Exhibit 99.1
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NEWS RELEASE |
Halcón Resources Announces First Quarter 2013 Financial Results and Provides Operational Update
Average Daily Production Increases 542% Year-Over-Year
Cash Flow Per Share Increases 211% Year-Over-Year
Definitive Agreement Signed for Divestment of Eagle Ford Assets in Fayette and Gonzales Counties
HOUSTON, TEXAS — May 2, 2013 — Halcón Resources Corporation (NYSE:HK) (“Halcón” or the “Company”) today announced its first quarter 2013 financial results and provided an operational update.
After adjusting for selected items (primarily related to the non-cash impact of derivatives and acquisition and merger related transaction costs), Halcón reported net income for the three months ended March 31, 2013 of $17.5 million, or $0.05 per diluted share, compared to a net loss of $2.7 million, or $0.04 per diluted share in the comparable quarter of 2012 (see Selected Item Review and Reconciliation table for additional information). Before adjusting for selected items, the Company reported net income available to common stockholders of $5.5 million, or $0.01 per diluted share for the quarter.
Cash flow from operations before changes in working capital, after adjusting for selected items (see Condensed Consolidated Statements of Cash Flows and Selected Item Review and Reconciliation table for additional information), was $106.4 million for the quarter, or $0.28 per diluted share, compared to $6.3 million, or $0.09 per diluted share for the same period of 2012. Halcón reported cash flow from operations before changes in working capital (see Condensed Consolidated Statements of Cash Flows for a reconciliation to net cash provided by operating activities), before adjusting for selected items, of $104.8 million, or $0.27 per diluted share for the three months ended March 31, 2013.
Revenues for the first quarter of 2013 increased to $190.7 million, compared to $26.9 million for the three months ended March 31, 2012. The increase is primarily attributable to increased production volumes related to the acquisitions of GeoResources, Inc. (“GeoResources”), certain
producing assets in East Texas (“East Texas Assets”) and two entities owning certain producing assets in the Williston Basin (“Williston Basin Assets”) in 2012.
Net production for the period increased to an average of 26,022 barrels of oil equivalent per day (Boe/d), compared to 4,055 Boe/d for the three months ended March 31, 2012. First quarter 2013 production was comprised of 82% oil, 5% natural gas liquids (NGLs) and 13% natural gas.
The Company realized 99% of the average NYMEX oil price, 37% of the average NYMEX oil price for NGLs and 88% of the average NYMEX natural gas price during the first quarter of 2013, excluding the impact of derivatives.
Lease operating expense for the three month period ending March 31, 2013 decreased by 47% to $10.86 per Boe, versus the comparable period of 2012. During the first quarter of 2013, 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 35% to $30.71 per Boe, compared to the first quarter of 2012.
Floyd C. Wilson, Chairman and Chief Executive Officer, stated, “We are making progress on all fronts — significant operational improvements in the Williston Basin, dramatic improvements in lease operating expense, the recent unveiling of a new core Eagle Ford play in East Texas and encouraging flowback data from our first well in the Utica/Point Pleasant play.”
Liquidity and Capital Spending
As of March 31, 2013, Halcón had liquidity of $716.5 million, which consisted of $0.8 million in cash and $715.7 million of borrowing capacity available on its senior revolving credit facility.
During the first quarter of 2013, the Company incurred capital costs of $398.0 million on drilling and completions, $57.7 million on leasehold acquisitions and $94.8 million on infrastructure, seismic and other.
Operational Update
Bakken/Three Forks
Halcón averaged 8 operated rigs (6 in Fort Berthold, 1 in Marmon and 1 in New Home II) and spud 22 wells (17 in Fort Berthold, 1 in Marmon and 4 in New Home II) on its operated acreage in the Williston Basin during the first quarter.
The Company completed 10 wells in its Fort Berthold area during the period, five each in the Bakken and Three Forks formations. The average initial and 30 day production rates for the
applicable Bakken wells were 1,691 Boe/d (82% oil) and 889 Boe/d (85% oil), respectively. These Bakken wells have an average effective lateral length of 10,041 feet and were completed with an average of 27 frac stages. The average initial and 30 day production rates for the applicable Three Forks wells were 1,463 Boe/d (84% oil) and 613 Boe/d (79% oil), respectively. These Three Forks wells have an average effective lateral length of 9,910 feet and were completed with an average of 28 frac stages.
