Exhibit 99.1

Petrohawk Energy Corporation Announces 2010 Operational Update

Pro Forma Production Grows 70%, Pro Forma Proved Reserves Up 50%

Strong Infrastructure Growth Forecast

HOUSTON, February 1, 2011 — Petrohawk Energy Corporation (“Petrohawk” or the “Company”) (NYSE: HK) today announced 2010 drilling and production results, as well as updated estimates of the Company’s total resource potential.

Petrohawk announced 3.4 trillion cubic feet of natural gas equivalent (Tcfe) of estimated proved reserves at December 31, 2010 represents 50% year over year reserve growth pro forma for approximately 500 Bcfe which were divested during 2010. Not adjusted for sales, Petrohawk grew reserves 23% year over year.

Of the Company’s 3.4 Tcfe of proved reserves (92% natural gas), approximately 1.4 Tcfe were added through the drillbit in 2010. Approximately 973 Bcfe were added in the Haynesville Shale with 351 wells drilled (101 operated and 250 non-operated), 467 Bcfe in the Eagle Ford Shale with 73 wells drilled (68 operated and 5 non-operated), and 14 Bcfe in the Bossier Shale with 16 wells drilled (1 operated and 15 non-operated).

Production of 562 million cubic feet of natural gas equivalent per day (Mmcfe/d), pro forma for approximately 113 Mmcfe/d which was divested during the year, represented 70% year over year growth.  Production before taking asset sales into account averaged 675 Mmcfe/d, or 34% growth over 2009. During 2010, approximately 70% of production was hedged with floors averaging $5.83/Mmbtu and $78.31/Bbl.

Petrohawk estimates that 2011 production will consist of approximately 12% crude oil, condensate and natural gas liquids, compared to 5% of production in 2010. Further, the Company estimates that approximately 27% of 2011 oil and gas revenue will be derived from crude oil, condensate and natural gas liquids. Petrohawk expects to exit 2011 with over 15% of production from crude oil, condensate and natural gas liquids.

The Company updated non-proved resource potential estimates Eagle Ford Shale, Haynesville and Lower Bossier Shales, detailed below.  The sum of those non-proved resource potential volumes is 28.3 Tcf, 592 Mmbc and 520 Mmbngl.  Of this total, only 261 Bcf, 1 Mmbc and 700 Mbngl have been produced to date.

Fourth Quarter 2010 and Full Year 2010 Production

Petrohawk’s fourth quarter 2010 production averaged 761 Mmcfe/d, 11 Mmcfe/d above the midpoint of the Company’s guidance. Full year 2010 production averaged 675 Mmcfe/d (562 Mmcfe/d pro forma for property sales, which accounted for approximately 113 Mmcfe/d). Fourth quarter production represented a 16% increase over third quarter 2010 and a 48% increase over the same period in 2009 on a pro forma basis. The Company exited 2010 producing approximately 744 Mmcfe/d compared to a pro forma exit rate of 455 Mmcfe/d in 2009.

Production grew substantially in both the Haynesville and Eagle Ford Shales throughout 2010. Net production from the Haynesville and Bossier Shales averaged 426 Mmcfe/d during 2010, a 100% increase year over year. Haynesville Shale and Bossier Shale net production was approximately 557 Mmcfe/d at year end 2010, aided by a lesser decline rate due to Petrohawk’s reservoir optimization program. The Eagle Ford Shale also grew at a high rate, with 67 Mmcfe/d produced on average in 2010, compared to 20 Mmcfe/d average net production in 2009, an increase of 235%. At year end 2010, net production from the Eagle Ford Shale was 125 Mmcfe/d, or, 61.0 Mmcf/d plus 7.1 Mbo/d and 3.6 Mbngl/d.

2011 Production Guidance and Hedging Update

Petrohawk has set the midpoint of first quarter 2011 production guidance at 770 Mmcfe/d (703 Mmcf/d + 6.6 Mbo/d + 4.3 Mbngl/d), which represents 15% pro forma growth over fourth quarter 2010. The midpoint of full year 2011 production guidance is 885 Mmcfe/d (781 Mmcf/d + 11.6 Mbo/d + 5.7 Mbngl/d), a 31% year over year increase and a 57% year over year increase pro forma for 2010 divestitures.

