Exhibit 99.1
PETROHAWK ENERGY CORPORATION REPORTS
RECORD RESULTS FOR THIRD QUARTER 2006
Company Achieves Production of 290 Mmcfe/d;
Operating Margin Improves 27% Over Prior Quarter
KCS Transaction Closed and Integrated;
Terryville Field Production Doubles
HOUSTON, November 2, 2006—Petrohawk Energy Corporation (“Petrohawk” or the “Company”) (NASDAQ: HAWK) today reported financial and operating results for the third quarter of 2006. During the quarter, Petrohawk achieved record net income of $52.7 million, or $0.33 per diluted share, and cash flows from operations before changes in working capital (a non-GAAP measure) of $112 million, or $0.70 per diluted share.
Petrohawk also provided a detailed update of current operations highlighting encouraging results from high-growth projects in all core areas. The Company’s performance was driven by the following factors:
| • | Substantial production increases in Terryville field, North Louisiana, from both the Cotton Valley and Gray Sands |
| • | Accelerated Cotton Valley drilling combined with high return Hosston recompletions in Elm Grove field, North Louisiana |
| • | Success in the 20-acre spacing pilot program in Elm Grove field |
| • | Exploration successes in South Texas and Mississippi |
| • | 32% quarter over quarter reduction in lease operating expenses |
| • | Realization of 99% of the third quarter’s NYMEX gas price (last trading day average) before effect of hedges |
| • | Increased revenues from strategic natural gas hedges of an additional $0.30 per Mcf |
“Our strategy – growth through acquisitions and drilling, strategic divestments, unit cost improvements and the creation of a significant portfolio of organic growth opportunities – is paying off,” said Floyd C. Wilson, Chairman, President and Chief Executive Officer. “We have delivered on our plan to create a balanced program of low-cost, low-risk development drilling complimented by high-potential exploratory drilling. After more than doubling the size of the company during the first half of 2006, we have also delivered 7% quarter-over-quarter pro forma production growth and have substantially managed volatile commodity prices through our hedging program. For the rest of the year, we look for record production volumes and revenues and substantial organic growth in 2007.”
Third Quarter Production Growth
| • | Petrohawk achieved record production during the quarter, averaging 290 Mmcfe/d, in line with its published guidance, representing a 195% increase over the prior year and a 127% increase over the previous quarter. Total production for the quarter was 21.9 Bcf of natural gas and 797 Mbbls of oil, or 26.7 Bcfe with 82% natural gas production. Without the effect of approximately 2.0 Mmcfe/d sold during the quarter, production would have been approximately 292 Mmcfe/d. Growth was mainly driven by incorporating operations from its acquisition of KCS Energy, Inc. (“KCS”) as of July 12, |
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as well as increases in production from high-margin, development drilling in the Elm Grove and Terryville fields of North Louisiana. |
Third Quarter Financial Highlights
| • | Petrohawk reported record revenues and cash flows for the quarter. The Company generated revenues for the quarter of $196 million, representing a 141% increase year over year. Cash flows from operations before changes in working capital (a non-GAAP measure) were $112 million, or $0.70 per fully diluted share. Year over year, cash flows from operations increased 131% and increased 141% from the previous quarter. |
| • | Petrohawk’s average prices from the sale of natural gas and oil were $6.52 per Mcf and $67.42 per Bbl respectively during the quarter, excluding the impact of hedges. Hedges increased average natural gas sales prices by $0.30 per Mcf and reduced average oil sales prices by $9.11 per Bbl. The Company’s results included a $68 million non-cash mark-to-market gain on its derivative position. Petrohawk does not elect hedge accounting. Approximately 44% of natural gas produced during the quarter was hedged at an average floor price of $6.89 per Mcf. |
| • | Production expense for the third quarter, which includes lease operating and workover expense, was $0.76 per Mcfe compared to $1.24 per Mcfe for the third quarter of 2005, a 39% per unit improvement, due to the acquisition of lower operating cost property, additional field level improvements, and the divestment of higher operating cost properties. Depletion, depreciation and amortization, a non-cash expense, was $89.2 million compared to $22.7 million for the same period last year, mainly attributable to higher production resulting from the Company’s acquisition activity. |
| • | Net income for the quarter reached $52.7 million, or $0.33 per fully diluted common share, before excluding selected items (see the Selected Item Review and Reconciliation table for additional information), compared to a ($0.56) loss per fully diluted share for the third quarter of 2005. |
| • | The Company also made significant progress in streamlining its capital structure and attained more favorable interest rates and debt ratings. The Company tendered for and retired its 8% Cumulative Convertible Preferred Stock and essentially all of its 9-7/8% Senior Notes. The Company issued 9-1/8% Senior Notes at a credit rating of B3/B as part of the financing of the KCS transaction. The Company’s second lien facility was also retired upon the closing of the KCS transaction. Additionally, Petrohawk’s corporate rating was upgraded to B2/B, reflecting the Company’s improved financial position. |
Third Quarter Operating Highlights – 105 wells, 98% Success
The Company participated in drilling 105 gross wells in the third quarter with a success rate of 98%. Of these wells, 72 were in the Mid-Continent region with a 100% success rate; 21 were in the Gulf Coast region with a 90% success rate; and 12 were in the Permian Basin region with a 100% success rate.