Halcón completed two Bakken wells in its Marmon area during the first quarter of 2013, and the average initial production rate for these wells was 1,405 Boe/d (88% oil). These two Bakken wells have an average effective lateral length of 9,704 feet and were completed with an average of 35 frac stages.
The Company completed seven Bakken wells in its New Home II area during the period. The average initial and 30 day production rates for the applicable wells was 694 Boe/d (92% oil) and 314 Boe/d (85% oil), respectively. These Bakken wells have an average effective lateral length of 9,613 feet and were completed with an average of 31 frac stages.
One Bakken well that was spud by Halcón in the fourth quarter of 2012 was completed in an operated spacing unit in McKenzie County during the first quarter of 2013. The initial and 30 day production rates for this well were 2,104 Boe/d (84% oil) and 1,114 Boe/d (75% oil), respectively. This Bakken well had an effective lateral length of 9,523 feet and was completed with 30 frac stages.
Initial results from the implementation of several drilling and completion modifications are encouraging. The Company believes that modified completion techniques are the primary factor contributing to the improved initial rates from the recently drilled and completed wells in the Fort Berthold and Marmon areas. Specifically, the last four Three Forks wells drilled in the Fort Berthold area have an average initial production rate of 2,094 Boe/d (86% oil), a 77% improvement to all other Three Forks wells completed by Halcón in the Fort Berthold area during the first quarter of 2013 using the previous completion method. In the Marmon area, the average initial production rate for the two most recently drilled Bakken wells is 91% higher than the average initial production rate for all Company-operated Bakken wells previously completed in the area.
As previously disclosed, production from the Williston Basin was negatively impacted by approximately 1,500 Boe/d in the first quarter due to the continued flaring of approximately 6 million cubic feet per day of natural gas, inclement winter weather and the implementation of batch drilling. Actions are currently underway to reduce flaring, but a more permanent solution is not expected to be in place until the fourth quarter of 2013.
There are currently 103 Bakken wells producing, 5 Bakken wells being completed or waiting on completion and 6 Bakken wells being drilled on Halcón’s operated acreage in the Williston Basin. Similarly, there are currently 32 Three Forks wells producing, 1 Three Forks well waiting on completion and 3 Three Forks wells being drilled on Halcón’s operated acreage.
El Halcón
The Company recently unveiled a 50,000 net acre position in East Texas that is targeting the Eagle Ford shale. Halcón will focus on defining the play area throughout the balance of 2013, and expectations are to build an aggregate position of up to 150,000 net acres over time.
The Company averaged one operated rig, spud two wells and completed two wells in El Halcón during the first quarter of 2013. The average initial and 30 day production rates for the applicable wells completed in the quarter were 1,028 Boe/d (94% oil) and 831 Boe/d (94%) oil, respectively. These wells have an average effective lateral length of 6,379 feet and were completed with an average of 33 frac stages.
Halcón recently drilled the Bumble Bee 1H well in Brazos County in 25 days (spud to rig release) with a pilot hole. This well has an effective lateral length of 8,870 feet, which is 39% longer than the average for the two wells completed in the first quarter. The curve was drilled in 24 hours and the lateral was drilled in 5.75 days.
There are currently seven Eagle Ford wells producing, one well being completed and three wells being drilled.
Utica/Point Pleasant
The Company averaged two operated rigs, spud four wells and completed four wells in Ohio and Pennsylvania during the three months ended March 31, 2013.
Halcón is in the process of delineating its Utica/Point Pleasant acreage position and expects the process to be completed by the fourth quarter of 2013. Production testing has commenced on the Phillips 1H in Mercer County, Pennsylvania, and the Company anticipates that four wells will have been tested or will be in the testing phase by the end of May 2013.
The Phillips 1H commenced flow back on April 8, 2013 and measured first hydrocarbons on April 14, 2013. Halcón has maintained a continuous flowback on the well and rates continue to increase. While still recovering frac load, early stage flow rate data is encouraging. The oil being produced is 52 degree API and the natural gas being produced is 1,330 BTU/SCF.
