) in Mercer County, Pennsylvania have each been drilled and completed with a 21 stage and 20 stage frac, respectively, and are currently resting for 60 days. Production tests are expected to occur on these two wells in the second quarter of 2013.
There are currently two wells resting after completion, two wells being completed or waiting on completion and two wells being drilled. HFS continues to identify and implement infrastructure solutions in the play. Third party infrastructure solutions will be utilized if available and competitive; however, consistent with the HFS strategy, a multi-modal approach to building and owning infrastructure is underway.
The Company currently has approximately 75,000 net acres prospective for the TMS in Louisiana. The first well drilled, the Broadway H1 in Rapides Parish , is currently being completed with a 21 stage frac. The well was drilled to a total measured depth of 19,442 feet with a 5,192 foot effective lateral section.
In late January, Halcón spud a stratigraphic test well, the Lambright, located 16 miles northwest of the Broadway 1H in Rapides Parish. This vertical test found the zone too thin for commercial production.
The Company intends to review completion results of the Broadway H1 prior to implementing a development strategy.
Conference Call and Webcast Information
Halcón Resources Corporation (NYSE:HK) has scheduled a conference call for Thursday, February 28, 2013 , at 10:00 a.m. EST (9:00 a.m. CST ). To participate in the conference call, dial (877) 810-3368 for domestic callers, and (914) 495-8561 for international callers a few minutes before the call begins and reference Halcón Resources conference ID 96884175. The conference call will also be webcast live over the Internet on Halcón Resources' website at http://www.halconresources.com in the Investor Relations section under Events & Presentations. A telephonic replay of the call will be available approximately two hours after the live broadcast ends and will be accessible until March 7 , 2013. To access the replay, dial (855) 859-2056 for domestic callers or (404) 537-3406 for international callers, in both cases referencing conference ID 96884175.
About Halcón Resources
Halcón Resources Corporation is an independent energy company engaged in the acquisition, production, exploration and development of onshore oil and natural gas properties in the United States .
For more information contact Scott Zuehlke , Vice President of Investor Relations, at 832-538-0314 or szuehlke@halconresources.com.
Forward-Looking Statements
This release may contain 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. Statements that are not strictly historical statements constitute forward-looking statements and may often, but not always, be identified by the use of such words such as "expects", "believes", "intends", "anticipates", "plans", "estimates", "potential", "possible", or "probable" or statements that certain actions, events or results "may", "will", "should", or "could" be taken, occur or be achieved. Additionally, initial production rates, average 30 day production rates and improvements mentioned herein are not necessarily indicative of future production rates or performance. Forward-looking statements are based on current beliefs and expectations and involve certain assumptions or estimates that involve various risks and uncertainties that could cause actual results to differ materially from those reflected in the statements. These risks include, but are not limited to, those set forth in the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2012 and other filings submitted by the Company to the U.S. Securities and Exchange Commission ("SEC"), copies of which may be obtained from the SEC's website at www.sec.gov or through the Company's website at www.halconresources.com. Readers should not place undue reliance on any such forward-looking statements, which are made only as of the date hereof. The Company has no duty, and assumes no obligation, to update forward-looking statements as a result of new information, future events or changes in the Company's expectations.