Petrohawk is currently running nine operated rigs in North Louisiana / East Texas, five operated rigs in the Onshore Gulf Coast and from one to two operated rigs in the Permian Basin.
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The Company’s highest-impact projects during the quarter include the following:
Mid-Continent Region
| • | Elm Grove / Caspiana Fields, Bossier & Caddo Parishes, Louisiana |
During the quarter, Petrohawk accelerated its low-risk, low-cost development program in Elm Grove and Caspiana fields, the most productive fields in the Company’s portfolio. Thirty-six wells were drilled in the region, of which 25 were operated with an average working interest (WI) of 82%. Gross operated field production is currently approximately 140 Mmcfe/d.
During the quarter the Company also utilized coiled tubing units to conduct approximately 10 Hosston recompletions per month, including the first such re-completions on the recently acquired Winwell acreage, confirming the viability of this technology on this property.
Four 20-acre Cotton Valley test wells were drilled during the quarter and an additional seven are planned for the fourth quarter. To date, all downspaced wells have indicated minimal or no drainage.
| • | Terryville Field, Lincoln Parish, Louisiana |
Six additional wells (average 89% WI) were drilled during the third quarter, utilizing two rigs and increasing gross operated field production from 20 Mmcfe/d at the end of the second quarter to 40 Mmcfe/d at the end of the third quarter. Included in the third quarter wells is the Wallace 9 #1 well (100% WI), which was completed in the deeper Gray sand and produced at an initial rate of 6.0 Mmcfe/d.
Petrohawk is also evaluating drilling on 40-acre spacing in this field. Drilling to date has been on 80 acre locations.
| • | Talihina Field, Latimer County, Oklahoma |
Three wells were drilled in the Talihina field in Panola County, Oklahoma (Avg. 32% WI), another Jackfork trend the Company is exploring. The Weyerhauser 22 #5 is producing at an initial rate of 2.2 Mmcfe/d. The Ellis 19 #3 tested at 2.2 Mmcfe/d and the third well is being completed.
| • | Activities on Petrohawk’s non-operated properties continue to be a significant portion of the drilling program. Twenty-five non-operated wells in various Mid-Continent fields were drilled in the third quarter with a success rate of 100%. |
Gulf Coast Region
| • | Lions Field, Goliad County, Texas |
During the third quarter, the Company acquired a new high density 3D seismic survey over the area and is accelerating seismic-based drilling in the field. The Weise #4 (45% WI) is nearing total depth of 15,500’. The Dehnert #2 (53% WI), completed during the second quarter, continues to produce approximately 15 Mmcfe/d. The Company expects to utilize one rig continuously to drill newly identified locations in the field. At least five additional wells are scheduled in 2007.
