Petrohawk Energy 10-K 2006 FY Annual report

Exhibit 99.1

	CHAIRMAN EMERITUS	EXECUTIVE COMMITTEE
	CLARENCE M. NETHERLAND	G. LANCE BINDER - DALLAS DANNY D. SIMMONS - HOUSTON
WORLDWIDE PETROLEUM CONSULTANTS ENGINEERING • GEOLOGY • GEOPHYSICS • PETROPHYSICS
	CHAIRMAN & CEO
	FREDERIC D. SEWELL	P. SCOTT FROST - DALLAS
		DAN PAUL SMITH - DALLAS
	PRESIDENTS & COO	JOSEPH J. SPELLMAN- DALLAS
	C.H. (SCOTT) REES III	THOMAS J. TELLA II - DALLAS

February 15, 2007

Mr. Steve Herod

Petrohawk Energy Corporation

1000 Louisiana Street, Suite 5600

Houston, Texas 77002

Dear Mr. Herod:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2006, to the interest of Petrohawk Energy Corporation and its subsidiaries (collectively referred to herein as “Petrohawk”) in certain oil and gas properties located in the United States. This report has been prepared using constant prices and costs, as discussed in subsequent paragraphs of this letter. The estimates of reserves and future revenue in this report conform to the guidelines of the U.S. Securities and Exchange Commission (SEC).

We estimate the net reserves and future net revenue to the Petrohawk interest in these properties, as of December 31, 2006, to be:

	Net Reserves			Future Net Revenue (M$)
Category	Oil (MBBL)	NGL (MBBL)	Gas (MMCF)	Total	Present Worth at 10%
Proved Developed
Producing	15,494.5	4,522.6	394,137.8	2,097,673.0	1,307,317.1
Non-Producing	2,449.1	721.6	140,423.1	662,664.7	375,069.2
Proved Undeveloped	6,467.7	1,508.4	354,575.6	984,629.1	328,495.6
Total Proved	24,411.3	6,752.6	889,136.4	3,744,966.8	2,010,881.9

Totals may not add because of rounding.

The oil reserves shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved developed producing, proved developed non-producing, and proved undeveloped reserves. In accordance with SEC guidelines, our estimates do not include any probable or possible reserves that may exist for these properties. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserve categorization conveys the relative degree of certainty; the estimates of reserves and future revenue included herein have not been adjusted for risk. Definitions of reserve categories are presented immediately following this letter.

Future gross revenue to the Petrohawk interest is prior to deducting state production taxes and ad valorem taxes. Future net revenue is after deductions for these taxes, future capital costs, operating expenses, and abandonment costs but before consideration of federal income taxes. In accordance with SEC guidelines, the future net revenue has been discounted at an annual rate of 10 percent to determine its present worth. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

4500 THANKSGIVING TOWER • 1601 ELM STREET • DALLAS, TEXAS 75201-4754 •  PH: 214-969-5401 Fax: 214- 969- 5411	nsai@nsai-petro.com
1221 LAMAR STREET. SUITE 1200 • HOUSTON, TEXAS 77010-3072 • PH: 713-654-4950 • FAX: 713-654-4951	netherlandsewell.com

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and their related facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability. Our estimates of future revenue do not include any salvage value for the lease and well equipment or the cost of abandoning the properties, except for offshore and certain Louisiana coastal water properties. Future revenue estimates for these selected properties do include Petrohawk’s estimates of the costs to abandon the wells, platforms, and production facilities. Abandonment costs are included as capital costs.

Oil and NGL prices used in this report are based on the December 31, 2006, Plains Marketing, L.P. West Texas Intermediate posted price of $57.75 per barrel and are adjusted by lease for quality, transportation fees, and regional price differentials. Gas prices used in this report are based on a December 31, 2006, Henry Hub spot market price of $5.635 per MMBTU and are adjusted by lease for energy content, transportation fees, and regional price differentials. All prices are held constant in accordance with SEC guidelines.