The Company is focused on building an inventory of approved/permitted multi-well pads in preparation for a full scale development program to optimize drilling and completion costs.
There is currently one Utica/Point Pleasant well producing, four wells resting, one well being completed and two wells being drilled.
Woodbine
During the quarter, Halcón averaged 5 operated rigs and spud 11 wells on its Woodbine acreage.
The Company has implemented a standardized measure for calculating initial flow rates. Woodbine wells are low energy wells that do not achieve maximum production until artificial lift equipment is installed. Initial rates will not be reported until a well has been online for 45 days, at which time the initial rate is calculated based on the highest 7 day average.
Halcón brought ten Woodbine wells online during the period (eight in Leon County and two in Madison County), five of which have been online long enough to report flow rates using the new standardized measure. Four of the five wells are in Leon County and one is in Madison County. The average initial and 30 day rates for the applicable wells completed in Leon County were 503 Boe/d (95% oil) and 438 Boe/d (96%) oil, respectively. The initial rate for the well completed in Madison County was 358 Boe/d (81% oil).
The wells brought online in the first quarter had an average effective lateral length of 6,716 feet and were completed with an average of 23 frac stages.
As previously disclosed, a combination of gas flaring, the implementation of full scale pad drilling and underperforming wells drilled to define the edge of the Halliday Field in Leon County negatively impacted production by approximately 1,333 Boe/d in the first quarter of 2013. Based on extensive technical work and recent well data, Halcón expects Woodbine results to improve and plans to focus on drilling in the core of the Halliday Field.
The Company has determined that the preferred initial method of artificial lift is jet lift, with the long term solution being rod pump. Halcón is currently reviewing options to move immediately to rod pump.
On the drilling side, the Company significantly reduced spud to target depth times by an average of 27% during the first quarter of 2013. In addition, footage drilled per day increased by approximately 23% for wells spud from January 2013 to March 2013.
There are currently 30 horizontal Woodbine wells producing, 11 wells being completed or waiting on completion and 3 wells being drilled.
Portfolio Management
Halcón has executed a definitive agreement to sell its Eagle Ford assets in Fayette and Gonzales Counties, Texas. The Company anticipates closing on the sale of these assets in the third quarter of 2013. In addition, subject to market conditions, Halcón intends to divest approximately 4,500 Boe/d of production from conventional assets in 2013.
Outlook
The following production and cost guidance for the second quarter of 2013 reflects the divestment of 500 Boe/d of production from certain properties in South Louisiana in the fourth quarter of 2012, which along with the aforementioned impacts to production amounts to a total of approximately 3,333 Boe/d.
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Q2 ‘13E |
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Production (Boe/d) |
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Low |
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27,000 |
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High |
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29,000 |
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% Oil |
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83 |
% | |
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% NGLs |
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5 |
% | |
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% Gas |
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12 |
% | |
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Operating Costs and Expenses ($/Boe) |
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Lease Operating |
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Low |
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$ |
9.00 |
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High |
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$ |
11.00 |
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Production Taxes |
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Low |
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$ |
7.00 |
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High |
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$ |
8.00 |
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Cash G&A |
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Low |
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$ |
9.00 |
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High |
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$ |
10.00 |
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Note: Guidance is forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond the Company’s control.
Conference Call and Webcast Information
Halcón Resources Corporation (NYSE:HK) has scheduled a conference call for Thursday, May 2, 2013, at 10:00 a.m. EDT (9:00 a.m. CDT). 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 48708540. 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 May 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 48708540.
