Exhibit 99.1
PETROHAWK ANNOUNCES THIRD QUARTER 2009
FINANCIAL AND OPERATING RESULTS
Company Expects to Grow Production 75% Over 2008
2010 Production Guidance Increased to 43% Over 2009
$1 Billion in Divestments Targeted for 2010
Haynesville and Eagle Ford Shale Plays Continue to Deliver Excellent Results
HOUSTON—November 4, 2009—Petrohawk Energy Corporation (“Petrohawk” or the “Company”) (NYSE:HK) today announced 1) its third quarter 2009 financial and operating results, including higher than expected production; 2) 2010 capital budget, production targets and planned divestments; 3) updated activities in the Haynesville and Eagle Ford Shales; 4) an expansion of its Eagle Ford Shale acreage position and 5) an evaluation of the Company’s Bossier Shale potential.
“The third quarter was defined by continued expansion of our activities in the Haynesville and Eagle Ford Shales. Today we detail plans that move these important assets to the forefront of our production and reserve profiles and predict significant production and reserve growth in the coming months and years,” said Floyd C. Wilson, Chairman and Chief Executive Officer. “Our focus is on seizing the substantial growth potential in these plays, how we plan to fuel that growth, and how we translate that growth into value for shareholders. The plans outlined today aim to balance 2010 cash flow and expenditures and accelerate drilling in these core shale plays, eliminating the need for future capital raises to fund their development.”
Production and Capital Expenditure Update
For the third quarter, Petrohawk reported production of 512 Mmcfe/d versus a guidance midpoint of 500 Mmcfe/d and second quarter production of 483 Mmcfe/d. Of the 512 Mmcfe/d, or 47,148 Mmcfe, produced during the quarter, 95% was natural gas. During 2009, Petrohawk has grown production at an average of approximately 12% per quarter. The Company’s previously stated guidance for fourth quarter 2009 was between 525 and 535 Mmcfe/d, which included production from the Permian Basin properties. Fourth quarter production is now expected to range between 565 and 575 Mmcfe/d, excluding the effect of Permian Basin production for two months of the quarter. With this increase in guidance for the fourth quarter, the Company is tracking to post 2009 average production of between 490 and 500 Mmcfe/d, or approximately 75% over 2008.
Petrohawk spent approximately $310 million on drilling, completions, seismic and workovers during the quarter. Petrohawk is increasing its budget for these expenditures in 2009 by $100 million, to $1.1 billion, to account for additional drilling and seismic opportunities in the Haynesville and Eagle Ford Shales. The Company has drilled 116
operated and non-operated Haynesville Shale wells year to date and is on track to meet its leasehold requirements in this important play.
Acquisitions and Divestitures
Petrohawk closed approximately $135 million in leasehold acquisitions during the third quarter, including: 1) Haynesville Shale acreage located in the company-defined core of the play in Northwest Louisiana; 2) Haynesville and Bossier Shale acreage located in the southern portion of the play and in East Texas (Nacogdoches / Shelby) Extension; 3) Eagle Ford Shale acreage contiguous to Petrohawk’s core activity area in McMullen and LaSalle Counties of South Texas; and 4) additional Eagle Ford Shale acreage in the Company’s newly announced oil prospective area in Dimmit County. During 2009, Petrohawk expects its total expenditures on leasehold acquisitions to be approximately $300 million.
For the year, Petrohawk has added approximately 53,000 net acres to its position in the Haynesville Shale play at a cost of approximately $190 million. By pairing the activities of its drilling and acquisition programs, Petrohawk expects that nearly half of the acreage acquired in the Haynesville Shale during 2009 is in units that will be drilled and evaluated in its year-end 2009 reserve estimate. The Company’s net acreage position in the Haynesville Shale now totals approximately 345,000 net acres.
Petrohawk has continued to be active in acquiring additional acreage in the Hawkville Field area, as well as the overall Eagle Ford Shale trend. Total net acreage in the Hawkville Field area has increased to over 225,000 net acres, a portion of which is located outside of Hawkville Field. On November 2, 2009, Petrohawk closed on the acquisition of approximately 13,000 net acres located in McMullen County, adjacent to its existing Eagle Ford Shale position at Hawkville Field for total consideration of approximately $39 million. During the course of 2009, the Company has expanded its position in the Hawkville Field area by approximately 20 miles to the northeast.
Petrohawk completed the sale of its Permian Basin assets on October 30, 2009 for $376 million, subject to ordinary post-closing adjustments. These properties accounted for 177 Bcfe in estimated proved reserves as of December 31, 2008 and were producing approximately 30 Mmcfe/d.