| HALCÓN RESOURCES CORPORATION | ||||
| CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) | ||||
| (In thousands, except share and per share amounts) | ||||
| Three Months Ended | Years Ended | |||
| 2012 | 2011 | 2012 | 2011 | |
| Operating revenues: | ||||
| Oil, natural gas and natural gas liquids sales: | ||||
| Oil | $ 114,006 | $ 20,818 | $ 223,048 | $ 82,968 |
| Natural gas | 5,775 | 2,421 | 12,458 | 10,673 |
| Natural gas liquids | 4,082 | 2,298 | 11,088 | 9,880 |
| Total oil, natural gas and natural gas liquids sales | 123,863 | 25,537 | 246,594 | 103,521 |
| Other | 791 | 44 | 1,351 | 168 |
| Total operating revenues | 124,654 | 25,581 | 247,945 | 103,689 |
| Operating expenses: | ||||
| Production: | ||||
| Lease operating | 19,828 | 8,000 | 49,941 | 30,043 |
| Workover and other | 2,045 | 935 | 4,429 | 1,967 |
| Taxes other than income | 9,605 | 1,791 | 19,253 | 7,214 |
| Restructuring | 674 | 1,071 | 2,406 | 1,071 |
| General and administrative | 45,022 | 7,639 | 111,349 | 20,609 |
| Depletion, depreciation and accretion | 55,623 | 6,109 | 90,284 | 22,986 |
| Total operating expenses | 132,797 | 25,545 | 277,662 | 83,890 |
| Income (loss) from operations | (8,143) | 36 | (29,717) | 19,799 |
| Other income (expenses): | ||||
| Interest expense and other | (8,973) | (3,561) | (31,223) | (17,879) |
| Net gain (loss) on derivative contracts | (5,277) | (13,156) | (6,126) | 3,479 |
| Total other income (expenses) | (14,250) | (16,717) | (37,349) | (14,400) |
| Income (loss) before income taxes | (22,393) | (16,681) | (67,066) | 5,399 |
| Income tax benefit (provision) | 14,352 | 4,477 | 13,181 | (6,802) |
| Net income (loss) | (8,041) | (12,204) | (53,885) | (1,403) |
| Non-cash preferred dividend | -- | -- | (88,445) | -- |
| Net income (loss) available to common stockholders | $ (8,041) | $ (12,204) | $ (142,330) | $ (1,403) |
| Net income (loss) per share of common stock: | ||||
| Basic | $ (0.04) | $ (0.46) | $ (0.91) | $ (0.05) |
| Diluted | $ (0.04) | $ (0.46) | $ (0.91) | $ (0.05) |
| Weighted average common shares outstanding: | ||||
| Basic | 228,075 | 26,270 | 156,494 | 26,258 |
| Diluted | 228,075 | 26,270 | 156,494 | 26,258 |
| HALCÓN RESOURCES CORPORATION | ||
| CONSOLIDATED BALANCE SHEETS (Unaudited) | ||
| (In thousands, except share and per share amounts) | ||
| 2012 | 2011 | |
| Current assets: | ||
| Cash | $ 2,506 | $ 49 |
| Accounts receivable | 262,809 | 10,288 |
| Receivables from derivative contracts | 7,428 | 1,850 |
| Current portion of deferred income taxes | 5,307 | 1,080 |
| Inventory | 3,116 | 4,310 |
| Prepaids and other | 6,691 | 2,729 |
| Total current assets | 287,857 | 20,306 |
| Oil and natural gas properties (full cost method): | ||
| Evaluated | 2,669,245 | 715,666 |
| Unevaluated | 2,326,598 | -- |
| Gross oil and natural gas properties | 4,995,843 | 715,666 |
| Less - accumulated depletion | (588,207) | (501,993) |
| Net oil and natural gas properties | 4,407,636 | 213,673 |
| Other operating property and equipment: | ||
| Gas gathering and other operating assets | 59,748 | 9,979 |
| Less - accumulated depreciation | (8,119) | (7,133) |
| Net other operating property and equipment | 51,629 | 2,846 |
| Other noncurrent assets: | ||
| Goodwill | 227,762 | -- |
| Receivables from derivative contracts | 371 | 2,050 |
| Debt issuance costs, net of amortization | 51,609 | 5,966 |
| Deferred income taxes | -- | 21,355 |
| Equity in oil and gas partnerships | 11,137 | -- |
| Funds in escrow | 2,090 | 560 |
| Other | 934 | 418 |
| Total assets | $ 5,041,025 | $ 267,174 |
| Current liabilities: | ||
| Accounts payable and accrued liabilities | $ 590,551 | $ 25,061 |
