May 2, 2013

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, May 2, 2013 (GLOBE NEWSWIRE) -- 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.

  Q2 '13E
Production (Boe/d)  
Low 27,000
High 29,000
% Oil 83%
% NGLs 5%
% Gas 12%
   
Operating Costs and Expenses ($/Boe)  
Lease Operating  
Low $9.00
High $11.00
Production Taxes  
Low $7.00
High $8.00
Cash G&A  
Low $9.00
High $10.00

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)
     
     
  Three Months Ended March 31,
  2013 2012
Operating revenues:    
Oil, natural gas and natural gas liquids sales:    
Oil   $ 180,780  $ 22,997
Natural gas  5,539  1,668
Natural gas liquids  3,808  2,169
Total oil, natural gas and natural gas liquids sales  190,127  26,834
Other  530  36
Total operating revenues  190,657  26,870
     
Operating expenses:    
Production:    
Lease operating  25,440  7,501
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
Total operating expenses  158,626  36,655
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)
     
Net income (loss) per share of common stock:    
Basic  $ 0.02  $ (0.50)
Diluted  $ 0.01  $ (0.50)
     
Weighted average common shares outstanding:    
Basic  346,139  68,816
Diluted  383,565  68,816
 
HALCÓN RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS (Unaudited)
(In thousands, except share and per share amounts)
     
  March 31, December 31,
  2013 2012
Current assets:    
Cash  $ 802  $ 2,506
Accounts receivable  323,672  262,809
Receivables from derivative contracts  2,156  7,428
Current portion of deferred income taxes  8,214  5,307
Inventory  4,150  3,116
Prepaids and other  3,056  6,691
Total current assets  342,050  287,857
Oil and natural gas properties (full cost method):    
Evaluated  3,031,073  2,669,245
Unevaluated  2,478,181  2,326,598
Gross oil and natural gas properties  5,509,254  4,995,843
Less - accumulated depletion  (668,098)  (588,207)
Net oil and natural gas properties  4,841,156  4,407,636
Other operating property and equipment:    
Gas gathering and other operating assets  102,122  59,748
Less - accumulated depreciation  (9,087)  (8,119)
Net other operating property and equipment  93,035  51,629
Other noncurrent assets:    
Goodwill   229,221  227,762
Receivables from derivative contracts  1,515  371
Debt issuance costs, net of amortization  61,201  51,609
Equity in oil and natural gas partnerships  10,948  11,137
Funds in escrow  847  2,090
Other  882  934
Total assets  $ 5,580,855  $ 5,041,025
Current liabilities:    
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 RESOURCES 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.
CONTACT: Scott Zuehlke

         Vice President of Investor Relations

         832-538-0314

         szuehlke@halconresources.com

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