2010 Production Guidance and Capital Budget
Production guidance for 2010 is being increased to between 665 and 685 Mmcfe/d, which represents a 43% pro forma increase over 2009, taking into account the sale of the Permian Basin properties.
Petrohawk has established a drilling and completion budget of $1.45 billion for 2010. The 2010 budget will be heavily weighted to activities in the Haynesville Shale, comprising $900 million or 62% of the total drilling and completion budget. The Eagle Ford Shale is allocated $350 million, or 24% of this budget, and the Fayetteville Shale is allocated $100 million, or 7%. The remaining 7% is expected to be spent in other areas, including the Company’s conventional drilling program in North Louisiana.
Petrohawk’s midstream subsidiary, Hawk Field Services, will have an estimated capital program of $250 million. Additionally, the Company expects to spend between $100 million and $300 million on ongoing leasing activities. A significant part of the capital plan will be funded through operating cash flow, a portion of which is protected through the Company’s hedging program, with the balance to be provided for by currently available liquidity.
To further enhance the Company’s liquidity position, Petrohawk has identified over $1 billion in potential asset transactions during 2010, which may include a transaction involving the Company’s midstream assets, divesting Terryville Field in northwest Louisiana, divesting its interest in the West Edmond Hunton Lime Unit in central Oklahoma as well as other non-core assets.
Financial Highlights
During the third quarter, Petrohawk generated revenues of $238 million and cash flows from operations before changes in working capital of approximately $152 million, or $0.52 per fully diluted common share (cash flow from operations before changes in working capital is a non-GAAP financial measure; see Condensed Consolidated Statements of Cash Flows in the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2009 for a reconciliation to net cash provided by operating activities).
Cash flows were substantially protected through the Company’s active hedging program. Third quarter revenues were $346 million, including a realized cash derivative gain of $108 million. During the third quarter, Petrohawk gained $2.40 per Mcf from hedging, bringing realized natural gas prices to $5.55 per Mcf. The Company also gained $1.57 per barrel from its hedging program during the quarter, bringing realized oil prices to $66.21 per barrel. Before the effect of hedges, Petrohawk realized 93% of NYMEX for its natural gas production and 95% of NYMEX for oil.
After adjusting for the effects of unrealized losses on derivatives, net income for the quarter was $0.11 per fully diluted common share, or $31.2 million after tax (see Selected Item Review and Reconciliation table for additional information). Before excluding selected items, the Company reported a net loss of $40.2 million, or $0.14 per fully diluted common share, for the quarter.
Cash costs (including lease operating, gathering and transportation, production taxes, workover, general and administrative, and interest expense) were $2.94 per Mcfe for the quarter. Lease operating expense was $0.44 per Mcfe for the quarter and is expected to trend lower in future quarters based on an increased proportion of production from the Haynesville Shale, as well as the effect of the sale of the Permian Basin properties. Depletion, depreciation and amortization (DD&A) expense, a non-cash item, for the third quarter was $1.94 per Mcfe.
Petrohawk closed its amended credit facility in October, which provided for a borrowing base of $1.3 billion, including $1.0 billion in capacity allocated to oil and gas reserves (already adjusted for the sale of the Permian Basin properties) plus up to an additional $300 million in value supplied by Hawk Field Services. Petrohawk’s liquidity at the end of the third quarter, prior to the closing of the Permian Basin sale, was approximately $1.1 billion.
Operational Highlights
During the third quarter, Petrohawk drilled 170 gross wells with 100% success. Of these, 92% were in the Haynesville, Eagle Ford and Fayetteville shales.
Q3 Operational Statistics
| | | | | | |
| | | Haynesville Shale | | Eagle Ford Shale | | Fayetteville Shale |
Operated Wells Drilled | | 24 | | 10 | | 8 |
Non-operated Wells Drilled | | 29 | | 1 | | 84 |
Total Wells Drilled | | 53 | | 11 | | 92 |
Average Operated Rigs Running | | 12 | | 2.5 | | 1 |
Average Operated Well IP (Mmcfe/d) | | 18.6(normally produced) 8.5(test constrained) | | 8.0 | | 1.7 |
Average Cost per Operated Well (Drill & Complete) ($MM) | | 9.5 | | 5.3 | | 2.6 |
