Exhibit 99.1
| | NEWS RELEASE |
Halcón Resources Announces Fourth Quarter and Full Year 2013 Results
Tuscaloosa Marine Shale Unveiled as New Core Area
Agrees to Sell Non-Core Assets for $450 Million
HOUSTON, TEXAS — February 26, 2014 — Halcón Resources Corporation (NYSE:HK) (“Halcón” or the “Company”) today announced its fourth quarter and full year 2013 results.
Halcón generated revenues of $289.3 million for the quarter ended December 31, 2013, compared to $124.8 million for the quarter ended December 31, 2012. Revenues for the full year 2013 were $999.5 million, compared to $248.3 million for the full year 2012.
Production for the three months and full year ended December 31, 2013 increased by 119% and 254% to 40,217 barrels of oil equivalent per day (Boe/d) and 33,329 Boe/d, respectively, compared to the same periods of 2012. Halcón reported full year 2013 production near the high-end of guidance, despite a 1,220 Boe/d negative impact related to weather downtime, primarily in the Williston Basin, during the fourth quarter. Production was comprised of 84% oil, 6% natural gas liquids (NGLs) and 10% natural gas for the quarter and 83% oil, 6% NGLs and 11% natural gas for the year.
Including the impact of hedges, the Company realized 88% of the average NYMEX oil price, 39% of the average NYMEX oil price for NGLs and 96% of the average NYMEX natural gas price during the fourth quarter 2013. For the full year 2013, Halcón realized 92% of the average NYMEX oil price, 37% of the average NYMEX oil price for NGLs and 98% of the average NYMEX natural gas price.
Total operating costs per unit (including lease operating expense, workover and other expense, taxes other than income, gathering and other expense, and general and administrative expense), after adjusting for selected items (see Selected Operating Data table for additional information), decreased by 17% to $27.69 per Boe in the fourth quarter of 2013, compared to the same period of 2012. Total operating costs per unit for 2013, after adjusting for selected
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items (see Selected Operating Data table for additional information), were $29.20 per Boe, representing a decrease of 21% versus 2012.
After adjusting for selected items primarily related to non-cash impairment charges and the non-cash impact of derivatives (see Selected Item Review and Reconciliation table for additional information), net income was $4.1 million, or $0.01 per diluted share, and $67.7 million, or $0.15 per diluted share, for the three months and full year ended December 31, 2013, respectively. Halcón reported a net loss available to common stockholders of $415.3 million, or $1.01 per diluted share for the quarter and $1.2 billion, or $3.25 per diluted share for the year. The reported net loss available to common stockholders for the quarter and the year includes non-cash pre-tax impairment charges of $238.9 million and $1.4 billion, respectively.
Floyd C. Wilson, Chairman and Chief Executive Officer, commented, “Our focus in 2014 is on drilling wells in the sweet spots of our de-risked acreage in the Williston Basin and El Halcón. We will also begin drilling wells on our newly acquired acreage located in what we believe to be the core of the Tuscaloosa Marine Shale. We are primed for growth and have a deep drilling inventory. We are committed to maintaining capital discipline and dedicated to improving capital efficiency.”
Agrees to Divest Non-Core Assets for $450 Million
The Company has entered into a purchase and sale agreement to divest non-core assets in East Texas for $450 million. The transaction is expected to close in the second quarter of 2014, subject to customary closing conditions and adjustments, with an effective date of April 1, 2014.
The assets subject to the purchase and sale agreement include approximately 83,000 net acres primarily located in Leon, Madison and Grimes Counties, Texas. These properties produced an average of approximately 3,800 Boe/d during the month of January 2014. Estimated proved reserves associated with these assets, as of December 31, 2013, were approximately 16.3 MMBoe, 39% of which was proved developed.
The closing of this sale would essentially conclude Halcón’s planned 2014 divestiture program. The Company plans to continue to evaluate all remaining non-core properties for future divestment opportunities.
Liquidity and Capital Spending
As of December 31, 2013, the Company had undrawn capacity on its senior secured revolving credit facility and cash on hand totaling approximately $700 million. Pro forma for the pending sale of the non-core assets in East Texas, and the related $100 million reduction to the revolver
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borrowing base that is expected, Halcón had undrawn capacity on its senior secured revolving credit facility and cash on hand totaling approximately $1.1 billion as of December 31, 2013.
During the fourth quarter of 2013, the Company incurred capital costs of $274.4 million on drilling and completions, $29.2 million on infrastructure/seismic and $1.7 million on other capital expenditures. In addition, $201.3 million was incurred for acquisitions primarily in the El Halcón and TMS areas, offset by divestiture proceeds totaling $287.8 million during the three months ended December 31, 2013.
Halcón incurred capital costs of $1.5 billion on drilling and completions, $177.4 million on infrastructure/seismic and $194.9 million on other capital expenditures in 2013. The Company also incurred $649.5 million for acquisitions in 2013, offset by divestiture proceeds totaling $446.4 million.