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| • | �� | Mission Rosario / Austin Fields, Goliad/Victoria Counties, Texas |
In the Mission Rosario field, the O’Connor Ranch #38 (100% WI) was completed in the Lower Wilcox with an initial rate of 3.3 Mmcfe/d. In the Austin field, the Salyer-Sherman #1 (59% WI) was completed in the Lower Wilcox with an initial production rate of 7.7 Mmcfe/d. The Company is also in the process of acquiring 3D seismic data in the area.
| • | La Reforma Field, Starr County, Texas |
The Guerra D #7 (50% WI) was completed in multiple Lower Vicksburg sands and had an initial production rate of 10.0 Mmcfe/d.
| • | Brushy Creek Prospect, Dewitt County, Texas |
The Company completed the McCabe #1 (50% WI) and re-completed the Pearce #1 (50% WI) in the Middle Wilcox for 1.6 Mmcfe/d and 1.4 Mmcfe/d, respectively.
| • | Dickinson Field, Galveston County, Texas |
Petrohawk completed two wells in this field, the Bayou Development “B” #20 and #22 (100% WI) for a combined rate of 2.0 Mmcfe/d.
| • | Coquat Field, Live Oak County, Texas |
The Meider #6 (50% WI) was completed in the Lower Wilcox with an initial rate of 7.2 Mmcfe/d.
Permian Region
Ten wells were completed in the Permian Basin during the third quarter, including six wells in the Waddell Ranch field (Crane County, Texas) and three wells in the Jalmat field (Lea County, New Mexico).
Fourth Quarter Outlook Update: Divestment Program Ahead of Plan; Exceptional Drilling Program Expected to Fuel Fourth Quarter Growth
During the third quarter, the Company sold certain non-core properties for $11.5 million. The properties were producing approximately 2 Mmcfe/d from 1,500 wellbores with an average lease operating cost of $2.60 per Mcfe.
Petrohawk has also entered into definitive agreements to sell previously identified non-core properties located in Wyoming and Michigan currently producing approximately 11 Mmcfe/d. The sales, which are subject to normal closing conditions and adjustments, are expected to generate proceeds of approximately $90 million and both are expected to close during the fourth quarter.
Solely to take into account production volumes associated with divestments during the third and fourth quarters, the Company is revising its fourth quarter production outlook by 6 Mmcfe/d, from between 330 Mmcfe/d to 340 Mmcfe/d to between 324 Mmcfe/d and 334 Mmcfe/d. The mid-point of this range represents 5% quarter over quarter proforma production growth.
As of November 1, Petrohawk’s net production totaled approximately 325 Mmcfe/d. The Company’s fourth quarter drilling schedule includes extensions of its established low-risk,
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development-style programs in North Louisiana as well as new areas where drilling is underway, including the following:
| • | Elm Grove / Caspiana Fields, Bossier & Caddo Parishes, Louisiana |
Petrohawk will continue to utilize five operated drilling rigs in the field and conduct ten coiled tubing re-completions per month.
| • | Terryville Field, Lincoln Parish, Louisiana |
Since the end of the third quarter an additional Lower Cotton Valley well, the LA Minerals 15 #2 (100% WI) has been completed at an initial production rate of 7.0 Mmcfe/d. Based on the successful drilling results, a third rig has been moved into the field to accelerate the development program.
In addition, a 60 square mile 3-D seismic shoot has been permitted to 1) enhance development of the Cotton Valley formation and 2) identify additional Gray Sand locations, which are approximately 1,000’ deeper than the Cotton Valley.
| • | Haley Field, Loving County, Texas |
The Bowdle 42 #3 well (48% WI) logged four payzones in the Morrow and Atoka sands. Following the first stage fracture stimulation, the well tested at 2.7 Mmcfe/d while the other three zones are scheduled to be fracture stimulated. Full well stream production is expected in mid-November.
| • | Flowers Prospect, Scott County, Arkansas |
Two operations have been initiated on this prospect. The USA 1 #1 re-entry well (76% WI) is currently being completed. Drilling operations on the Flowers 13 #1 (76% WI) targeting multiple Middle Atoka sands at 11,000’ are underway. The Company also plans to drill a third well during the quarter.
| • | Duderstadt Prospect, Goliad County, Texas |
The Company is in the process of a multi-stage completion program on the Parma #1 (33% WI) that should be finished in mid November. The initial test rate was 10.2 Mmcfe/d for the lowermost zone.