Approximately 63% of expected 2011 production is hedged with natural gas collars with floors averaging $5.55/Mmbtu and ceilings averaging $9.66/Mmbtu. For oil, floors average $78.00/barrel (Bbl) and ceilings average $98.88/Bbl in 2011. In 2012, 192,150 Bbtu and 3,660

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Mbbls are currently hedged at floors averaging $4.88/Mmbtu and ceilings averaging $6.55/Mmbtu for natural gas and floors averaging $77.00/Bbl and ceilings averaging $100.00/Bbl for oil. A summary of the Company’s derivative program can be found on its website, www.petrohawk.com.

Divestiture Update

During 2010, Petrohawk sold various non-core properties, comprising approximately 500 Bcfe of proved reserves. These properties, along with a joint venture of half of Petrohawk’s interest in its Haynesville Shale midstream business, were sold for approximately $2.1 billion. An additional $75 million sale of the Company’s Fayetteville Shale midstream business has closed since year end 2010. The proceeds of these asset sales were used to partially fund Petrohawk’s 2010 capital budget and will also be used to partially fund the 2011 capital budget.

2010 Capital Expenditures

For 2010, capital expenditures totaled $2.8 billion. Capital expenditures for drilling and completions were $1.9 billion — $635 million for lease acquisitions, $22 million for seismic, and approximately $211 million for Hawk Field Services, LLC. Leasehold acquisitions for 2010 were $420 million in the Eagle Ford Shale, primarily in the Black Hawk area, $141 million in the Haynesville Shale and $74 million in other areas. Capital expenditures outside of Petrohawk’s operating cash flows were supplemented by proceeds from divestitures, which totaled $2.1 billion in 2010. Approximately $146 million was drawn on the Company’s $1.6 billion revolving credit facility at year end. Capital expenditures for 2011 are budgeted at $2.3 billion.

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Operational Highlights

Eagle Ford Shale

Petrohawk is currently operating five rigs in Hawkville Field with plans to maintain that rig count throughout 2011. Five rigs are currently running in the Black Hawk area, with plans to increase to seven rigs by end of the first quarter and 11 rigs by the third quarter of 2011. Also, Petrohawk plans to drill approximately five additional wells in the Red Hawk area during the year.

Four dedicated frac fleets to service the Hawkville, Black Hawk and Red Hawk areas are under contract with two currently operating.  The third fleet is expected to arrive in mid-February with the fourth expected by early in the third quarter 2011. The increase in dedicated frac fleets will allow for a reduction in the inventory of wells currently waiting on frac —12 wells at Hawkville Field and 15 wells at Black Hawk.

Hawkville Field

The Company drilled thirty-six operated wells and five non-operated wells in Hawkville Field during 2010 with an even distribution of the drilling between dry gas and gas and condensate areas.  Significant delineation of the field took place through this drilling, resulting in the identification of two generalized areas of the field: the dry gas area (with approximately 1,100 btu gas) and a gas and condensate area yielding an average of 100 barrels of condensate per million cubic feet of natural gas (Mmcf) with approximately 1,200 btu gas.

Based on 90-acre spacing, Petrohawk has estimated its remaining resource potential for the field to be 6.6 Tcf plus 174 million barrels of condensate (MMbc) and 399 million barrels of natural gas liquids (MMbngl), after adjusting for proved reserves from the field. This is based on an estimate of approximately 224,000 net commercially productive acres with approximately 112,000 net acres in the dry gas area with an average per well EUR of 5.0 Bcf and 207 Mbngl, and approximately 112,000 net acres in an area that averages 100 barrels of condensate/Mmcf  with an average per well EUR of 2.5 Bcf plus 195 thousand barrels of condensate (Mbc) and 249 Mbngl.