Proved Reserves — 609% Organic Reserve Replacement; 61% Organic Reserve Growth
Halcón’s estimated proved reserves as of December 31, 2013 were approximately 136 million barrels of oil equivalent (MMBoe). Year-end 2013 estimated proved reserves were 84% oil, 7% NGLs and 9% natural gas on an equivalent basis. Of total estimated proved reserves, 90.5 MMBoe were in the Williston Basin, 22.7 MMBoe were in the East Texas Eagle Ford (“El Halcón) and 22.8 MMBoe were in other areas.
The present value of Halcón’s estimated future oil and gas revenues, net of estimated expenses, discounted at an annual rate of 10% (PV10) was approximately $2.77 billion as of December 31, 2013. In comparison, the standardized measure is approximately $2.75 billion; the difference is attributed to the estimated future income tax expense discounted at 10%. Proved developed reserves account for 40% of total estimated proved reserves. A summary of year-over-year changes in estimated proved reserves is as follows:
Proved Reserves Reconciliation | | Oil (MBbls) | | Gas (MMcf) | | NGL (MBbls) | | Total MBoe | |
As of 12.31.12 | | 87,378 | | 96,145 | | 5,383 | | 108,785 | |
Extensions, discoveries and additions | | 61,160 | | 25,364 | | 4,344 | | 69,731 | |
Purchases | | 2,770 | | 1,791 | | 162 | | 3,231 | |
Sales | | (17,417 | ) | (25,717 | ) | (1,611 | ) | (23,314 | ) |
Production | | (10,148 | ) | (8,003 | ) | (683 | ) | (12,165 | ) |
Revisions of previous estimates and pricing | | (9,233 | ) | (19,832 | ) | 2,237 | | (10,301 | ) |
As of 12.31.13 | | 114,510 | | 69,748 | | 9,832 | | 135,967 | |
Pro forma for sales and purchases, the Company replaced 609% of production including revisions, and reported a net increase in proved reserves of 60.7 MMBoe over year-end 2012, representing an organic growth rate of 61%. A pro forma summary of year-over-year changes in estimated proved reserves is as follows:
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Pro Forma Proved Reserves Reconciliation | | Proved | | PF Proved | |
(MMBoe) | | Reserves | | Reserves | |
As of 12.31.12 | | 108.8 | | 82.8 | |
Extensions, discoveries and additions | | 69.7 | | 69.7 | |
Purchases | | 3.2 | | — | |
Sales | | (23.3 | ) | — | |
Production | | (12.2 | ) | (10.0 | ) |
Revisions of previous estimates and pricing | | (10.3 | ) | (9.0 | ) |
As of 12.31.13 | | 136.0 | | 133.5 | |
Organic Reserve Additions, including revisions (MMBoe) | | | | 60.7 | |
Organic Reserve Growth | | | | 61 | % |
Organic Reserve Replacement | | | | 609 | % |
The Company’s estimated proved reserves at December 31, 2013 were prepared by the independent reserve engineering firm Netherland, Sewell and Associates, Inc. (NSAI) in accordance with Securities and Exchange Commission guidelines.
Estimated Net Unrisked Resource Potential of ~1.4 BBoe
Halcón estimates current net unrisked resource potential at 1.4 billion barrels of oil equivalent (BBoe), which is comprised of 75% oil, 11% NGLs and 14% gas. Net unrisked resource potential calculations were estimated by the Company’s internal reserve group and consist of a horizontal drilling inventory of approximately 3,270 net locations.
Tuscaloosa Marine Shale (“TMS”) Unveiled as New Core Area
Halcón has established the TMS as a third core area. In aggregate, the Company currently has approximately 307,000 net acres leased or under contract in the play. Approximately 77% of the acreage is located in Southwest Mississippi and the Louisiana Florida Parishes, also known as the “Eastern TMS”.
The proceeds from the pending sale of non-core assets are expected to provide Halcón the ability to internally fund the TMS program. However, the Company is evaluating joint venture options for its entire TMS position and is engaged in ongoing discussions with several potential partners.
Halcón employs an experienced exploration staff that has been working the TMS for more than a year with access to hundreds of well logs and core data from a number of wells. As a result, geologic mapping from these efforts have allowed for the acquisition of land within a well-defined area believed to be the geologic core.
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The Company plans to operate an average of 2 rigs for the remainder of 2014 and spud 10 to 12 gross operated wells in the TMS. Halcón also expects to participate in several non-operated wells in 2014. Expectations are to spud the next operated well in March of 2014 near producing TMS wells in Wilkinson County, Mississippi. No changes to guidance are being made as a result of this announcement as TMS drilling activity was incorporated into the Company’s 2014 business plan and budget. Halcón plans to spend approximately 10% of its drilling and completions budget in the play in 2014, subject to reduction dependent upon ongoing negotiations with potential joint venture partners.
Charles E. Cusack III, Chief Operating Officer, stated, “We have been working the Tuscaloosa Marine Shale from a geologic standpoint and monitoring industry activity in the play for quite some time. Our strategy is to identify scalable and repeatable resources plays where we feel we can meaningfully improve the economics by applying our extensive technical experience. We believe the TMS fits that strategy, and we are excited about our position in the play.”
Operational Update — Williston Basin and El Halcón Type Curve EURs Increased
The Company’s 2014 capital budget is primarily focused on its three, oil-biased core resource plays: the Williston Basin, El Halcón and the TMS.