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, Form 10-Q for the quarter ended March 31, 2013 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)
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Three Months Ended March 31, |
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2013 |
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2012 |
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Operating revenues: |
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Oil, natural gas and natural gas liquids sales: |
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Oil |
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$ |
180,780 |
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$ |
22,997 |
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Natural gas |
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5,539 |
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1,668 |
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Natural gas liquids |
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3,808 |
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2,169 |
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Total oil, natural gas and natural gas liquids sales |
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190,127 |
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26,834 |
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Other |
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530 |
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36 |
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Total operating revenues |
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190,657 |
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26,870 |
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Operating expenses: |
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|
|
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Production: |
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|
|
|
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Lease operating |
|
25,440 |
|
7,501 |
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|
Workover and other |
|
1,624 |
|
833 |
| ||
|
Taxes other than income |
|
17,436 |
|
1,926 |
| ||
|
Restructuring |
|
671 |
|
104 |
| ||
|
General and administrative |
|
31,597 |
|
20,312 |
| ||
|
Depletion, depreciation and accretion |
|
81,858 |
|
5,979 |
| ||
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Total operating expenses |
|
158,626 |
|
36,655 |
| ||
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Income (loss) from operations |
|
32,031 |
|
(9,785 |
) | ||
|
Other income (expenses): |
|
|
|
|
| ||
|
Interest expense and other, net |
|
(4,850 |
) |
(12,997 |
) | ||
|
Net gain (loss) on derivative contracts |
|
(18,422 |
) |
(4,945 |
) | ||
|
Total other income (expenses) |
|
(23,272 |
) |
(17,942 |
) | ||
|
Income (loss) before income taxes |
|
8,759 |
|
(27,727 |
) | ||
|
Income tax benefit (provision) |
|
(3,294 |
) |
(5,595 |
) | ||
|
Net income (loss) |
|
5,465 |
|
(33,322 |
) | ||
|
Non-cash preferred dividend |
|
— |
|
(1,102 |
) | ||
|
Net income (loss) available to common stockholders |
|
$ |
5,465 |
|
$ |
(34,424 |
) |
|
|
|
|
|
|
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Net income (loss) per share of common stock: |
|
|
|
|
| ||
|
Basic |
|
$ |
0.02 |
|
$ |
(0.50 |
) |
|
Diluted |
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$ |
0.01 |
|
$ |
(0.50 |
) |
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|
|
|
|
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Weighted average common shares outstanding: |
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|
|
|
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Basic |
|
346,139 |
|
68,816 |
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Diluted |
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383,565 |
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68,816 |
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HALCÓN RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS (Unaudited)
(In thousands, except share and per share amounts)
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|
|