2010 Target Cost per Operated Well (Drill & Complete) ($MM) | | 8.0-9.0 | | 4.5-5.0 | | N/A1 |
1 Petrohawk will target deeper wells in the Fayetteville Shale in 2010 that are not comparable to 2009 well types.
Haynesville Shale
The Company drilled a total of 24 operated wells in the Haynesville Shale during the third quarter. Twenty-three wells were in Northwest Louisiana and one well was located in Shelby County, Texas. Eighteen of the wells were completed during the quarter. Of these, fourteen were produced according to normal procedure with an average initial production rate of 18.6 Mmcfe/d, ranging from 12.6 Mmcfe/d to 25.5 Mmcfe/d. Petrohawk currently has 62 operated Haynesville Shale wells on production with current gross operated production of approximately 450 Mmcfe/d and net operated production of approximately 285 Mmcfe/d. Of the 62 operated wells that are currently producing, there are now 53 wells that have greater than 30 days of production. The average initial 30-day production rate for those wells is 14 Mmcfe/d.
Included in the 62 operated wells that are currently on production are four wells being tested at restricted rates to compare the decline characteristics of the test wells to other wells in the same area that have been produced conventionally. The four test wells, which have been kept on a 14/64” choke since first production, had initial production rates of between 8-9 Mmcfe/d and flowing casing pressures of approximately 8500#. They have all exhibited shallower decline rates in both production and flowing pressure than the control set. The oldest well in the group has produced approximately 900 Mmcfe and has considerably higher flowing pressure than the control wells had at the same cumulative production. Further study of the economic and reservoir implications of this reduced rate method are needed before any conclusions are reached that would impact the Company’s production practices.
Petrohawk accomplished a significant reduction in average drilling days per well during the quarter in the Haynesville Shale operations, primarily due to more efficient rigs and faster rates of penetration during the horizontal lateral drilling phase. From January through June 2009 the average days from spud to spud for all Haynesville Shale “grass roots” wells (wells drilled from spud to total depth with the same rig) was approximately 68 days. In July, that number decreased to just over 61 days and in August decreased to less than 47. The Company’s current forecast for average drilling days per well in 2010 is 42 days, a 20% reduction from the expected 2009 average of 51 days and approximately a 50% reduction from average drilling days of 79 in 2008. A direct example of how this improvement has occurred is a review of the number of days in which greater than 800’ of drilling occurred in the lateral. Prior to third quarter 2009 there had been only 1 of these days. However, in the third quarter there were 22 of these days, with the most footage on any given day being greater than 1,700’. There are a number of factors that contributed to this improvement, with the most significant being construction of a new type of PDC bit that is specifically designed for the Haynesville Shale, as well as a much better understanding of the precise section within the Haynesville Shale to target the lateral in order to increase rate of penetration.
Completion techniques have also improved well performance. A combination of higher pump rates (as high as 100 barrels per minute), higher sand concentrations (up to 3 lbs. per gallon) and decreased distance between perforation clusters (50-65’ spacing as compared to 85’) have potentially increased the amount of rock contacted through fracing. These improved techniques have been employed in conjunction with a significant decrease in average completion cost. The average per well completion cost during 2009 has decreased from approximately $5.3 million in January to the current cost of $3.5 million. These improvements in the drilling and completion operations lead the Company to a revised view that 2010 drill and complete costs per well in the Haynesville Shale are expected to average between $8.0 and 9.0 million, versus a year to date 2009 average per well cost of $9.5 million.
Lower Bossier Shale Play
Petrohawk has been evaluating the Lower Bossier Shale in Northwest Louisiana and East Texas as a viable shale gas reservoir through an abundance of open hole log data, core data, and most recently a number of well tests by industry partners. The conclusions of this evaluation are that 1) the area of prospective commercial production within the Company’s current leasehold area is approximately 122,000 net acres; 2) the rock quality does approach that of the Haynesville Shale in a limited area of the play; and 3) the expected recovery from a Lower Bossier Shale well on average should be somewhat less than that of the Haynesville Shale, with an estimated range of between 5.0 and 6.0 Bcfe/well.
At this time, and pending advanced technology that would allow multiple zones to be completed with a single wellbore, the Bossier Shale will require wellbores independent of the Haynesville Shale. Petrohawk expects to drill its initial well to test the Lower Bossier in during the first quarter of 2010.