In Hawkville Field, a new frac design has significantly improved the Company’s EUR estimates, with some increasing more than 50% as compared to wells completed using the older frac design. Two wells with sufficient production history to estimate EUR’s are the Heim #2H which is projected to produce an estimated 8.9 Bcf and 260 Mbngl, and the Dilworth #1H which is projected to produce an estimated 2.1 Bcf and 400 Mbc and 208 Mbngl.  Four additional wells

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have been fracture stimulated with this new design and are too new to project.  In addition to the new frac design, the Company has been testing the use of hybrid frac fluids (the combination of slickwater and cross linked gel).  The wells that have been completed with the hybrid design have consistently outperformed those completed with slickwater, which has also aided in the increased well performance in the field. These design changes, as well as continued changes to other aspects of the completion design are a result of an overall reservoir optimization program, similar to Petrohawk’s program in the Haynesville Shale.

Black Hawk

The Black Hawk area of the Eagle Ford Shale has become the Company’s dominant focus for high-return drilling in the current commodity price environment. Petrohawk drilled 29 wells in this area during 2010, and expects to drill approximately 85 wells in 2011. The Company recently acquired approximately 10,500 additional net acres in the Black Hawk area.  This acreage is located primarily in Karnes County, Texas.  Wells in this area of the trend are expected to have condensate yield of approximately 700 barrels/Mmcf.

Petrohawk has continued to see significant improvement in well performance in Black Hawk.  Specifically, the last six completed wells have average initial production rates of 3.0 Mmcf/d, 1,490 barrels of condensate per day (Bc/d) and 300 barrels of natural gas liquids per day (Bngl/d) on a 15/64” choke with 6,625 lbs. flowing casing pressure.  The improved well performance is a function of the Company’s reservoir optimization program.  The initial Black Hawk wells were typically produced on a 12/64” choke.  Petrohawk concluded that that choke size was too restrictive and chokes were increased to 15/64” on average.  Also, the wells are being drilled with longer lateral lengths.  The first six wells completed in Black Hawk averaged approximately 4,400’ while the last six have averaged approximately 5,500’.  Finally, the frac design has been modified for tighter perforation cluster spacing and increased proppant volume resulting in a more effective stimulation.

Improvements in well performance at Black Hawk have prompted the Company to change its estimate of the average EUR from approximately 2.2 Bcf and 375 Mbc to an average of 1.8 Bcf, 550 Mbc and 220 Mbngl.  Assuming 100-acre spacing and an estimate of approximately 73,600 net commercially productive acres, the total resource potential at Black Hawk is approximately 1.0 Tcf plus 304 MMbc and 121 MMbngl.  After adjusting for proved reserves from the field, the

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estimated remaining non-proved resource potential is 958 Bcfg and 293 MMbc and 121 MMbngl.

Red Hawk

Based on well performance and modeling of the area’s potential, Petrohawk intends to increase its investment in the oil-prospective Red Hawk area. The Mustang Ranch “C” #1H has exceeded previous EUR estimates, with a current estimate of approximately 200 thousand barrels of oil (Mbo). The third well in the area, the Chaparrosa Ranch “D” #1H, is currently flowing back following an 18 stage frac that was completed in late-January. The Company expects to drill five additional wells in 2011.

Assuming 60 acre spacing and a net risked commercially productive area of 50,000 acres the Company estimates that 125 million barrels of crude oil resource potential may be recoverable at approx 200,000 barrels of oil per well.

Haynesville Shale

During 2010, Petrohawk drilled 351 Haynesville Shale wells. These included 101 operated wells and 250 non-operated wells. The Company is currently operating 16 rigs in the play, which are scheduled to drill an additional 57 wells by mid-year, at which time the rig count is scheduled to decline to seven.  The Company expects to drill 31 operated wells during the second half of 2011.

Petrohawk expects to have 280 operated sections and 590 non-operated sections held by production by year-end 2011. This will leave approximately 25 operated and 120 non-operated wells to be drilled in 2012 to complete the lease capture process. The Company also owns and operates an additional 20 sections which are held by production from other zones. Petrohawk has retained three dedicated frac fleets for this area. At year end 2010 there were ten uncompleted Haynesville Shale wells in inventory.