March 31, |
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December 31, |
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2013 |
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2012 |
| ||
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Current assets: |
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|
|
|
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Cash |
|
$ |
802 |
|
$ |
2,506 |
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|
Accounts receivable |
|
323,672 |
|
262,809 |
| ||
|
Receivables from derivative contracts |
|
2,156 |
|
7,428 |
| ||
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Current portion of deferred income taxes |
|
8,214 |
|
5,307 |
| ||
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Inventory |
|
4,150 |
|
3,116 |
| ||
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Prepaids and other |
|
3,056 |
|
6,691 |
| ||
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Total current assets |
|
342,050 |
|
287,857 |
| ||
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Oil and natural gas properties (full cost method): |
|
|
|
|
| ||
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Evaluated |
|
3,031,073 |
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2,669,245 |
| ||
|
Unevaluated |
|
2,478,181 |
|
2,326,598 |
| ||
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Gross oil and natural gas properties |
|
5,509,254 |
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4,995,843 |
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Less - accumulated depletion |
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(668,098 |
) |
(588,207 |
) | ||
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Net oil and natural gas properties |
|
4,841,156 |
|
4,407,636 |
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Other operating property and equipment: |
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|
|
|
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Gas gathering and other operating assets |
|
102,122 |
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59,748 |
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Less - accumulated depreciation |
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(9,087 |
) |
(8,119 |
) | ||
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Net other operating property and equipment |
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93,035 |
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51,629 |
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Other noncurrent assets: |
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|
|
|
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Goodwill |
|
229,221 |
|
227,762 |
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Receivables from derivative contracts |
|
1,515 |
|
371 |
| ||
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Debt issuance costs, net of amortization |
|
61,201 |
|
51,609 |
| ||
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Equity in oil and natural gas partnerships |
|
10,948 |
|
11,137 |
| ||
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Funds in escrow |
|
847 |
|
2,090 |
| ||
|
Other |
|
882 |
|
934 |
| ||
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Total assets |
|
$ |
5,580,855 |
|
$ |
5,041,025 |
|
|
Current liabilities: |
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|
|
|
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Accounts payable and accrued liabilities |
|
$ |
706,558 |
|
$ |
590,551 |
|
|
Liabilities from derivative contracts |
|
22,297 |
|
10,429 |
| ||
|
Asset retirement obligations |
|
2,424 |
|
2,319 |
| ||
|
Promissory notes |
|
6,924 |
|
74,669 |
| ||
|
Total current liabilities |
|
738,203 |
|
677,968 |
| ||
|
Long-term debt |
|
2,501,038 |
|
2,034,498 |
| ||
|
Other noncurrent liabilities: |
|
|
|
|
| ||
|
Liabilities from derivative contracts |
|
2,536 |
|
2,461 |
| ||
|
Asset retirement obligations |
|
75,116 |
|
72,813 |
| ||
|
Deferred income taxes |
|
161,963 |
|
160,055 |
| ||
|
Other |
|
10 |
|
10 |
| ||
|
Commitments and contingencies |
|
|
|
|
| ||
|
Mezzanine equity: |
|
|
|
|
| ||
|