Eagle Ford Shale
Petrohawk drilled ten operated wells and one non-operated well during the third quarter in Hawkville Field. Seven of the operated wells were completed with an average initial production rate of 6.7 Mmcf/d and 220 Bc/d, or 8.0 Mmcfe/d using a 6:1 ratio for condensate, or 10.0 Mmcfe/d using a 15:1 ratio. There are currently sixteen operated wells on production. The average initial rate of all sixteen wells is approximately 7.8 Mmcf/d and 143 Bc/d, or 8.7 Mmcfe/d or 10.0 Mmcfe/d depending on which ratio is used. Current gross operated production is approximately 55 Mmcf/d and 1,300 Bc/d, or 75 Mmcfe/d using a 15:1 conversion ratio. Net operated production is currently approximately 49 Mmcfe/d using a 15:1 conversion ratio. Twelve of the sixteen wells on production have at least 30 days of production with the average rate during the first 30 days being 7.1 Mmcfe/d using a 15:1 conversion ratio.
Drilling operations in the Hawkville Field have continued to gain efficiencies with the average number of days from spud to total depth for the nine non-pilot holes drilled during the quarter being 19 days. This efficiency has resulted in an average spud to rig release cost of approximately $2.3 million, with current total drilling and completion costs averaging approximately $5.3 million. The Company currently has two operated rigs running and one non-operated rig working in the play. Petrohawk intends to focus drilling operations during the next quarter on the high condensate yield area of the field due to more restrictive hunting season restrictions in the dry gas window area and the Company’s desire to take advantage of the current disparity between condensate and natural gas prices.
In addition to the decrease in drilling days, Petrohawk is continuing to refine completion techniques used in the play. The first seven completions in Hawkville Field had an average lateral length of 3,736’ with an average of 10.6 stages pumped across an average stage length of 350’. The last nine completions had an average lateral length of 4,356’ with an average of 15.3 stages across an average stage length of 285’. In addition to the increased lateral length and associated increase in the number of stages and decreased stage length, the Company is increasing the sand concentration to 2.5-3.0#/gallon for each stage. These combined changes in the completion design appear to have resulted in better well performance that Petrohawk hopes will result in higher EUR’s. Additionally, the Company will be extending the lateral length on its wells to approximately 6,000-6,500’ when possible, a change that is also expected to translate into potentially better overall well performance.
Fayetteville Shale
Petrohawk drilled eight operated wells and 84 non-operated wells in the third quarter. The high level of non-operated activity has assisted in maintaining a steady rate of production growth throughout 2009, with the exception of short-term curtailments in the late third and early fourth quarter resulting from a combination of low commodity prices and repairs being made on the Boardwalk pipeline system. Average net production curtailed during the third quarter was approximately 5 Mmcfe/d. The Company expects curtailments will be less during the fourth quarter as the Boardwalk system returns to full production.
While the drilling activity during the third quarter appears to be very heavily weighted to the non-operated wells, Petrohawk and its primary non-operated partners achieved a comparable level of net drilling. The average working interest for the eight Petrohawk
operated wells was 48.5% (3.9 net wells). Of the 84 non-operated wells drilled, 49 were drilled by Southwestern Energy with an average 6.7% working interest (3.3 net wells) and 29 were drilled by Chesapeake Energy with an average 15.2% working interest (4.3 net wells). This level of drilling activity has resulted in increased total net production from 72 Mmcfe/d at the end of the first quarter to a maximum rate of 88 Mmcfe/d in late August prior to the onset of the previously mentioned curtailments.
Hawk Field Services
Petrohawk’s rapidly growing midstream business, Hawk Field Services (HFS) generated $55 million in revenues during the quarter, tracking to revenues of over $80 million for the year, primarily as the gathering and treating operator for Petrohawk’s production in the Haynesville Shale. HFS plans to continue to grow its transportation and treating capacity in the Haynesville and Eagle Ford Shales. HFS currently has six third-party customers and has been actively adding third party customers. By the end of 2009, HFS is expected to have approximately 375 miles of pipeline in service, with nearly 200 miles in the Haynesville Shale.
Petrohawk Earnings Conference Call and Webcast
Petrohawk will host a conference call tomorrow, Thursday, November 5, 2009 at 10:30 a.m. EST (9:30 a.m. CST) to discuss third quarter 2009 financial and operating results. To access, dial 800-644-8607 five to ten minutes before the call begins. Please reference Petrohawk Energy Conference ID 31504868. International callers may also participate by dialing 706-679-8184. In addition, the call will be webcast live on Petrohawk’s website athttp://www.petrohawk.com. A replay of the call will be available at that site through November 26, 2009.
Petrohawk Energy Corporation is an independent energy company engaged in the acquisition, production, exploration and development of natural gas and oil with properties concentrated in North Louisiana, Arkansas, East Texas, South Texas and Oklahoma.
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.