Bakken/Three Forks
Halcón operated an average of five rigs in the Williston Basin during the fourth quarter. The Company spudded 8 wells and put 10 wells online in the Fort Berthold area during the three months ended December 31, 2013. In addition, Halcón spudded four wells and put two wells online in Williams County during the period. The Company also participated in 50 non-operated wells during the quarter with an average working interest of approximately 3%. Despite weather-related impacts of approximately 1,040 Boe/d, Halcón produced an average of 24,125 Boe/d in the Williston Basin during the fourth quarter, representing an increase of 15% versus the prior quarter. Drilling and completion delays related to the inclement weather in the Williston Basin during the fourth quarter of 2013 are also expected to impact production in the first quarter of 2014.
The Company continues to modify its drilling and completions techniques in an effort to improve recoveries and reduce costs. Based on improved results to date, Halcón has revised the EUR estimates higher for its type curves. Note that the Company is now using one average type curve for all Bakken and Three Forks wells drilled in the Fort Berthold area, and one average type curve for all Bakken wells drilled in Williams County. In the Fort Berthold area, the average Bakken/Three Forks type curve increased by 39% to 801 thousand barrels of oil equivalent (MBoe), while the average Bakken type curve EUR in Williams County was revised higher by 43% to 477 MBoe.
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Data suggests that wells completed with slickwater fracs in the Williston Basin are outperforming wells completed with cross-linked gel, all else being equal. As a result, Halcón plans to complete the majority of its future operated wells in the Williston Basin using the slickwater frac technique. All Company-operated wells online in the Fort Berthold area that were completed via a slickwater frac are currently outperforming the new 801 MBoe type curve, and internal reserve engineers estimate an average EUR for these slickwater wells of approximately 970 MBoe.
The Company has identified several cost reduction opportunities and anticipates well costs will trend down throughout 2014 by 5% to 10%. Efficiencies related to pad drilling/simultaneous operations and additional completion modifications (proppant type, fluid type, pumping services) are expected to lead to lower well costs.
Early stage downspacing tests continue to yield positive results, and indicate the potential for up to 16 locations per drilling spacing unit (DSU) in the Fort Berthold area, which would more than triple the Company’s drilling inventory in this area alone compared to the previous development plan.
Halcón currently has working interests in approximately 142,000 net acres prospective for the Bakken and Three Forks formations in the Williston Basin. The Company plans to operate an average of 4 rigs and spud 40 to 50 gross operated wells in 2014. Halcón also expects to participate in 200 to 225 gross non-operated wells in 2014 with an average working interest of approximately 3%. The Company is focused on drilling wells in the highly economic Fort Berthold area in 2014 and anticipates spending approximately 49% of its total drilling and completions budget in the Williston Basin.
There are currently 141 Bakken wells producing, 12 Bakken wells being completed or waiting on completion and 2 Bakken wells being drilled on Halcón’s operated acreage. Similarly, there are currently 39 Three Forks wells producing, 7 Three Forks wells being completed or waiting on completion and 2 Three Forks wells being drilled on the Company’s operated acreage.
“El Halcón” - East Texas Eagle Ford
Halcón operated an average of four rigs in El Halcón during the fourth quarter. The Company spudded 13 wells and put 9 wells online in the play during the three months ended December 31, 2013. Halcón produced an average of 7,138 Boe/d in El Halcón during the fourth quarter, representing an increase of 43% compared to the third quarter of 2013.
The Company has made meaningful progress towards identifying an optimal well design and continues to modify its completion techniques. Testing is underway on a number of completion design variations to reduce cost and increase performance, some of which include modifying
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perforated cluster density, varying proppant types and altering the fluid systems. Based on historical well results, lateral length directly correlates to EUR for wells completed with a sufficient volume of proppant. As such, Halcón continues to work to find the most economic completed lateral length and currently expects to drill wells with an average lateral length of 7,500 feet in 2014.
Based on improved well results, the Company has revised its El Halcón type curve EUR estimate higher by 22% to 452 MBoe. The new type curve is based on wells that were spaced a minimum of 750 feet apart and completed with 1,200 pounds, or more, of proppant per lateral foot. Well spacing pilot tests are ongoing.
Halcón currently has working interests in approximately 100,000 net acres prospective for the Eagle Ford formation in East Texas and believes a majority of its acreage is located in the core of the play. The Company plans to operate an average of 3 rigs and spud 40 to 50 gross operated wells in 2014. Halcón anticipates spending approximately 40% of its total drilling and completions budget in the play in 2014.
There are currently 45 Eagle Ford wells producing, 10 wells being completed or waiting on completion and 4 wells being drilled.
2014 Production Guidance
Based on improved well performance in core areas, the Company is reaffirming full year 2014 production guidance, despite the impact related to the pending sale of the non-core assets in East Texas expected to close in the second quarter of 2014. Halcón is also providing first quarter 2014 production guidance, which accounts for the divestitures that closed in the fourth quarter of 2013 and the carryover effect from weather-related downtime in the Williston Basin. Pro forma for all acquisition and divestiture activity, including the pending sale of the non-core assets in East Texas, the Company estimates it would have produced approximately 24,898 Boe/d on average from continuing operations in 2013.
| | | | Full Year | |
| | 1Q14E | | 2014E | |
Production (Boe/d) | | | | | |
Low | | 34,000 | | 38,000 | |
High | | 36,000 | | 42,000 | |
% Oil | | | | 85 | % |
% NGLs | | | | 5 | % |
% Gas | | | | 10 | % |
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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. See “Forward-Looking Statements” section below.