Preferred stock: 1,000,000 shares of $0.0001 par value authorized; none and 10,880 shares issued and outstanding as of March 31, 2013 and December 31, 2012, respectively |
|
— |
|
695,238 |
| ||
|
Stockholders’ equity: |
|
|
|
|
| ||
|
Common stock: 670,000,000 and 336,666,666 shares of $0.0001 par value authorized; 369,754,373 and 259,802,37 shares issued; 369,754,373 and 258,152,468 outstanding at March 31, 2013 and December 31, 2012, respectively |
|
37 |
|
26 |
| ||
|
Additional paid-in capital |
|
2,370,950 |
|
1,681,717 |
| ||
|
Treasury stock: none and 1,649,909 shares at March 31, 2013 and December 31, 2012, respectively, at cost |
|
— |
|
(9,298 |
) | ||
|
Accumulated deficit |
|
(268,998 |
) |
(274,463 |
) | ||
|
Total stockholders’ equity |
|
2,101,989 |
|
1,397,982 |
| ||
|
Total liabilities and stockholders’ equity |
|
$ |
5,580,855 |
|
$ |
5,041,025 |
|
HALCÓN RESOURECS CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(In thousands)
|
|
|
Three Months Ended March 31, |
| ||||
|
|
|
2013 |
|
2012 |
| ||
|
Cash flows from operating activities: |
|
|
|
|
| ||
|
Net income (loss) |
|
$ |
5,465 |
|
$ |
(33,322 |
) |
|
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: |
|
|
|
|
| ||
|
Depletion, depreciation and accretion |
|
81,858 |
|
5,979 |
| ||
|
Deferred income tax provision (benefit) |
|
(999 |
) |
5,522 |
| ||
|
Share-based compensation, net |
|
2,335 |
|
1,935 |
| ||
|
Unrealized loss (gain) on derivative contracts |
|
16,071 |
|
4,851 |
| ||
|
Amortization and write-off of deferred loan costs |
|
265 |
|
6,087 |
| ||
|
Non-cash interest and amortization of discount and premium |
|
866 |
|
4,065 |
| ||
|
Other income |
|
(1,013 |
) |
(12 |
) | ||
|
Cash flow from operations before changes in working capital |
|
104,848 |
|
(4,895 |
) | ||
|
Changes in working capital, net of acquisitions |
|
(49,569 |
) |
(4,304 |
) | ||
|
Net cash provided by (used in) operating activities |
|
55,279 |
|
(9,199 |
) | ||
|
|
|
|
|
|
| ||
|
Cash flows from investing activities: |
|
|
|
|
| ||
|
Oil and natural gas capital expenditures |
|
(389,543 |
) |
(23,986 |
) | ||
|
Other operating property and equipment capital expenditures |
|
(36,483 |
) |
(629 |
) | ||
|
Acquisition of Williston Basin Assets |
|
(29,895 |
) |
— |
| ||
|
Funds held in escrow and other |
|
1,328 |
|
(3,763 |
) | ||
|
Net cash provided by (used in) investing activities |
|
(454,593 |
) |
(28,378 |
) | ||
|
|
|
|
|
|
| ||
|
Cash flows from financing activities: |
|
|
|
|
| ||
|
Proceeds from borrowings |
|
844,000 |
|
237,410 |
| ||
|
Repayments of borrowings |
|
(434,476 |
) |
(208,000 |
) | ||
|
Debt issuance costs |
|
(11,483 |
) |
(4,495 |
) | ||
|
Offering costs |
|
(431 |
) |
(18,056 |
) | ||
|
Common stock repurchased |
|
— |
|
(2,139 |
) | ||
|
Preferred stock issued |
|
— |
|
311,556 |
| ||
|
Preferred beneficial conversion feature |
|
— |
|
88,445 |
| ||
|
Common stock issued |
|
— |
|
275,000 |
| ||
|
Warrants issued |
|
— |
|
43,590 |
| ||
|
Net cash provided by (used in) financing activities |
|
397,610 |
|
723,311 |
| ||
|
|
|
|
|
|
| ||
|
Net increase (decrease) in cash |
|
(1,704 |
) |
685,734 |
| ||
|
|
|
|
|
|
| ||
|
Cash at beginning of period |
|
2,506 |
|
49 |
| ||
|
Cash at end of period |
|
$ |
802 |
|
$ |
685,783 |
|
HALCÓN RESOURCES CORPORATION
SELECTED OPERATING DATA
(Unaudited)
|
|
|
Three Months Ended March 31, |
| ||||
|
|
|
2013 |
|
2012 |
| ||
|
|
|
|
|
|
| ||
|
Production volumes: |
|
|
|
|
| ||
|
Oil (MBbls) |
|
1,931 |
|
226 |
| ||
|
Natural gas (Mmcf) |
|
1,811 |
|
615 |
| ||
|
Natural gas liquids (MBbls) |
|
109 |
|
40 |
| ||
|
Total (MBoe) |
|
2,342 |
|
369 |
| ||
|
Average daily production (Boe) |
|
26,022 |
|
4,055 |
| ||
|
|
|
|
|
|
| ||
|
Average prices: |
|
|
|
|
| ||
|
Oil (per Bbl) |
|
$ |
93.62 |
|
$ |
101.76 |
|
|
Natural gas (per Mcf) |
|
3.06 |
|
2.71 |
| ||
|
Natural gas liquids (per Bbl) |
|
34.94 |
|
54.23 |
| ||
|
Total per Boe |
|
81.18 |
|
72.72 |
| ||
|
|
|
|
|
|
| ||
|
Cash effect of derivative contracts: |
|
|
|
|
| ||
|
Oil (per Bbl) |
|
$ |
(1.48 |
) |
$ |
(0.62 |
) |
|
Natural gas (per Mcf) |
|
0.28 |
|
1.16 |
| ||
|
Natural gas liquids (per Bbl) |
|
— |
|
— |
| ||
|
Total per Boe |
|
(1.00 |
) |
1.56 |