| Liabilities from derivative contracts | 10,429 | 1,855 |
| Asset retirement obligations | 2,319 | 1,010 |
| Promissory notes | 74,669 | -- |
| Total current liabilities | 677,968 | 27,926 |
| Long-term debt | 2,034,498 | 202,000 |
| Other noncurrent liabilities: | ||
| Liabilities from derivative contracts | 2,461 | 2,855 |
| Asset retirement obligations | 72,813 | 32,703 |
| Deferred income taxes | 160,055 | -- |
| Other | 10 | 10 |
| Commitments and contingencies | ||
| Mezzanine equity: | ||
| Preferred stock: 1,000,000 shares of | 695,238 | -- |
| Stockholders' equity: | ||
| Common stock: 336,666,666 and 33,333,333 shares of | 26 | 3 |
| Additional paid-in capital | 1,681,717 | 229,414 |
| Treasury stock: 1,649,909 and 1,450,131 shares at | (9,298) | (7,159) |
| Accumulated deficit | (274,463) | (220,578) |
| Total stockholders' equity | 1,397,982 | 1,680 |
| Total liabilities and stockholders' equity | $ 5,041,025 | $ 267,174 |
| HALCÓN RESOURCES CORPORATION | ||||
| CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) | ||||
| (In thousands) | ||||
| Three Months Ended | Years Ended | |||
| 2012 | 2011 | 2012 | 2011 | |
| Cash flows from operating activities: | ||||
| Net income (loss) | $ (8,041) | $ (12,204) | $ (53,885) | $ (1,403) |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||
| Depletion, depreciation and accretion | 55,623 | 6,109 | 90,284 | 22,986 |
| Deferred income tax provision (benefit) | (14,090) | (4,580) | (13,060) | 6,549 |
| Share-based compensation | 707 | 1,357 | 4,573 | 3,584 |
| Unrealized loss (gain) on derivative contracts | 8,530 | 13,437 | 11,727 | (2,954) |
| Amortization and write-off of deferred loan costs | (35) | 338 | 6,212 | 3,663 |
| Non-cash interest and amortization of discount | 767 | -- | 9,387 | 362 |
| Other expense (income) | (822) | 245 | (352) | 223 |
| Cash flow from operations before changes in working capital | 42,639 | 4,702 | 54,886 | 33,010 |
| Changes in working capital, net of acquisitions | 61,967 | 1,320 | 63,288 | (3,175) |
| Net cash provided by (used in) operating activities | 104,606 | 6,022 | 118,174 | 29,835 |
| Cash flows from investing activities: | ||||
| Oil and natural gas capital expenditures | (489,140) | (5,614) | (1,216,835) | (25,214) |
| Acquisition of | -- | -- | (579,497) | -- |
| Acquisition of East Texas Assets | -- | -- | (296,139) | -- |
| Acquisition of Williston Basin Assets | (756,056) | -- | (756,056) | -- |
| Other operating property and equipment capital expenditures | (20,512) | (169) | (38,752) | (672) |
| Proceeds received from sales of property and equipment | 10 | (425) | 564 | 48 |
| Proceeds received from sale of oil and gas assets | 21,964 | 462 | 21,964 | 462 |
| Funds held in escrow | 1,460 | -- | (1,529) | -- |
| Net cash provided by (used in) investing activities | (1,242,274) | (5,746) | (2,866,280) | (25,376) |
| Cash flows from financing activities: | ||||
| Proceeds from borrowings | 1,184,353 | 12,001 | 2,466,608 | 250,167 |
| Repayments of borrowings | (327,000) | (10,399) | (655,000) | (245,621) |
| Debt issuance costs | (29,221) | (822) | (52,878) | (7,825) |
| Offering costs | (84) | (985) | (18,619) | (985) |
| Common stock repurchased | -- | (66) | (2,139) | (183) |
| Preferred stock issued | -- | -- | 311,556 | -- |
| Preferred beneficial conversion feature | -- | -- | 88,445 | -- |
| Common stock issued | 294,000 | -- | 569,000 | -- |
| Warrants issued | -- | -- | 43,590 | -- |
| Net cash provided by (used in) financing activities | 1,122,048 | (271) | 2,750,563 | (4,447) |
| Net increase (decrease) in cash | (15,620) | 5 | 2,457 | 12 |
| Cash at beginning of period | 18,126 | 44 | 49 | 37 |