An updated slide presentation can be accessed on Halcón’s website at http://www.halconresources.com in the Investor Relations section under Events & Presentations.
Conference Call and Webcast Information
Halcón Resources Corporation (NYSE:HK) has scheduled a conference call for Thursday, February 27, 2014, 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 36618134. 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 6, 2014. To access the replay, dial (855) 859-2056 for domestic callers or (404) 537-3406 for international callers, in both cases referencing conference ID 36618134.
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
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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, 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.
Disclosures Regarding Estimated Ultimate Recovery (EUR) and Resource Potential
The Securities and Exchange Commission requires oil and gas companies, in their filings with the SEC, to disclose proved reserves that a company has demonstrated by actual production or through reliable technology to be economically and legally producible at specific prices and existing economic and operating conditions. The SEC permits optional disclosure of probable and possible reserves; however, Halcón has made no such disclosures in its filings with the SEC. The Company uses certain terms in its periodic news releases and other presentation materials such as “estimated ultimate recovery” or “EUR,” “resource potential,” and “net resource potential,” which terms include quantities of oil and gas that may not meet the SEC’s definitions of proved, probable and possible reserves, and which the SEC’s guidelines strictly prohibit Halcón from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being recovered by the Company and accordingly are subject to substantially more risks of actually being realized. Investors are urged to closely consider the disclosures about Halcón’s reserves in its Annual Report on Form 10-K for the year ended December 31, 2013, and in other reports on file with the SEC.
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HALCÓN RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(In thousands, except per share amounts)
| | Three Months Ended December 31, | | Years Ended December 31, | |
| | 2013 | | 2012 | | 2013 | | 2012 | |
Operating revenues: | | | | | | | | | |
Oil, natural gas and natural gas liquids sales: | | | | | | | | | |
Oil | | $ | 272,368 | | $ | 114,006 | | $ | 944,535 | | $ | 223,056 | |
Natural gas | | 7,348 | | 5,860 | | 27,319 | | 12,735 | |
Natural gas liquids | | 8,588 | | 4,100 | | 24,564 | | 11,180 | |
Total oil, natural gas and natural gas liquids sales | | 288,304 | | 123,966 | | 996,418 | | 246,971 | |
Other | | 998 | | 791 | | 3,088 | | 1,351 | |
Total operating revenues | | 289,302 | | 124,757 | | 999,506 | | 248,322 | |
| | | | | | | | | |
Operating expenses: | | | | | | | | | |
Production: | | | | | | | | | |
Lease operating | | 44,506 | | 19,746 | | 139,182 | | 49,859 | |
Workover and other | | 1,992 | | 2,045 | | 6,268 | | 4,429 | |
Taxes other than income | | 26,006 | | 9,605 | | 88,622 | | 19,253 | |
Gathering and other | | 4,844 | | 185 | | 11,745 | | 459 | |
Restructuring | | 3,964 | | 674 | | 4,471 | | 2,406 | |
General and administrative | | 33,525 | | 45,022 | | 132,410 | | 111,349 | |
Depletion, depreciation and accretion | | 143,391 | | 55,623 | | 463,655 | | 90,284 | |
Impairment charges | | 238,873 | | — | | 1,444,100 | | — | |
Total operating expenses | | 497,101 | | 132,900 | | 2,290,453 | | 278,039 | |
| | | | | | | | | |
Income (loss) from operations | | (207,799 | ) | (8,143 | ) | (1,290,947 | ) | (29,717 | ) |
| | | | | | | | | |
Other income (expenses): | | | | | | | | | |
Net gain (loss) on derivative contracts | | 7,516 | | (5,277 | ) | (31,233 | ) | (6,126 | ) |
Interest expense and other, net | | (33,953 | ) | (8,973 | ) | (58,198 | ) | (31,223 | ) |
Total other income (expenses) | | (26,437 | ) | (14,250 | ) | (89,431 | ) | (37,349 | ) |
Income (loss) before income taxes | | (234,236 | ) | (22,393 | ) | (1,380,378 | ) | (67,066 | ) |