| • | Nabors Field. Starr County, Texas |
The Cleopatra #5 (100% WI) is in the process of being completed and has been fracture stimulated in four separate intervals which tested, combined, at a rate of 11.9 Mmcfe/d. The Company is also nearing total depth of 10,500’ on the offset Cleopatra #7 (100% WI) and will test similar Vicksburg sands with anticipated first production in late November.
| • | Winchester and Coldwater Creek Prospects, Wayne County, Mississippi |
The Board of Education 16-11 (33% WI) well has been completed in the Smackover section at a depth of approximately 15,500’ and was tested at a rate 1,200 Boe/d. The Clark 45 #1 well was drilled and logged an apparently productive Smackover section and will be tested shortly. The wells are currently waiting on pipeline connection and initial production is anticipated in December. A third exploration prospect is currently drilling and the first development well is scheduled for the fourth quarter.
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2007 Preview
The preliminary 2007 capital program anticipates drilling approximately 550 wells with a $620 million budget, resulting in projected increases in production volumes of 10-15% over pro-forma 2006 levels. Eighty-five percent of the capital is expected to be applied to continuing drilling programs predominantly focused on operated properties in North Louisiana and Onshore Gulf Coast.
Continuation of Hedging Strategy
The Company strives to hedge approximately 50-60% of expected production. Current hedge positions are summarized below.
| Fourth Quarter 2006 | 2007 | 2008 | ||||||||||||||||||||||
| GAS | GAS | GAS | ||||||||||||||||||||||
| Volume (MMbtu) | Floor | Ceiling | Volume (MMbtu) | Floor | Ceiling | Volume (MMbtu) | Floor | Ceiling | ||||||||||||||||
Collars | 6,066,000 | $ | 6.75 | $ | 10.79 | 40,725,000 | $ | 7.26 | $ | 11.38 | 12,740,000 | $ | 6.59 | $ | 10.91 | |||||||||
Swaps | 4,020,000 | $ | 6.72 | 3,455,000 | $ | 7.19 | ||||||||||||||||||
Puts | 1,350,000 | $ | 8.00 | 7,250,000 | $ | 8.00 | ||||||||||||||||||
Total (Mmbtu) / Avg price | 11,436,000 | $ | 6.89 | $ | 10.79 | 51,430,000 | $ | 7.36 | $ | 11.38 | 12,740,000 | $ | 6.59 | $ | 10.91 | |||||||||
| OIL | OIL | OIL | ||||||||||||||||||||||
| Volume (Bbls) | Floor | Ceiling | Volume (Bbls) | Floor | Ceiling | Volume (Bbls) | Floor | Ceiling | ||||||||||||||||
Collars | 377,600 | $ | 40.28 | $ | 53.34 | 1,736,034 | $ | 63.04 | $ | 81.53 | 792,000 | $ | 64.96 | $ | 80.26 | |||||||||
Swaps | 40,400 | $ | 53.74 | 36,045 | $ | 63.85 | 144,000 | $ | 38.10 | |||||||||||||||
Total (Bbls) / Avg price | 418,000 | $ | 41.58 | $ | 53.34 | 1,772,079 | $ | 63.05 | $ | 81.53 | 936,000 | $ | 60.83 | $ | 80.26 | |||||||||
Total (Mmcfe) | 13,944,000 | 62,062,474 | 18,356,000 | |||||||||||||||||||||
Petrohawk will hold a conference call November 3, 2006 at 10:00 a.m. CST (11:00 a.m. EST) to discuss this announcement. To access, dial 800-644-8607 five to ten minutes before the call begins. Please reference Petrohawk Energy Conference ID 9956611. International callers may also participate by dialing 706-679-8184. A replay of the call will be available approximately two hours after the live broadcast ends and will be accessible until November 10, 2006. To access the replay, please dial 800-642-1687 and reference conference ID 9956611. International callers may listen to a playback by dialing 706-645-9291.
Petrohawk Energy Corporation is an independent energy company engaged in the acquisition, production, exploration and development of oil and gas, with properties concentrated in the Mid-Continent, Gulf Coast and Permian regions.