Additional Information for Investors
This press release contains information regarding initial and 30-day average rates of production that are subject to decline over time and should not be regarded as reflective of sustained production levels. Our current estimates are that the average rate of production from our Haynesville Shale wells will decline approximately 80%-85% during the first twelve months of production and the average rate of production from our Eagle Ford Shale wells will decline approximately 75%-80% during the first twelve months of production. Comparable rates of decline may be expected to be similar to rates of decline of shale wells in other areas, but insufficient data exists to estimate decline curves in these areas with any degree of certainty. Accordingly, actual decline rates may differ significantly.
This press release contains forward-looking information regarding Petrohawk that is intended to be covered by the safe harbor “forward-looking statements” provided by the Private Securities Litigation Reform Act of 1995, based on Petrohawk’s current expectations and forward-looking statements include statements regarding estimates of future production, capital expenditures and results of operations, and other statements reflecting 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) and include, without limitation, estimated production for 2009 and 2010 and estimated 2009 and 2010 capital expenditures. Management’s assumptions and future performance are subject to a wide range of business risks, uncertainties and actual levels of capital expenditures, and there is no assurance that these projections can or will be met. 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 these 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; uncertainties related to acquisitions and divestitures; risks associated with derivative positions; 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 Petrohawk’s operations or financial results are included in the section entitled “Risk Factors” in Petrohawk’s Annual Report on Form 10-K and its reports on Form 10-Q on file with the SEC. Investors are cautioned that any forward-looking statements are not guarantees of future performance and actual results or developments may differ materially from the expectations in the forward-looking statements. 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.
The SEC generally permits oil and gas companies, in filings made with the SEC, to disclose only proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. In this press release, we use the term “resource potential” which the SEC guidelines prohibit from being included in filings with the SEC. “Resource potential” refers to the Company’s internal estimates of hydrocarbon quantities that may be potentially discovered through
exploratory drilling or recovered with additional drilling or recovery techniques. Resource potential may not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System and does not include any proved reserves. Area wide resource potential has been risked using a risk factor selected by the Company’s management. Actual quantities that may be ultimately recovered from the Company’s interests will differ substantially. Factors affecting ultimate recovery include the scope of our ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and actual drilling results, including geological and mechanical factors affecting recovery rates. Estimates of resource potential may change significantly as development of the Company’s resource plays provides additional data. In addition, our production forecasts and expectations for future periods are dependant upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases.
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PETROHAWK ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(In thousands, except per share amounts)
| | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | | Nine Months Ended September 30, | |
| | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Operating revenues: | | | | | | | | | | | | | | | | |
Oil and natural gas | | $ | 174,783 | | | $ | 304,960 | | | $ | 512,528 | | | $ | 824,531 | |