Income tax benefit (provision) | | (176,152 | ) | 14,352 | | 157,716 | | 13,181 | |
Net income (loss) | | (410,388 | ) | (8,041 | ) | (1,222,662 | ) | (53,885 | ) |
Non-cash preferred dividend | | — | | — | | — | | (88,445 | ) |
Series A preferred dividends | | (4,959 | ) | — | | (10,745 | ) | — | |
Net income (loss) available to common stockholders | | $ | (415,347 | ) | $ | (8,041 | ) | $ | (1,233,407 | ) | $ | (142,330 | ) |
| | | | | | | | | |
Net income (loss) per share of common stock: | | | | | | | | | |
Basic | | $ | (1.01 | ) | $ | (0.04 | ) | $ | (3.25 | ) | $ | (0.91 | ) |
Diluted | | $ | (1.01 | ) | $ | (0.04 | ) | $ | (3.25 | ) | $ | (0.91 | ) |
Weighted average common shares outstanding: | | | | | | | | | |
Basic | | 412,042 | | 228,075 | | 379,621 | | 156,494 | |
Diluted | | 412,042 | | 228,075 | | 379,621 | | 156,494 | |
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HALCÓN RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS (Unaudited)
(In thousands, except share and per share amounts)
| | December 31, | |
| | 2013 | | 2012 | |
Current assets: | | | | | |
Cash | | $ | 2,834 | | $ | 2,506 | |
Accounts receivable | | 312,518 | | 262,809 | |
Receivables from derivative contracts | | 2,028 | | 7,428 | |
Current portion of deferred income taxes | | — | | 5,307 | |
Inventory | | 5,148 | | 3,116 | |
Prepaids and other | | 16,098 | | 6,691 | |
Total current assets | | 338,626 | | 287,857 | |
Oil and natural gas properties (full cost method): | | | | | |
Evaluated | | 4,960,467 | | 2,669,245 | |
Unevaluated | | 2,028,044 | | 2,326,598 | |
Gross oil and natural gas properties | | 6,988,511 | | 4,995,843 | |
Less - accumulated depletion | | (2,189,515 | ) | (588,207 | ) |
Net oil and natural gas properties | | 4,798,996 | | 4,407,636 | |
Other operating property and equipment: | | | | | |
Gas gathering and other operating assets | | 125,837 | | 59,748 | |
Less - accumulated depreciation | | (8,461 | ) | (8,119 | ) |
Net other operating property and equipment | | 117,376 | | 51,629 | |
Other noncurrent assets: | | | | | |
Goodwill | | — | | 227,762 | |
Receivables from derivative contracts | | 22,734 | | 371 | |
Debt issuance costs, net | | 64,308 | | 51,609 | |
Deferred income taxes | | 8,474 | | — | |
Equity in oil and gas partnerships | | 4,463 | | 11,137 | |
Funds in escrow and other | | 1,514 | | 3,024 | |
Total assets | | $ | 5,356,491 | | $ | 5,041,025 | |
| | | | | |
Current liabilities: | | | | | |
Accounts payable and accrued liabilities | | $ | 636,589 | | $ | 590,551 | |
Liabilities from derivative contracts | | 17,859 | | 10,429 | |
Asset retirement obligations | | 71 | | 2,319 | |
Current portion of deferred income taxes | | 8,474 | | — | |
Current portion of long-term debt | | 1,389 | | — | |
Promissory notes | | — | | 74,669 | |
Total current liabilities | | 664,382 | | 677,968 | |
Long-term debt | | 3,183,823 | | 2,034,498 | |
Other noncurrent liabilities: | | | | | |
Liabilities from derivative contracts | | 19,333 | | 2,461 | |
Asset retirement obligations | | 39,186 | | 72,813 | |
Deferred income taxes | | — | | 160,055 | |
Other | | 2,157 | | 10 | |
Commitments and contingencies | | | | | |
Mezzanine equity: | | | | | |
Preferred stock: 1,000,000 shares of $0.0001 par value authorized; no and 10,880 shares of 8% Automatically Convertible, issued and outstanding as of December 31, 2013 and 2012, respectively | | — | | 695,238 | |
Stockholders’ equity: | | | | | |
Preferred stock: 1,000,000 shares of $0.0001 par value authorized; 345,000 and no shares of 5.75% Cumulative Perpetual Convertible Series A, issued and outstanding as of December 31, 2013 and 2012, respectively | | — | | — | |
Common stock: 670,000,000 and 336,666,666 shares of $0.0001 par value authorized; 415,729,962 and 259,802,377 shares issued; 415,729,962 and 258,152,468 shares outstanding at December 31, 2013 and 2012, respectively | | 41 | | 26 | |
Additional paid-in capital | | 2,953,786 | | 1,681,717 | |
Treasury stock: no and 1,649,909 shares at December 31, 2013 and 2012, respectively, at cost | | — | | (9,298 | ) |
Accumulated deficit | | (1,506,217 | ) | (274,463 | ) |
Total stockholders’ equity | | 1,447,610 | | 1,397,982 | |