For more information contact Joan Dunlap, Vice President – Investor Relations, at (832) 204-2737 or jdunlap@petrohawk.com. For additional information about Petrohawk, please visit our website at www.petrohawk.com.
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Additional Information for Investors
This press release contains “forward-looking statements” within the meaning of the US Private Securities Litigation Reform Act of 1995, based on Petrohawk’s current expectations and include statements regarding planned capital expenditures (including the amount and nature thereof), acquisitions and divestitures, estimates of future production, statements regarding business plans and timing for drilling and exploration expenditures, the number of wells we anticipate drilling in 2006 and 2007, the number and nature of potential drilling locations, future results of operations, quality and nature of the asset base, the assumptions upon which estimates are based and other expectations, beliefs, plans, objectives, assumptions, strategies or statements about future events or performance (often, but not always, using words such as “expects”, “anticipates”, “plans”, “estimates”, “potential”, “possible”, “probable”, or “intends”, or stating that certain actions, events or results “may”, “will”, “should”, or “could” be taken, occur or be achieved). Statements concerning oil and gas reserves also may be deemed to be forward looking statements in that they reflect estimates based on certain assumptions that the resources involved can be economically exploited. Forward-looking statements are based on current expectations, estimates and projections that involve a number of risks and uncertainties, which could cause actual results to differ materially from those, reflected in the statements. These risks include, but are not limited to: the risks of the oil and gas industry (for example, operational risks in exploring for, developing and producing crude oil and natural gas; risks and uncertainties involving geology of oil and gas deposits; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to future production, costs and expenses; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; health, safety and environmental risks and risks related to weather such as hurricanes and other natural disasters); uncertainties as to the availability and cost of financing; fluctuations in oil and gas prices; inability to realize expected value from acquisitions, inability of our management team to execute its plans to meet its goals, shortages of drilling equipment, oil field personnel and services, unavailability of gathering systems, pipelines and processing facilities and the possibility that government policies may change or governmental approvals may be delayed or withheld. Additional information on these and other factors which could affect either companies’ operations or financial results are included in the companies’ other reports on file with the United States Securities and Exchange Commission. Forward-looking statements are based on the estimates and opinions of management at the time the statements are made. Petrohawk does not assume any obligation to update forward-looking statements should circumstances or management’s estimates or opinions change.
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PETROHAWK ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(In thousands, except per share amounts)
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
| 2006 | 2005 | 2006 | 2005 | |||||||||||||
Operating revenues: | ||||||||||||||||
Oil and gas | $ | 196,439 | $ | 81,447 | $ | 385,859 | $ | 149,957 | ||||||||
Operating expenses: | ||||||||||||||||
Production: | ||||||||||||||||