| Cash at end of period | $ 2,506 | $ 49 | $ 2,506 | $ 49 |
| Supplemental cash flow information: | ||||
| Cash paid for interest, net of capitalized interest | $ 11,344 | $ 23 | $ 11,705 | $ 554 |
| Cash paid for income taxes | (3,842) | 3,290 | 89 | 15,326 |
| Disclosure of non-cash investing and financing activities: | ||||
| Asset retirement obligations | $ 7,898 | $ 979 | $ 8,587 | $ 956 |
| Preferred dividend | -- | -- | 88,445 | -- |
| Payment-in-kind interest | -- | (362) | 14,669 | -- |
| Common stock issued for | -- | -- | 321,416 | -- |
| Common stock issued for East Texas Assets | -- | -- | 130,623 | -- |
| Common stock issued for Williston Basin Assets | 695,238 | -- | 695,238 | -- |
| Current notes payable issued for oil and natural gas properties | 74,669 | -- | 74,669 | -- |
| HALCÓN RESOURCES CORPORATION | ||||
| SELECTED OPERATING DATA | ||||
| (Unaudited) | ||||
| Three Months Ended | Years Ended | |||
| 2012 | 2011 | 2012 | 2011 | |
| Production volumes: | ||||
| Oil (MBbls) | 1,264 | 223 | 2,415 | 884 |
| Natural gas (Mmcf) | 1,914 | 677 | 4,554 | 2,662 |
| Natural gas liquids (MBbls) | 105 | 40 | 268 | 176 |
| Total (MBoe) | 1,688 | 376 | 3,442 | 1,504 |
| Average daily production (Boe) | 18,348 | 4,087 | 9,404 | 4,121 |
| Average prices: | ||||
| Oil (per Bbl) | $ 90.19 | $ 93.35 | $ 92.36 | $ 93.86 |
| Natural gas (per Mcf) | 3.02 | 3.58 | 2.74 | 4.01 |
| Natural gas liquids (per Bbl) | 38.88 | 57.45 | 41.37 | 56.14 |
| Total per Boe | 73.38 | 67.92 | 71.64 | 68.83 |
| Cash effect of derivative contracts: | ||||
| Oil (per Bbl) | $ 1.66 | $ -- | $ 0.89 | $ (2.02) |
| Natural gas (per Mcf) | 0.44 | 0.51 | 0.82 | 0.94 |
| Natural gas liquids (per Bbl) | -- | -- | -- | -- |
| Total per Boe | 1.74 | 0.91 | 1.70 | 0.49 |
| Average prices computed after cash effect of settlement of derivative contracts: | ||||
| Oil (per Bbl) | $ 91.85 | $ 93.35 | $ 93.25 | $ 91.84 |
| Natural gas (per Mcf) | 3.46 | 4.09 | 3.56 | 4.95 |
| Natural gas liquids (per Bbl) | 38.88 | 57.45 | 41.37 | 56.14 |
| Total per Boe | 75.12 | 68.83 | 73.34 | 69.32 |
| Average cost per Boe: | ||||
| Production: | ||||
| Lease operating(1) | $ 11.75 | $ 21.28 | $ 14.36 | $ 19.98 |
| Workover and other | 1.21 | 2.49 | 1.29 | 1.31 |
| Taxes other than income | 5.69 | 4.76 | 5.59 | 4.80 |
| General and administrative, as adjusted(1) | 14.47 | 16.71 | 15.81 | 11.32 |
| Restructuring costs | 0.40 | 2.85 | 0.70 | 0.71 |
| Depletion | 32.03 | 14.55 | 25.05 | 13.55 |
| (1) Represents lease operating and general and administrative costs per Boe, adjusted for items noted in the reconciliation below: | ||||
| General and administrative: | ||||
| General and administrative, as reported | $ 26.67 | $ 20.32 | $ 32.35 | $ 13.70 |
| Share-based compensation: | ||||
| Cash | -- | -- | (0.11) | -- |
| Non-cash | (0.42) | (3.61) | (0.61) | (2.38) |
| Recapitalization and change in control: | ||||
| Cash | -- | -- | (3.10) | -- |
| Non-cash | -- | -- | (0.72) | -- |
| Acquisition and merger transaction costs: | ||||
| Cash | (11.78) | -- | (12.00) | -- |
| General and administrative, as adjusted | $ 14.47 | $ 16.71 | $ 15.81 | $ 11.32 |
| Lease operating: | ||||
| Lease operating, as reported | $ 11.75 | $ 21.28 | $ 14.51 | $ 19.98 |
| Recapitalization and change in control: | ||||
| Cash | -- | -- | (0.15) | -- |
| Lease operating, as adjusted | $ 11.75 | $ 21.28 | $ 14.36 | $ 19.98 |
| Total operating costs, as reported | $ 45.32 | $ 48.85 | $ 53.74 | $ 39.79 |
| Total adjusting items | (12.20) | (3.61) | (16.69) | (2.38) |
| Total operating costs, as adjusted(2) | $ 33.12 | $ 45.24 | $ 37.05 | $ 37.41 |