| ||
|
|
|
|
|
|
| ||
|
Average prices computed after cash effect of settlement of derivative contracts: |
|
|
|
|
| ||
|
Oil (per Bbl) |
|
$ |
92.14 |
|
$ |
101.14 |
|
|
Natural gas (per Mcf) |
|
3.34 |
|
3.87 |
| ||
|
Natural gas liquids (per Bbl) |
|
34.94 |
|
54.23 |
| ||
|
Total per Boe |
|
80.18 |
|
74.28 |
| ||
|
|
|
|
|
|
| ||
|
Average cost per Boe: |
|
|
|
|
| ||
|
Production: |
|
|
|
|
| ||
|
Lease operating |
|
$ |
10.86 |
|
$ |
20.33 |
|
|
Workover and other |
|
0.69 |
|
2.26 |
| ||
|
Taxes other than income |
|
7.44 |
|
5.22 |
| ||
|
General and administrative, as adjusted(1) |
|
11.72 |
|
19.41 |
| ||
|
Restructuring costs |
|
0.29 |
|
0.28 |
| ||
|
Depletion |
|
34.11 |
|
14.53 |
| ||
(1) Represents general and administrative costs per Boe, adjusted for items noted in the reconciliation below:
|
General and administrative: |
|
|
|
|
| ||
|
General and administrative, as reported |
|
$ |
13.49 |
|
$ |
55.05 |
|
|
Share-based compensation: |
|
|
|
|
| ||
|
Cash |
|
— |
|
(4.89 |
) | ||
|
Non-cash |
|
(1.00 |
) |
(6.74 |
) | ||
|
Recapitalization and change in control: |
|
|
|
|
| ||
|
Cash |
|
— |
|
— |
| ||
|
Non-cash |
|
— |
|
(24.01 |
) | ||
|
Acquisition and merger transaction costs: |
|
|
|
|
| ||
|
Cash |
|
(0.77 |
) |
— |
| ||
|
General and administrative, as adjusted |
|
$ |
11.72 |
|
$ |
19.41 |
|
|
Total operating costs, as reported |
|
$ |
32.48 |
|
$ |
82.86 |
|
|
Total adjusting items |
|
(1.77 |
) |
(35.64 |
) | ||
|
Total operating costs, as adjusted(2) |
|
$ |
30.71 |
|
$ |
47.22 |
|
(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 share amounts)
|
|
|
Three Months Ended March 31, |
| ||||
|
|
|
2013 |
|
2012 |
| ||
|
|
|
|
|
|
| ||
|
Unrealized loss (gain) on derivatives contracts:(1) |
|
|
|
|
| ||
|
Crude oil |
|
$ |
13,644 |
|
$ |
5,574 |
|
|
Natural gas |
|
3,155 |
|
(112 |
) | ||
|
Interest rate |
|
— |
|
(518 |
) | ||
|
Total mark-to-market non-cash charge |
|
16,799 |
|
4,944 |
| ||
|
Recapitalization expenditures(2) |
|
— |
|
21,467 |
| ||
|
Restructuring(3) |
|
671 |
|
104 |
| ||
|
Acquisition and merger transaction costs and other(4) |
|
1,810 |
|
— |
| ||
|
Selected items, before income taxes and preferred dividend |
|
19,280 |
|
26,515 |
| ||
|
Income tax effect of selected items(5) |
|
(7,247 |
) |
4,083 |
| ||
|
Selected items, net of tax and before preferred dividend |
|
12,033 |
|
30,598 |
| ||
|
Non-cash preferred dividend(6) |
|
— |
|
1,102 |
| ||
|
Selected items, net of tax |
|
12,033 |
|
31,700 |
| ||
|
Net income (loss) available to common stockholders, as reported |
|
5,465 |
|
(34,424 |
) | ||
|
Net income (loss) available to common stockholders, excluding selected items |
|
$ |
17,498 |
|
$ |
(2,724 |
) |
|
|
|
|
|
|
| ||
|
Basic net income (loss) per common share, as reported |
|
$ |
0.02 |
|
$ |
(0.50 |
) |
|
Impact of selected items |
|
0.03 |
|
0.46 |
| ||
|
Basic net income (loss) per common share, excluding selected items |
|
$ |
0.05 |
|
$ |
(0.04 |
) |
|
|
|
|
|
|
| ||
|
Diluted net income (loss) per common share, as reported |
|
$ |
0.01 |
|
$ |
(0.50 |
) |
|
Impact of selected items |
|
0.04 |
|
0.46 |
| ||
|
Diluted net income (loss) per common share, excluding selected items |
|
$ |
0.05 |
|
$ |
(0.04 |
) |
|
|
|
|
|
|
| ||
|
Cash flow from operations before changes in working capital |
|
$ |
104,848 |
|
$ |
(4,895 |
) |
|
Cash components of selected items |
|
2,481 |
|
13,257 |
| ||
|
Income tax effect of selected items(5) |
|
(933 |
) |
(2,041 |
) | ||
|
Cash flow from operations before changes in working capital, adjusted for selected items |
|
$ |
106,396 |
|
$ |
6,321 |
|
|
|
|
|
|
|
| ||
|
Cash flow from operations before changes in working capital per diluted share |
|
$ |
0.27 |
|
$ |
(0.07 |
) |
|
Impact of selected items |
|
0.01 |
|
0.16 |
| ||
|
Cash flow from operations before changes in working capital per diluted share, adjusted for selected items |
|
$ |
0.28 |
|
$ |
0.09 |
|
(1) Represents the non-cash unrealized (gain) loss 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 37.6%
(6) Represents amortization of the non-cash preferred dividend as a result of the beneficial conversion feature of convertible preferred stock.