Lease operating | 17,594 | 10,276 | 40,460 | 19,826 | ||||||||||||
Workover and other | 2,720 | 941 | 5,210 | 2,180 | ||||||||||||
Taxes other than income | 15,739 | 6,405 | 30,346 | 10,842 | ||||||||||||
Gathering, transportation and other | 5,178 | 515 | 9,314 | 1,135 | ||||||||||||
General and administrative: | ||||||||||||||||
General and administrative | 12,132 | 5,782 | 25,883 | 13,258 | ||||||||||||
Stock-based compensation | 3,173 | 780 | 5,041 | 3,003 | ||||||||||||
Depletion, depreciation and amortization | 89,212 | 22,730 | 164,120 | 45,238 | ||||||||||||
Total operating expenses | 145,748 | 47,429 | 280,374 | 95,482 | ||||||||||||
Income from operations | 50,691 | 34,018 | 105,485 | 54,475 | ||||||||||||
Other income (expenses): | ||||||||||||||||
Net gain (loss) on derivative contracts | 68,048 | (83,585 | ) | 94,495 | (120,568 | ) | ||||||||||
Interest expense and other | (35,870 | ) | (9,923 | ) | (55,865 | ) | (20,306 | ) | ||||||||
Total other income (expenses) | 32,178 | (93,508 | ) | 38,630 | (140,874 | ) | ||||||||||
Income (loss) before income taxes | 82,869 | (59,490 | ) | 144,115 | (86,399 | ) | ||||||||||
Income tax (provision) benefit | (30,213 | ) | 23,066 | (53,667 | ) | 33,521 | ||||||||||
Net income (loss) | 52,656 | (36,424 | ) | 90,448 | (52,878 | ) | ||||||||||
Preferred dividends | — | (110 | ) | (217 | ) | (329 | ) | |||||||||
Net income (loss) available to common shareholders | $ | 52,656 | $ | (36,534 | ) | $ | 90,231 | $ | (53,207 | ) | ||||||
Earnings (loss) per share of common stock: | ||||||||||||||||
Basic | $ | 0.34 | $ | (0.56 | ) | $ | 0.84 | $ | (1.10 | ) | ||||||
Diluted | $ | 0.33 | $ | (0.56 | ) | $ | 0.82 | $ | (1.10 | ) | ||||||
Weighted average shares outstanding: | ||||||||||||||||
Basic | 157,135 | 64,877 | 107,908 | 48,425 | ||||||||||||
Diluted | 159,647 | 64,877 | 110,706 | 48,425 | ||||||||||||
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)
(In thousands)
| September 30, 2006 | December 31, 2005 | |||||
Assets: | ||||||
Current assets | $ | 217,532 | $ | 105,981 | ||
Oil and gas properties, net | 3,100,587 | 1,140,950 | ||||
Other assets | 969,932 | 163,243 | ||||
Total assets | $ | 4,288,051 | $ | 1,410,174 | ||
Liabilities and stockholders’ equity: | ||||||
Current liabilities | $ | 283,203 | $ | 143,886 | ||
Long-term debt | 1,395,019 | 495,801 | ||||
Other noncurrent liabilities | 713,834 | 244,029 | ||||
Stockholders’ equity | 1,895,995 | 526,458 | ||||
Total liabilities and stockholders’ equity | $ | 4,288,051 | $ | 1,410,174 | ||
PETROHAWK ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(In thousands)
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
| 2006 | 2005 | 2006 | 2005 | |||||||||||||
Cash flows from operating activities: | ||||||||||||||||
Net income (loss) | $ | 52,656 | $ | (36,424 | ) | $ | 90,448 | $ | (52,878 | ) | ||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||||||
Depletion, depreciation and amortization | 89,212 | 22,730 | 164,120 | 45,238 | ||||||||||||
Income tax provision (benefit) | 30,213 | (22,732 | ) | 53,667 | (33,521 | ) | ||||||||||
Stock-based compensation | 3,173 | 780 | 5,041 | 3,003 | ||||||||||||
Net unrealized (gain) loss on derivative contracts | (68,713 | ) | 74,971 | (106,304 | ) | 109,543 | ||||||||||
Net realized loss on derivative contracts acquired | 4,663 | 9,657 | 14,597 | 9,657 | ||||||||||||
Other | 463 | (626 | ) | 88 | 889 | |||||||||||
Cash flow from operations before changes in working capital | 111,667 | 48,356 | 221,657 | 81,931 | ||||||||||||
Changes in working capital | (32,884 | ) | 4,407 | (39,333 | ) | 3,497 | ||||||||||
Net cash provided by operating activities | 78,783 | 52,763 | 182,324 | 85,428 | ||||||||||||