Since the onset of Haynesville Shale development in mid-2008, Petrohawk has incorporated geological data, reservoir engineering analysis and other data in its assessment of the

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commercial limits of the field given prevailing natural gas price expectations. The Company estimates that it controls approximately 225,000 net acres within this area. Of those, approximately 170,000 net acres are operated and approximately 55,000 net acres are non-operated. Assuming an average of 90 acre spacing, Petrohawk’s current risked estimate of its non-proved resource potential in the Haynesville Shale is 15 Tcfe. After adjusting for proved reserves, Petrohawk’s estimated net non-proved resource potential is 12.7 Tcf.

Reservoir optimization efforts continue in the Haynesville Shale. These efforts, in conjunction with the belief that Petrohawk’s primary operations are concentrated in a portion of the play with favorable reservoir characteristics, continue to indicate to the Company that future recoveries may improve.

Haynesville Shale drilling and completion operations continue to evolve with the objective of driving down costs. Petrohawk estimates that the most significant potential savings lie with the future implementation of full-scale pad development. In advance of full-scale development, several pairs of wells have been drilled by using “batch drilling” techniques.  In this process, the initial well is drilled to intermediate point with water based mud. Once casing is set, the rig is “skid” to the neighboring location, drilled, and intermediate casing is set.  The process is then repeated as the curve and lateral sections are drilled with oil based mud. This process requires approximately 1-2 fewer days of pit cleaning and approximately three fewer days of picking up and laying down drill pipe plus approximately four fewer days of initial mobilization. These are just a few of the techniques that are being evaluated as part of what the Company expects to be a more efficient process as Petrohawk moves toward full section development.

The early stages of full section development are beginning as the lease capture phase nears completion. In Petrohawk’s first full development section, Section 8-T14N-R11W, Petrohawk and another operator drilled six development wells to complement the initial unit well, which was completed in June 2009. The six development wells were all brought on production in mid-December 2010 and are producing under restricted rate conditions with rates varying between 8 Mmcfe/d and 11 Mmcfe/d on chokes between 14/64” and 17/64”.  Numerous diagnostic techniques were employed during the completion and early time production of the wells and many additional tests will be conducted in order to gather as much data as possible to aid in the evaluation of optimum well spacing.

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Another operational advancement initiated in 2010, the production liner program, which was designed to reduce surface treating pressures and aid in reducing completion costs, has thus far proven successful.  A total of 11 wells have been drilled under this program. Of these, 7 wells have been completed and 4 wells are waiting on completion.  In virtually all of the frac stages pumped to date the maximum treating pressures have been under 10,000 lbs.  While the continued market demand for pressure pumping services has limited Petrohawk’s ability to maximize cost savings using this technique, net per well savings have averaged approximately $250,000.

Another significant cost saving effort is being tested whereby each development area of the field has been analyzed for its most cost efficient frac design.  While the process of evaluating this program is ongoing and the cost savings are not yet defined, the Company estimates potential savings of $250,000 or more per well.

Lower Bossier Shale

Petrohawk drilled one operated and 15 non-operated wells in the Lower Bossier Shale during 2010. The operated well, the Whitney 19 #1H in Sabine Parish, Louisiana, was completed in August 2010.  The initial restricted production rate was approximately 8 Mmcfe/d on a 14/64” choke with flowing casing pressure of approximately 8,300 lbs.  Of the 15 non-operated wells, five were drilled in North Louisiana and ten were drilled in East Texas.  Well performance to date for this limited number of wells indicates that the four wells drilled in the area of the Whitney 19 #1H have been the best performers with EURs averaging 9 Bcfe.

In the entire Lower Bossier Shale play, the industry has completed approximately 50 Lower Bossier Shale wells. The Company estimates that a large area of commercially productive Lower Bossier Shale acreage exists across the southern portion of the Haynesville Shale trend of North Louisiana and East Texas.  Petrohawk does not plan to commit significant capital to the Lower Bossier Shale until late 2012. At that time, given a favorable price environment for natural gas, the Company plans to launch directly into development of the Lower Bossier Shale, employing any cost saving measures that were successful in the Haynesville Shale, such as area-specific fracs and pad drilling. Petrohawk currently controls approximately 150,000 net acres in the Lower Bossier Shale that appears to be commercially productive based on regional well performance and geological data.  Assuming 90 acre spacing and an average EUR of 6.5

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Bcf/well, the Company’s estimated net non-proved resource potential for the Lower Bossier Shale is 8.1 Tcf.