Total liabilities and stockholders’ equity | | $ | 5,356,491 | | $ | 5,041,025 | |
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HALCÓN RESOURECS CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(In thousands)
| | Three Months Ended December 31, | | Years Ended December 31, | |
| | 2013 | | 2012 | | 2013 | | 2012 | |
Cash flows from operating activities: | | | | | | | | | |
Net income (loss) | | $ | (410,388 | ) | $ | (8,041 | ) | $ | (1,222,662 | ) | $ | (53,885 | ) |
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | | | | | | | | | |
Depletion, depreciation and accretion | | 143,391 | | 55,623 | | 463,655 | | 90,284 | |
Impairment charges | | 238,873 | | — | | 1,444,100 | | — | |
Deferred income tax provision (benefit) | | 175,642 | | (14,090 | ) | (159,239 | ) | (13,060 | ) |
Share-based compensation, net | | 5,118 | | 707 | | 17,112 | | 4,573 | |
Unrealized loss (gain) on derivative contracts | | (10,228 | ) | 8,530 | | 8,728 | | 11,727 | |
Amortization and write-off of deferred loan costs | | 1,313 | | (35 | ) | 2,656 | | 6,212 | |
Non-cash interest and amortization of discount and premium | | 630 | | 767 | | 2,025 | | 9,387 | |
Other expense (income) | | 6,668 | | (822 | ) | 1,427 | | (352 | ) |
Cash flow from operations before changes in working capital | | 151,019 | | 42,639 | | 557,802 | | 54,886 | |
Changes in working capital, net of acquisitions | | (48,700 | ) | 39,843 | | (63,878 | ) | 29,474 | |
Net cash provided by (used in) operating activities | | 102,319 | | 82,482 | | 493,924 | | 84,360 | |
| | | | | | | | | |
Cash flows from investing activities: | | | | | | | | | |
Oil and natural gas capital expenditures | | (551,476 | ) | (467,183 | ) | (2,380,445 | ) | (1,183,295 | ) |
Proceeds received from sales of oil and natural gas assets | | 288,031 | | 21,964 | | 448,299 | | 21,964 | |
Acquisition of GeoResources, Inc., net of cash acquired | | — | | — | | — | | (579,497 | ) |
Acquisition of East Texas Assets | | — | | — | | — | | (296,139 | ) |
Acquisition of Williston Basin Assets | | (532 | ) | (756,056 | ) | (32,713 | ) | (756,056 | ) |
Other operating property and equipment capital expenditures | | (19,224 | ) | (20,345 | ) | (139,295 | ) | (38,478 | ) |
Funds held in escrow and other | | 9,002 | | 1,470 | | 3,455 | | (965 | ) |
Net cash provided by (used in) investing activities | | (274,199 | ) | (1,220,150 | ) | (2,100,699 | ) | (2,832,466 | ) |
| | | | | | | | | |
Cash flows from financing activities: | | | | | | | | | |
Proceeds from borrowings | | 965,000 | | 1,184,353 | | 3,725,000 | | 2,466,608 | |
Repayments of borrowings | | (786,000 | ) | (327,000 | ) | (2,644,400 | ) | (655,000 | ) |
Debt issuance costs | | (4,571 | ) | (29,221 | ) | (23,873 | ) | (52,878 | ) |
Offering costs | | (33 | ) | (84 | ) | (17,346 | ) | (18,619 | ) |
Common stock repurchased | | — | | — | | — | | (2,139 | ) |
Series A preferred stock issued | | — | | — | | 345,000 | | — | |
Preferred stock issued | | — | | — | | — | | 311,556 | |
Preferred beneficial conversion feature | | — | | — | | — | | 88,445 | |
Common stock issued | | — | | 294,000 | | 222,870 | | 569,000 | |
Warrants issued | | — | | — | | — | | 43,590 | |
Other | | (143 | ) | — | | (148 | ) | — | |
Net cash provided by (used in) financing activities | | 174,253 | | 1,122,048 | | 1,607,103 | | 2,750,563 | |
| | | | | | | | | |
Net increase (decrease) in cash | | 2,373 | | (15,620 | ) | 328 | | 2,457 | |
| | | | | | | | | |
Cash at beginning of period | | 461 | | 18,126 | | 2,506 | | 49 | |
Cash at end of period | | $ | 2,834 | | $ | 2,506 | | $ | 2,834 | | $ | 2,506 | |
| | | | | | | | | |
Supplemental cash flow information: | | | | | | | | | |
Cash paid for interest, net of capitalized interest | | $ | 24,028 | | $ | 11,344 | | $ | 25,462 | | $ | 11,705 | |
Cash paid for income taxes | | — | | 3,842 | | 9,014 | | 89 | |
| | | | | | | | | |
Disclosure of non-cash investing and financing activities: | | | | | | | | | |
Accrued capitalized interest | | $ | (659 | ) | $ | 22,124 | | $ | 9,890 | | $ | 33,814 | |
Asset retirement obligations | | (49,549 | ) | 7,898 | | (39,472 | ) | 8,587 | |
Non-cash preferred dividend | | — | | — | | — | | 88,445 | |