Marketing | | | 63,155 | | | | — | | | | 216,165 | | | | — | |
| | | | | | | | | | | | | | | | |
Total operating revenues | | | 237,938 | | | | 304,960 | | | | 728,693 | | | | 824,531 | |
| | | | | | | | | | | | | | | | |
Operating expenses: | | | | | | | | | | | | | | | | |
Marketing | | | 66,586 | | | | — | | | | 211,722 | | | | — | |
Production: | | | | | | | | | | | | | | | | |
Lease operating | | | 20,788 | | | | 12,324 | | | | 55,903 | | | | 37,621 | |
Workover and other | | | 865 | | | | 1,696 | | | | 1,793 | | | | 3,482 | |
Taxes other than income | | | 15,204 | | | | 12,185 | | | | 39,921 | | | | 37,185 | |
Gathering, transportation and other | | | 22,743 | | | | 12,489 | | | | 65,870 | | | | 32,956 | |
General and administrative: | | | | | | | | | | | | | | | | |
General and administrative | | | 20,405 | | | | 15,607 | | | | 57,419 | | | | 43,296 | |
Stock-based compensation | | | 4,145 | | | | 3,389 | | | | 10,762 | | | | 9,068 | |
Depletion, depreciation and amortization | | | 91,692 | | | | 99,400 | | | | 290,383 | | | | 269,221 | |
Full cost ceiling impairment | | | — | | | | — | | | | 1,732,486 | | | | — | |
| | | | | | | | | | | | | | | | |
Total operating expenses | | | 242,428 | | | | 157,090 | | | | 2,466,259 | | | | 432,829 | |
| | | | | | | | | | | | | | | | |
(Loss) income from operations | | | (4,490 | ) | | | 147,870 | | | | (1,737,566 | ) | | | 391,702 | |
Other (expenses) income: | | | | | | | | | | | | | | | | |
Net (loss) gain on derivative contracts | | | (1,568 | ) | | | 388,216 | | | | 196,360 | | | | (32,130 | ) |
Interest expense and other | | | (58,981 | ) | | | (40,018 | ) | | | (170,929 | ) | | | (102,709 | ) |
| | | | | | | | | | | | | | | | |
Total other (expenses) income | | | (60,549 | ) | | | 348,198 | | | | 25,431 | | | | (134,839 | ) |
| | | | | | | | | | | | | | | | |
(Loss) income before income taxes | | | (65,039 | ) | | | 496,068 | | | | (1,712,135 | ) | | | 256,863 | |
Income tax benefit (provision) | | | 24,862 | | | | (190,603 | ) | | | 650,201 | | | | (99,776 | ) |
| | | | | | | | | | | | | | | | |
Net (loss) income available to common stockholders | | $ | (40,177 | ) | | $ | 305,465 | | | $ | (1,061,934 | ) | | $ | 157,087 | |
| | | | | | | | | | | | | | | | |
| | | | |
Net (loss) income per share of common stock: | | | | | | | | | | | | | | | | |
Basic | | $ | (0.14 | ) | | $ | 1.30 | | | $ | (3.88 | ) | | $ | 0.75 | |
| | | | | | | | | | | | | | | | |
Diluted | | $ | (0.14 | ) | | $ | 1.28 | | | $ | (3.88 | ) | | $ | 0.74 | |
| | | | | | | | | | | | | | | | |
| | | | |
Weighted average shares outstanding: | | | | | | | | | | | | | | | | |
Basic | | | 287,913 | | | | 235,235 | | | | 273,477 | | | | 208,549 | |
| | | | | | | | | | | | | | | | |
Diluted | | | 287,913 | | | | 239,479 | | | | 273,477 | | | | 212,503 | |
| | | | | | | | | | | | | | | | |
PETROHAWK ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)
(In thousands)
| | | | | | |
| | | September 30, | | December 31, |
| | | 2009 | | 2008 |
Assets: | | | | | | |
Current assets | | $ | 526,060 | | $ | 648,432 |
Net oil and natural gas properties | | | 4,157,027 | | | 5,071,287 |
Other noncurrent assets | | | 1,724,381 | | | 1,187,610 |
| | | | | | |
Total assets | | $ | 6,407,468 | | $ | 6,907,329 |
| | | | | | |
| | |
Liabilities and stockholders’ equity: | | | | | | |
Current liabilities | | $ | 693,656 | | $ | 726,312 |
Long-term debt | | | 2,394,270 | | | 2,283,874 |
Other noncurrent liabilities | | | 37,132 | | | 492,233 |
Stockholders’ equity | | | 3,282,410 | | | 3,404,910 |
| | | | | | |
Total liabilities and stockholders’ equity | | $ | 6,407,468 | | $ | 6,907,329 |
| | | | | | |
PETROHAWK ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(In thousands)
| | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | | Nine Months Ended September 30, | |
| | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Cash flows from operating activities: | | | | | | | | | | | | | | | | |
Net (loss) income | | $ | (40,177 | ) | | $ | 305,465 | | | $ | (1,061,934 | ) | | $ | 157,087 | |
Adjustments to reconcile net (loss) income to net cash provided by operating activities: | | | | | | | | | | | | | | | | |