Cash flows from investing activities: | ||||||||||||||||
Oil and gas capital expenditures | (99,347 | ) | (51,588 | ) | (222,696 | ) | (88,427 | ) | ||||||||
Acquisition of KCS, net of cash acquired of $8,260 | (512,152 | ) | — | (512,152 | ) | — | ||||||||||
Acquisition of Winwell Resources, Inc., net of cash acquired of $14,965 | — | — | (175,037 | ) | — | |||||||||||
Acquisition of Mission Resources, net of cash acquired of $48,359 | — | (95,816 | ) | — | (95,816 | ) | ||||||||||
Acquisition of Proton Oil & Gas Corp., net of cash acquired of $870 | — | — | — | (52,625 | ) | |||||||||||
Acquisition of oil and gas properties | (2,598 | ) | — | (87,893 | ) | — | ||||||||||
Proceeds received from sale of oil and gas properties | 12,564 | 9,450 | 62,083 | 88,844 | ||||||||||||
Other | (11,877 | ) | (763 | ) | 10,117 | (1,741 | ) | |||||||||
Net cash used in investing activities | (613,410 | ) | (138,717 | ) | (925,578 | ) | (149,765 | ) | ||||||||
Cash flows from financing activities: | ||||||||||||||||
Proceeds from exercise of options | 1,624 | 10,958 | 2,466 | 11,780 | ||||||||||||
Proceeds from issuance of common stock | — | — | 188,500 | — | ||||||||||||
Acquisition of common stock | — | — | (46,200 | ) | — | |||||||||||
Proceeds from borrowings | 1,141,183 | 242,000 | 1,466,183 | 310,000 | ||||||||||||
Repayment of borrowings | (593,319 | ) | (159,000 | ) | (828,319 | ) | (249,000 | ) | ||||||||
Debt issue costs | (14,374 | ) | — | (14,374 | ) | — | ||||||||||
Net realized loss on derivative contracts acquired | (4,663 | ) | (9,657 | ) | (14,597 | ) | (9,657 | ) | ||||||||
Offering costs | (39 | ) | — | (10,725 | ) | — | ||||||||||
Buyback of 8% cumulative preferred stock | (942 | ) | 0 | (5,339 | ) | — | ||||||||||
Dividends paid on 8% cumulative referred stock | — | — | (328 | ) | (220 | ) | ||||||||||
Other | 994 | (46 | ) | (640 | ) | (46 | ) | |||||||||
Net cash provided by financing activities | 530,464 | 84,255 | 736,627 | 62,857 | ||||||||||||
Net decrease in cash | (4,163 | ) | (1,699 | ) | (6,627 | ) | (1,480 | ) | ||||||||
Cash: | ||||||||||||||||
Beginning of period | 3,642 | 6,359 | 12,911 | 5,660 | ||||||||||||
End of period | $ | (521 | ) | $ | 4,660 | $ | 6,284 | $ | 4,180 | |||||||
PETROHAWK ENERGY CORPORATION
SELECTED OPERATING DATA (Unaudited)
(In thousands, except per share amounts)
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
| 2006 | 2005 | 2006 | 2005 | |||||||||||||
Production: | ||||||||||||||||
Natural gas - Mmcf | 21,871 | 6,103 | 38,850 | 13,089 | ||||||||||||
Crude oil - Mbbl | 797 | 488 | 1,962 | 984 | ||||||||||||
Natural gas equivalent - Mmcfe | 26,652 | 9,032 | 50,622 | 18,994 | ||||||||||||
Daily production - Mmcfe | 290 | 98 | 185 | 70 | ||||||||||||
Average price per unit: | ||||||||||||||||
Realized oil price - as reported | $ | 67.42 | $ | 60.87 | $ | 64.96 | $ | 54.46 | ||||||||
Realized impact of derivatives | (9.11 | ) | (11.90 | ) | (9.09 | ) | (6.29 | ) | ||||||||
Net realized oil price | 58.31 | 48.97 | 55.87 | 48.17 | ||||||||||||
Realized gas price - as reported | 6.52 | 8.47 | 6.64 | 7.34 | ||||||||||||
Realized impact of derivatives | 0.30 | (0.47 | ) | 0.16 | (0.37 | ) | ||||||||||
Net realized gas price | 6.82 | 8.00 | 6.80 | 6.97 | ||||||||||||
Cash flow from operations(1) | 111,667 | 48,356 | 221,657 | 81,931 | ||||||||||||
Cash flow from operations - per share (diluted) | 0.70 | 0.75 | 2.00 | 1.69 | ||||||||||||
Average cost per Mcfe: | ||||||||||||||||
Production: | ||||||||||||||||
Lease operating | 0.66 | 1.14 | 0.80 | 1.04 | ||||||||||||
Workover and other | 0.10 | 0.10 | 0.10 | 0.11 | ||||||||||||
Taxes other than income | 0.59 | 0.71 | 0.60 | 0.57 | ||||||||||||