Series A preferred dividends paid in common stock | | 4,959 | | — | | 9,092 | | — | |
Payment-in-kind interest | | — | | — | | — | | 14,669 | |
Common stock issued for GeoResources, Inc. | | — | | — | | — | | 321,416 | |
Common stock issued for East Texas Assets | | — | | — | | — | | 130,623 | |
Preferred stock issued for Williston Basin Assets | | — | | 695,238 | | — | | 695,238 | |
Current notes payable issued for oil and natural gas properties | | — | | 74,669 | | — | | 74,669 | |
Payable for acquisition of oil and natural gas properties | | 2,157 | | — | | 2,157 | | — | |
12
HALCÓN RESOURCES CORPORATION
SELECTED OPERATING DATA (Unaudited)
| | Three Months Ended December 31, | | Years Ended December 31, | |
| | 2013 | | 2012 | | 2013 | | 2012 | |
Production volumes: | | | | | | | | | |
Crude oil (MBbls) | | 3,120 | | 1,264 | | 10,148 | | 2,415 | |
Natural gas (MMcf) | | 2,116 | | 1,914 | | 8,003 | | 4,554 | |
Natural gas liquids (MBbls) | | 227 | | 105 | | 683 | | 268 | |
Total (MBoe) | | 3,700 | | 1,688 | | 12,165 | | 3,442 | |
Average daily production (Boe) | | 40,217 | | 18,348 | | 33,329 | | 9,404 | |
| | | | | | | | | |
Average prices: | | | | | | | | | |
Crude oil (per Bbl) | | $ | 87.30 | | $ | 90.19 | | $ | 93.08 | | $ | 92.36 | |
Natural gas (per Mcf) | | 3.47 | | 3.06 | | 3.41 | | 2.80 | |
Natural gas liquids (per Bbl) | | 37.83 | | 39.05 | | 35.96 | | 41.72 | |
Total per Boe | | 77.92 | | 73.44 | | 81.91 | | 71.75 | |
| | | | | | | | | |
Cash effect of derivative contracts: | | | | | | | | | |
Crude oil (per Bbl) | | $ | (1.03 | ) | $ | 1.66 | | $ | (2.42 | ) | $ | 0.89 | |
Natural gas (per Mcf) | | 0.23 | | 0.44 | | 0.25 | | 0.82 | |
Natural gas liquids (per Bbl) | | — | | — | | — | | — | |
Total per Boe | | (0.73 | ) | 1.74 | | (1.85 | ) | 1.70 | |
| | | | | | | | | |
Average prices computed after cash effect of settlement of derivative contracts: | | | | | | | | | |
Crude oil (per Bbl) | | $ | 86.27 | | $ | 91.85 | | $ | 90.66 | | $ | 93.25 | |
Natural gas (per Mcf) | | 3.70 | | 3.50 | | 3.66 | | 3.62 | |
Natural gas liquids (per Bbl) | | 37.83 | | 39.05 | | 35.96 | | 41.72 | |
Total per Boe | | 77.19 | | 75.18 | | 80.06 | | 73.45 | |
| | | | | | | | | |
Average cost per Boe: | | | | | | | | | |
Production: | | | | | | | | | |
Lease operating, as adjusted (1) | | $ | 12.03 | | $ | 11.70 | | $ | 11.44 | | $ | 14.34 | |
Workover and other | | 0.54 | | 1.21 | | 0.52 | | 1.29 | |
Taxes other than income | | 7.03 | | 5.69 | | 7.28 | | 5.59 | |
Gathering and other | | 1.31 | | 0.11 | | 0.97 | | 0.13 | |
Restructuring | | 1.07 | | 0.40 | | 0.37 | | 0.70 | |
General and administrative, as adjusted (1) | | 6.78 | | 14.47 | | 8.99 | | 15.81 | |
Depletion | | 38.08 | | 32.03 | | 37.28 | | 25.05 | |
(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 | | $ | 9.06 | | $ | 26.67 | | $ | 10.89 | | $ | 32.35 | |
Share-based compensation: | | | | | | | | | |
Cash | | — | | — | | — | | (0.11 | ) |
Non-cash | | (1.38 | ) | (0.42 | ) | (1.41 | ) | (0.61 | ) |
Recapitalization and change in control: | | | | | | | | | |
Cash | | — | | — | | — | | (3.10 | ) |
Non-cash | | — | | — | | — | | (0.72 | ) |
Acquisition and merger transaction costs: | | | | | | | | | |
Cash | | (0.90 | ) | (11.78 | ) | (0.49 | ) | (12.00 | ) |
General and administrative, as adjusted | | $ | 6.78 | | $ | 14.47 | | $ | 8.99 | | $ | 15.81 | |
| | | | | | | | | |
Lease operating: | | | | | | | | | |
Lease operating, as reported | | $ | 12.03 | | $ | 11.70 | | $ | 11.44 | | $ | 14.49 | |
Recapitalization and change in control: | | | | | | | | | |
Cash | | — | | — | | — | | (0.15 | ) |
Lease operating, as adjusted | | $ | 12.03 | | $ | 11.70 | | $ | 11.44 | | $ | 14.34 | |
| | | | | | | | | |
Total operating costs, as reported | | $ | 29.97 | | $ | 45.38 | | $ | 31.10 | | $ | 53.85 | |
Total adjusting items | | (2.28 | ) | (12.20 | ) | (1.90 | ) | (16.69 | ) |
Total operating costs, as adjusted (2) | | $ | 27.69 | | $ | 33.18 | | $ | 29.20 | | $ | 37.16 | |
(2) Represents lease operating, workover and other expense, taxes other than income, gathering and other expense and general and administrative costs per Boe, adjusted for items noted in reconciliation above.