Midstream Activities

During 2010, midstream activities in both the Haynesville Shale and Eagle Ford Shale expanded significantly. Considerable additional growth is planned in 2011. Approximately 214 miles of gathering pipeline and 750 gallons per minute (GPM) of treating capacity were added in the Haynesville Shale during 2010. To date, the Haynesville Shale system, of which 50% is owned by Petrohawk and known as Kinderhawk, comprises approximately 365 miles of pipeline and 2,360 GPM of treating capacity. As of December 31, 2010, daily system throughput averaged 753 Mmcf/d.

In the Eagle Ford Shale, approximately $88 million was spent during 2010 to fund a significant expansion of gathering, condensate handling and treating capacity. By year end 2010, Hawk Field Services had laid approximately 156 miles of gas gathering pipeline to service Hawkville Field and the Black Hawk area and is scheduled to complete 131 additional miles during 2011, bringing the estimated year-end 2011 total to 287. Seventeen miles of condensate gathering pipeline was also added during 2010, with an anticipated 136 miles planned for 2011. Petrohawk’s Hawkville system’s treating capacity reached 250 GPM by year-end 2010 with 2,500 BPD in stabilization capacity for condensate currently nearing completion. The Company plans to invest in additional condensate stabilization facilities with expected capacity of 80,000 BPD as well as takeaway capacity that may include pipelines, trucks or rail.  It is expected that this area will have a significant third party gathering opportunity for both natural gas and condensate.

Conference Call

Petrohawk has scheduled a conference call for Tuesday, February 1, 2011 at 10:30 a.m. EDT (9:30 a.m. CDT) to discuss fourth quarter and full year 2010 operational results. To access, dial 888-230-5502 five to ten minutes before the call begins. Please reference Petrohawk Energy Conference ID 2576533. International callers may also participate by dialing 913-312-1482. A replay of the call will be available approximately two hours after the live broadcast ends and will be accessible until February 8, 2011. To access the replay, please dial 888-203-

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1112 and reference conference ID 2576533. International callers may listen to a playback by dialing 719-457-0820.

Petrohawk Energy Corporation is an independent energy company engaged in the acquisition, production, exploration and development of oil and natural gas with properties concentrated in North Louisiana, in the Haynesville Shale, and South Texas, in the Eagle Ford Shale.

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.

The information in this release is unaudited. Audited and final results will be included in our Annual Report on Form 10-K for the year ended December 31, 2010 currently planned to be filed with the Securities and Exchange Commission by the end of February 2011.

Additional Information for Investors

This press release contains forward-looking information regarding Petrohawk that is intended to be covered by the safe harbor “forward-looking statements” provided by of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are based on Petrohawk’s current expectations, beliefs, plans, objectives, assumptions and strategies. Forward-looking often, but not always, can be identified by words such as “expects”, “anticipates”, “plans”, “estimates”, “potential”, “possible”, “probable”, or “intends”, or where we state 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, including 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;

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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; risks associated with derivative positions; inability to realize expected value from acquisitions, risks associated with the  timing of and potential proceeds from divestitures, 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 Petrohawk’s reports  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 projections 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 requires oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are 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. Beginning with year-end reserves for 2009, the SEC permits the optional disclosure of probable and possible reserves. Petrohawk has elected not to disclose the Company’s probable and possible reserves in its filings with the SEC. Petrohawk uses the term “resource potential,” to describe volumes of resources potentially recoverable through additional drilling or recovery techniques that may include probable and possible reserves as defined by the SEC’s guidelines. The SEC’s rules prohibit us from including in filings with the SEC estimates of reserves described as resource potential. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized. Resource potential refers to Petrohawk’s internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques and have not been reviewed by independent engineers. Resource potential does not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System and does not include proved reserves. Area wide

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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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