Gathering, transportation and other | 0.19 | 0.06 | 0.18 | 0.06 | ||||||||||||
General and administrative expense: | ||||||||||||||||
General and administrative | 0.46 | 0.64 | 0.51 | 0.70 | ||||||||||||
Stock-based compensation | 0.12 | 0.09 | 0.10 | 0.16 | ||||||||||||
Depletion expense | 3.32 | 2.46 | 3.20 | 2.32 | ||||||||||||
| (1) | Represents cash flow from operations before changes in working capital. See the Consolidated Statements of Cash Flows for a reconciliation from this non-GAAP financial measure to the most comparable GAAP financial measure. |
SELECTED ITEM REVIEW AND RECONCILIATION (Unaudited)
(In thousands, except per share amounts)
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
| 2006 | 2005 | 2006 | 2005 | |||||||||||||
Unrealized (gain) loss on derivatives:(1) | ||||||||||||||||
Natural gas | $ | (42,378 | ) | $ | 70,774 | $ | (83,700 | ) | $ | 89,165 | ||||||
Crude oil | (26,334 | ) | 4,137 | (22,604 | ) | 20,376 | ||||||||||
Total mark-to-market non-cash charge | (68,712 | ) | 74,911 | (106,304 | ) | 109,541 | ||||||||||
Stock based compensation | 3,173 | 780 | 5,041 | 3,003 | ||||||||||||
Interest payment(2) | — | — | — | 2,411 | ||||||||||||
Expense of deferred financing costs(3) | — | — | — | 1,061 | ||||||||||||
9 7/8% Note extinguishment(4) | 5,831 | — | 5,831 | — | ||||||||||||
Second Lien extinguishment(5) | 1,750 | — | 1,750 | — | ||||||||||||
Loss on extinguishment of debt | — | 2,875 | 1,500 | 2,875 | ||||||||||||
Total selected items, before tax | (57,958 | ) | 78,566 | (92,182 | ) | 118,891 | ||||||||||
Income tax effect of selected items | 21,269 | (30,462 | ) | 33,828 | (46,127 | ) | ||||||||||
Selected items, net of tax | (36,690 | ) | 48,104 | (58,354 | ) | 72,764 | ||||||||||
Net income (loss) available (applicable) to common shareholders, as reported | 52,656 | (36,534 | ) | 90,231 | (53,207 | ) | ||||||||||
Net income available to common shareholders, excluding selected items | $ | 15,966 | $ | 11,570 | $ | 31,877 | $ | 19,557 | ||||||||
Basic income (loss) per share, as reported | $ | 0.34 | $ | (0.56 | ) | $ | 0.84 | $ | (1.10 | ) | ||||||
Impact of selected items | (0.24 | ) | 0.74 | (0.54 | ) | 1.50 | ||||||||||
Basic income per share, excluding selected items | $ | 0.10 | $ | 0.18 | $ | 0.30 | $ | 0.40 | ||||||||
Diluted income (loss) per share, as reported | $ | 0.33 | $ | (0.56 | ) | $ | 0.82 | $ | (1.10 | ) | ||||||
Impact of selected items | (0.23 | ) | 0.74 | (0.53 | ) | 1.50 | ||||||||||
Diluted income per share, excluding selected items(6) | $ | 0.10 | $ | 0.18 | $ | 0.29 | $ | 0.40 | ||||||||
| (1) | Represents the unrealized (gain) loss associated with the mark-to-market valuation of outstanding derivative positions at September 30, 2006 and 2005. |
| (2) | Represents interest that would have been payable on the $35 million subordinated convertible note payable had the note been held until May 25, 2006, discounted at 10%. |
| (3) | Represents a non-cash charge related to the conversion of the $35 million subordinated convertible note payable into 8.75 million shares of common stock. |
| (4) | Represents the net impact of the extinguishment of the 9 7/8% notes assumed in conjunction with the Mission merger in July 2005. Amount includes a non-cash credit of $9.1 million related to the write-off of a premium recorded in conjunction with purchase accounting. Amount also includes a cash charge of $14.9 million related to the premium paid to the noteholders upon extinguishment of the notes. |
| (5) | Represents a prepayment penalty on the early extinguishment of the second lien note. |
| (6) | Preferred dividends have been added back for the diluted earnings per share calculations for the three and nine months ended September 30, 2006. |