Depletion, depreciation and amortization | | | 91,692 | | | | 99,400 | | | | 290,383 | | | | 269,221 | |
Full cost ceiling impairment | | | — | | | | — | | | | 1,732,486 | | | | — | |
Income tax (benefit) provision | | | (24,862 | ) | | | 190,603 | �� | | | (650,201 | ) | | | 99,776 | |
Stock-based compensation | | | 4,145 | | | | 3,389 | | | | 10,762 | | | | 9,068 | |
Net unrealized loss (gain) on derivative contracts | | | 115,171 | | | | (423,917 | ) | | | 96,752 | | | | (57,337 | ) |
Other | | | 6,466 | | | | 2,211 | | | | 15,926 | | | | 2,292 | |
| | | | | | | | | | | | | | | | |
Cash flow from operations before changes in working capital | | | 152,435 | | | | 177,151 | | | | 434,174 | | | | 480,107 | |
Changes in working capital | | | (3,801 | ) | | | 60,044 | | | | 40,576 | | | | 45,677 | |
| | | | | | | | | | | | | | | | |
Net cash provided by operating activities | | | 148,634 | | | | 237,195 | | | | 474,750 | | | | 525,784 | |
| | | | | | | | | | | | | | | | |
| | | | |
Cash flows from investing activities: | | | | | | | | | | | | | | | | |
Oil and natural gas capital expenditures | | | (416,290 | ) | | | (1,151,837 | ) | | | (1,164,392 | ) | | | (2,545,944 | ) |
Proceeds received from sale of oil and natural gas properties | | | 724 | | | | (3,576 | ) | | | 724 | | | | 107,324 | |
Marketable securities purchased | | | (519,509 | ) | | | (1,034,979 | ) | | | (1,282,601 | ) | | | (2,151,077 | ) |
Marketable securities redeemed | | | 386,501 | | | | 1,271,971 | | | | 1,255,582 | | | | 1,898,358 | |
Decrease in restricted cash | | | — | | | | — | | | | — | | | | 269,837 | |
Other operating property and equipment expenditures | | | (79,971 | ) | | | (44,484 | ) | | | (225,322 | ) | | | (75,525 | ) |
Other intangible assets acquired | | | (105,108 | ) | | | — | | | | (105,108 | ) | | | — | |
Other | | | 37,600 | | | | — | | | | 37,600 | | | | — | |
| | | | | | | | | | | | | | | | |
Net cash used in investing activities | | | (696,053 | ) | | | (962,905 | ) | | | (1,483,517 | ) | | | (2,497,027 | ) |
| | | | | | | | | | | | | | | | |
| | | | |
Cash flows from financing activities: | | | | | | | | | | | | | | | | |
Proceeds from exercise of options and warrants | | | 711 | | | | 510 | | | | 2,667 | | | | 10,770 | |
Proceeds from issuance of common stock | | | 571,500 | | | | 762,738 | | | | 956,500 | | | | 1,831,951 | |
Offering costs | | | (21,696 | ) | | | (29,037 | ) | | | (30,727 | ) | | | (73,754 | ) |
Proceeds from borrowings | | | 303,000 | | | | 368,000 | | | | 937,674 | | | | 1,964,000 | |
Repayment of borrowings | | | (307,354 | ) | | | (368,865 | ) | | | (849,513 | ) | | | (1,736,266 | ) |
Debt issue costs | | | 212 | | | | (4,832 | ) | | | (13,025 | ) | | | (23,391 | ) |
| | | | | | | | | | | | | | | | |
Net cash provided by financing activities | | | 546,373 | | | | 728,514 | | | | 1,003,576 | | | | 1,973,310 | |
| | | | | | | | | | | | | | | | |
| | | | |
Net (decrease) increase in cash | | | (1,046 | ) | | | 2,804 | | | | (5,191 | ) | | | 2,067 | |
Cash at beginning of period | | | 2,738 | | | | 1,075 | | | | 6,883 | | | | 1,812 | |
| | | | | | | | | | | | | | | | |
Cash at end of period | | $ | 1,692 | | | $ | 3,879 | | | $ | 1,692 | | | $ | 3,879 | |
| | | | | | | | | | | | | | | | |
PETROHAWK ENERGY CORPORATION
SELECTED OPERATING DATA (Unaudited)
(In thousands, except per unit and per share amounts)
| | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | | Nine Months Ended September 30, | |
| | | 2009 | | 2008 | | | 2009 | | 2008 | |
Production: | | | | | | | | | | | | | | |
Natural gas - Mmcf | | | 44,850 | | | 26,701 | | | | 120,926 | | | 71,637 | |
Crude oil - MBbl | | | 383 | | | 378 | | | | 1,204 | | | 1,128 | |
Natural gas equivalent - Mmcfe | | | 47,148 | | | 28,972 | | | | 128,150 | | | 78,405 | |
Daily production - Mmcfe | | | 512 | | | 315 | | | | 469 | | | 286 | |
| | | | |
Average price per unit: | | | | | | | | | | | | | | |
Realized oil price - as reported | | $ | 64.64 | | $ | 117.14 | | | $ | 51.82 | | $ | 110.17 | |
Realized impact of derivatives | | | 1.57 | | | (34.28 | ) | | | 3.38 | | | (30.47 | ) |