13
HALCÓN RESOURCES CORPORATION
SELECTED ITEM REVIEW AND RECONCILIATION (Unaudited)
(In thousands, except per share amounts)
| | Three Months Ended December 31, | | Years Ended December 31, | |
| | 2013 | | 2012 | | 2013 | | 2012 | |
As Reported: | | | | | | | | | |
Net income (loss) available to common stockholders, as reported | | $ | (415,347 | ) | $ | (8,041 | ) | $ | (1,233,407 | ) | $ | (142,330 | ) |
Non-cash preferred dividend | | — | | — | | — | | 88,445 | |
Series A preferred dividends | | 4,959 | | — | | 10,745 | | — | |
Net income (loss) | | (410,388 | ) | (8,041 | ) | (1,222,662 | ) | (53,885 | ) |
| | | | | | | | | |
Impact of Selected Items: | | | | | | | | | |
Unrealized loss (gain) on derivatives contracts: | | | | | | | | | |
Crude oil | | $ | (13,502 | ) | $ | 8,936 | | $ | 9,606 | | $ | 11,606 | |
Natural gas | | 3,273 | | 146 | | 544 | | 2,117 | |
Interest rate | | — | | — | | — | | (518 | ) |
Total mark-to-market non-cash charge | | (10,229 | ) | 9,082 | | 10,150 | | 13,205 | |
Impairment charges | | 238,873 | | — | | 1,444,100 | | — | |
Deferred financing costs expensed, net(1) | | 955 | | — | | 1,846 | | — | |
Recapitalization expenditures(2) | | — | | — | | — | | 21,980 | |
Restructuring | | 3,964 | | 674 | | 4,471 | | 2,406 | |
Acquisition and merger transaction costs and other | | 3,336 | | 19,882 | | 5,921 | | 41,294 | |
Selected items, before income taxes | | 236,899 | | 29,638 | | 1,466,488 | | 78,885 | |
Income tax effect of selected items(3) | | 177,574 | | (11,074 | ) | (182,888 | ) | (28,951 | ) |
Selected items, net of tax | | 414,473 | | 18,564 | | 1,283,600 | | 49,934 | |
| | | | | | | | | |
As Adjusted: | | | | | | | | | |
Net income (loss) available to common stockholders, excluding selected items | | $ | 4,085 | | $ | 10,523 | | $ | 60,938 | | $ | (3,951 | ) |
Interest on convertible debt, net | | — | | — | | 6,724 | | — | |
Net income (loss) available to common stockholders after assumed conversions, excluding selected items(4) | | $ | 4,085 | | $ | 10,523 | | $ | 67,662 | | $ | (3,951 | ) |
| | | | | | | | | |
Basic net income (loss) per common share, as reported | | $ | (1.01 | ) | $ | (0.04 | ) | $ | (3.25 | ) | $ | (0.91 | ) |
Impact of selected items | | 1.02 | | 0.08 | | 3.41 | | 0.88 | |
Basic net income (loss) per common share, excluding selected items(4) | | $ | 0.01 | | $ | 0.04 | | $ | 0.16 | | $ | (0.03 | ) |
| | | | | | | | | |
Diluted net income (loss) per common share, as reported | | $ | (1.01 | ) | $ | (0.04 | ) | $ | (3.25 | ) | $ | (0.91 | ) |
Impact of selected items | | 1.02 | | 0.06 | | 3.40 | | 0.88 | |
Diluted net income (loss) per common share, excluding selected items(4)(5) | | $ | 0.01 | | $ | 0.02 | | $ | 0.15 | | $ | (0.03 | ) |
| | | | | | | | | |
Net cash provided by (used in) operating activities | | $ | 102,319 | | $ | 82,482 | | $ | 493,924 | | $ | 84,360 | |
Changes in working capital, net of acquisitions | | 48,700 | | (39,843 | ) | 63,878 | | (29,474 | ) |
Cash flow from operations before changes in working capital | | 151,019 | | 42,639 | | 557,802 | | 54,886 | |
Cash components of selected items | | 6,464 | | 20,556 | | 9,556 | | 57,366 | |
Income tax effect of selected items | | (2,318 | ) | (7,690 | ) | (3,455 | ) | (21,052 | ) |
Cash flow from operations before changes in working capital, adjusted for selected items(4) | | $ | 155,165 | | $ | 55,505 | | $ | 563,903 | | $ | 91,200 | |
(1) Represents charges related to the write-off of debt issuance costs associated with decreases in the Company’s borrowing base under its senior revolving credit facility.
(2) Represents costs related to the recapitalization, change in control and credit facility refinancing.
(3) For the 2013 columns, this represents tax impact using an estimated tax rate of 36.16%. These columns are also adjusted for $84.5 million (year-to-date) and $0.4 million (quarter-to-date) associated with the writeoff of goodwill which is non-deductible for income tax purposes and a $262.8 million adjustment for the change in valuation allowance.
(4) Net income (loss) and earnings per share excluding selected items and cash flow from operations before changes in working capital adjusted for selected items are non-GAAP measures. These financial measures are presented based on management’s belief that they will enable a user of the financial information to understand the impact of these items on reported results. Additionally, this presentation provides a beneficial comparison to similarly adjusted measurements of prior periods. These financial measures are not measures of financial performance under GAAP and should not be considered as an alternative to net income, earnings per share and cash flow from operations, as defined by GAAP. These financial measures may not be comparable to similarly named non-GAAP financial measures that other companies may use and may not be useful in comparing the performance of those companies to Halcón’s performance.
(5) The impact of selected items for the three months and year ended December 31, 2013 was calculated based upon weighted average diluted shares of 412.3 million and 457.3 million, respectively, due to the net income available to common stockholders, excluding selected items.
14