| (2) Represents lease operating, workover and other expense, taxes other than income and general and administrative costs per Boe, adjusted for items noted in reconciliation above. | ||||
| HALCÓN RESOURCES CORPORATION | ||||
| SELECTED ITEM REVIEW AND RECONCILIATION (Unaudited) | ||||
| (In thousands, except per unit, per share and per mcfe amounts) | ||||
| Three Months Ended | Years Ended | |||
| 2012 | 2011 | 2012 | 2011 | |
| Unrealized loss (gain) on derivatives:(1) | ||||
| Crude oil | $ 8,936 | $ 14,265 | $ 11,606 | $ (5,341) |
| Natural gas | 146 | (1,015) | 2,117 | 72 |
| Interest rate | -- | (49) | (518) | 506 |
| Total mark-to-market non-cash charge | 9,082 | 13,201 | 13,205 | (4,763) |
| Recapitalization expenditures(2) | -- | -- | 21,980 | 2,718 |
| Restructuring(3) | 674 | -- | 2,406 | -- |
| Acquisition and merger transaction costs and other(4) | 19,882 | -- | 41,294 | -- |
| Selected items, before income taxes and preferred dividend | 29,638 | 13,201 | 78,885 | (2,045) |
| Income tax effect of selected items(5) | (11,074) | (4,783) | (28,951) | 751 |
| Selected items, net of tax and before preferred dividend | 18,564 | 8,418 | 49,934 | (1,294) |
| Non-cash preferred dividend(6) | -- | -- | 88,445 | -- |
| Selected items, net of tax | 18,564 | 8,418 | 138,379 | (1,294) |
| Net income (loss) available to common stockholders, as reported | (8,041) | (12,204) | (142,330) | (1,403) |
| Net income (loss) available to common stockholders, excluding selected items | $ 10,523 | $ (3,786) | $ (3,951) | $ (2,697) |
| Basic net income (loss) per common share, as reported | $ (0.04) | $ (0.46) | $ (0.91) | $ (0.05) |
| Impact of selected items | 0.08 | 0.32 | 0.88 | (0.05) |
| Basic net income (loss) per common share, excluding selected items | $ 0.04 | $ (0.14) | $ (0.03) | $ (0.10) |
| Diluted net income (loss) per common share, as reported | $ (0.04) | $ (0.46) | $ (0.91) | $ (0.05) |
| Impact of selected items(7) | 0.06 | 0.32 | 0.88 | (0.05) |
| Diluted net income (loss) per common share, excluding selected items | $ 0.02 | $ (0.14) | $ (0.03) | $ (0.10) |
| Cash flow from operations before changes in working capital | $ 42,639 | $ 4,702 | $ 54,886 | $ 33,010 |
| Cash components of selected items | 20,556 | -- | 57,366 | -- |
| Income tax effect of selected items(5) | (7,690) | -- | (21,052) | -- |
| Cash flow from operations before changes in working capital, adjusted for selected items | $ 55,505 | $ 4,702 | $ 91,200 | $ 33,010 |
| Cash flow from operations before changes in working capital per diluted share, adjusted for selected items | $ 0.13 | $ 0.18 | $ 0.23 | $ 1.26 |
| Impact of selected items(8) | 0.04 | -- | 0.15 | -- |
| Cash flow from operations before changes in working capital per diluted share, adjusted for selected items | $ 0.17 | $ 0.18 | $ 0.38 | $ 1.26 |
| (1) Represents the non-cash unrealized loss (gain) associated with the mark-to-market valuation of outstanding derivative contracts. | ||||
| (2) Represents costs related to the recapitalization, change in control and credit facility refinancing. | ||||
| (3) Represents costs related to relocating key administrative functions to corporate headquarters. | ||||
| (4) Represents costs primarily related to acquisitions of producing properties and mergers. | ||||
| (5) Represents tax impact using an estimated tax rate of 36.7% | ||||
| (6) Represents amortization of the non-cash preferred dividend as a result of the beneficial conversion feature of convertible preferred stock. | ||||
| (7) The impact of selected items for the three months ended | ||||
| (8) The impact of selected items for the three months and year ended | ||||
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