| | | | | | | | | | | | | | |
Net realized oil price (Bbl) | | $ | 66.21 | | $ | 82.86 | | | $ | 55.20 | | $ | 79.70 | |
| | | | | | | | | | | | | | |
| | | | |
Realized gas price - as reported | | $ | 3.15 | | $ | 9.68 | | | $ | 3.54 | | $ | 9.71 | |
Realized impact of derivatives | | | 2.40 | | | (0.85 | ) | | | 2.34 | | | (0.79 | ) |
| | | | | | | | | | | | | | |
Net realized gas price (Mcf) | | $ | 5.55 | | $ | 8.83 | | | $ | 5.88 | | $ | 8.92 | |
| | | | | | | | | | | | | | |
| | | | |
Cash flow from operations(1) | | | 152,435 | | | 177,151 | | | | 434,174 | | | 480,107 | |
Cash flow from operations - per share (diluted) | | | 0.52 | | | 0.74 | | | | 1.57 | | | 2.26 | |
| | | | |
Average cost per Mcfe: | | | | | | | | | | | | | | |
Production: | | | | | | | | | | | | | | |
Lease operating | | | 0.44 | | | 0.43 | | | | 0.44 | | | 0.48 | |
Workover and other | | | 0.02 | | | 0.06 | | | | 0.01 | | | 0.04 | |
Taxes other than income | | | 0.32 | | | 0.42 | | | | 0.31 | | | 0.47 | |
Gathering, transportation and other | | | 0.48 | | | 0.43 | | | | 0.51 | | | 0.42 | |
General and administrative: | | | | | | | | | | | | | | |
General and administrative | | | 0.43 | | | 0.54 | | | | 0.45 | | | 0.55 | |
Stock-based compensation | | | 0.09 | | | 0.12 | | | | 0.08 | | | 0.12 | |
Depletion | | | 1.85 | | | 3.39 | | | | 2.18 | | | 3.39 | |
| (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. |
PETROHAWK ENERGY CORPORATION
SELECTED ITEM REVIEW AND RECONCILIATION (Unaudited)
(In thousands, except per share amounts)
| | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | | Nine Months Ended September 30, | |
| | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Unrealized loss (gain) on derivatives:(1) | | | | | | | | | | | | | | | | |
Natural gas | | $ | 112,861 | | | $ | (374,622 | ) | | $ | 88,177 | | | $ | (51,111 | ) |
Crude oil | | | 30 | | | | (49,295 | ) | | | 8,575 | | | | (6,226 | ) |
Interest | | | 2,280 | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | |
Total mark-to-market noncash charge | | | 115,171 | | | | (423,917 | ) | | | 96,752 | | | | (57,337 | ) |
Full cost ceiling impairment | | | — | | | | — | | | | 1,732,486 | | | | — | |
Expense of deferred financing costs(2) | | | — | | | | — | | | | 911 | | | | 782 | |
Master limited partnership withdrawal | | | — | | | | — | | | | — | | | | 3,352 | |
| | | | | | | | | | | | | | | | |
Total selected items, before tax | | | 115,171 | | | | (423,917 | ) | | | 1,830,149 | | | | (53,203 | ) |
Income tax effect of selected items | | | (43,788 | ) | | | 162,403 | | | | (695,823 | ) | | | 20,382 | |
| | | | | | | | | | | | | | | | |
Selected items, net of tax | | | 71,383 | | | | (261,514 | ) | | | 1,134,326 | | | | (32,821 | ) |
Net loss available to common stockholders, as reported | | | (40,177 | ) | | | 305,465 | | | | (1,061,934 | ) | | | 157,087 | |
| | | | | | | | | | | | | | | | |
Net income available to common stockholders, excluding selected items | | $ | 31,206 | | | $ | 43,951 | | | $ | 72,392 | | | $ | 124,266 | |
| | | | | | | | | | | | | | | | |
Basic net loss per share of common stock, as reported | | $ | (0.14 | ) | | $ | 1.30 | | | $ | (3.88 | ) | | $ | 0.75 | |
Impact of selected items | | | 0.25 | | | | (1.11 | ) | | | 4.15 | | | | (0.16 | ) |
| | | | | | | | | | | | | | | | |
Basic net income per share of common stock, excluding selected items | | $ | 0.11 | | | $ | 0.19 | | | $ | 0.27 | | | $ | 0.59 | |
| | | | | | | | | | | | | | | | |
| | | | |
Diluted net loss per share of common stock, as reported | | $ | (0.14 | ) | | $ | 1.28 | | | $ | (3.88 | ) | | $ | 0.74 | |
Impact of selected items | | | 0.25 | | | | (1.09 | ) | | | 4.11 | | | | (0.15 | ) |
| | | | | | | | | | | | | | | | |
Diluted net income per share of common stock, excluding selected items | | $ | 0.11 | | | $ | 0.19 | | | $ | 0.23 | | | $ | 0.59 | |
| | | | | | | | | | | | | | | | |
| (1) | Represents the non-cash unrealized loss (gain) associated with the mark-to-market valuation of outstanding derivative contracts. |
| (2) | Represents non-cash charges related to the write-off of debt issue costs associated with the senior revolving credit facility. |