Lease and well operating costs used in this report are based on operating expense records of Petrohawk. As requested, these costs include direct lease- and field-level costs and Petrohawk’s estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties. For nonoperated properties, these costs also include the per-well overhead expenses allowed under joint operating agreements. Lease and well operating costs are held constant in accordance with SEC guidelines. Capital costs are included as required for workovers, recompletions, new development wells, and production equipment.

We have made no investigation of potential gas volume and value imbalances resulting from overdelivery or underdelivery to the Petrohawk interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Petrohawk receiving its net revenue interest share of estimated future gross gas production.

The reserves shown in this report are estimates only and should not be construed as exact quantities. The reserves may or may not be recovered; if they are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. A substantial portion of these reserves are for behind pipe zones, non-producing zones, undeveloped locations, and producing wells that lack sufficient production history upon which performance-related estimates of reserves can be based. Therefore, these reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogies to similar production. Because such reserve estimates are usually subject to greater revision than those based on substantial production and pressure data, it may be necessary to revise these estimates as additional performance data become available. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report. Also, estimates of reserves may increase or decrease as a result of future operations.

In evaluating the information at our disposal concerning this report, we have excluded from our consideration all matters as to which the controlling interpretation may be legal or accounting, rather than engineering and geologic. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geologic data; therefore, our conclusions necessarily represent only informed professional judgment.

The titles to the properties have not been examined by Netherland, Sewell & Associates, Inc., nor has the actual degree or type of interest owned been independently confirmed. The data used in our estimates were obtained from Petrohawk Energy Corporation, other interest owners, various operators of the properties, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. and were accepted as accurate. Supporting geologic, field performance, and work data are on file in our office. We are independent petroleum

engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties and are not employed on a contingent basis.

Very truly yours,
NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	/s/ Frederic D. Sewell, P.E.
	Frederic D. Sewell, P.E.
	Chairman and Chief Executive Officer

By:	/s/ Thomas J. Tella, P.E.	By:	/s/ William Knights P.E.
	Thomas J. Tella, P.E.		William Knights P.E.
	Senior Vice President		Vice President
Date	Signed: February 15, 2007	Date	Signed: February 15, 2007

TJT:SNP

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from Securities and Exchange Commission Regulation S-X Rule 4-10(a)

The following definitions of proved reserves are set forth in Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included (in italics) are certain subsequent interpretations set forth in the SEC’s Corporate Finance Accounting Interpretations and Guidance [SEC Interpretations]; SEC Staff Accounting Bulletins: Topic 12 [SEC Topic 12]; and the 1997 reserves definitions approved by the Society of Petroleum Engineers and World Petroleum Council [SPE/WPC Definitions].

Proved Oil and Gas Reserves.Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

The determination of reasonable certainty is generated by supporting geological and engineering data. There must be data available which indicate that assumptions such as decline rates, recovery factors, reservoir limits, recovery mechanisms and volumetric estimates, gas-oil ratios or liquid yield are valid. If the area in question is new to exploration and there is little supporting data for decline rates, recovery factors, reservoir drive mechanisms etc., a conservative approach is appropriate until there is enough supporting data to justify the use of more liberal parameters for the estimation of proved reserves. The concept of reasonable certainty implies that, as more technical data becomes available, a positive, or upward, revision is much more likely than a negative, or downward, revision.

Existing economic and operating conditions are the product prices, operating costs, production methods, recovery techniques, transportation and marketing arrangements, ownership and/or entitlement terms and regulatory requirements that are extant on the effective date of the estimate. An anticipated change in conditions must have reasonable certainty of occurrence; the corresponding investment and operating expense to make that change must be included in the economic feasibility at the appropriate time. These conditions include estimated net abandonment costs to be incurred and duration of current licenses and permits.

If oil and gas prices are so low that production is actually shut-in because of uneconomic conditions, the reserves attributed to the shut-in properties can no longer be classified as proved and must be subtracted from the proved reserve data base as a negative revision. Those volumes may be included as positive revisions to a subsequent year’s proved reserves only upon their return to economic status. [SEC Interpretations]

Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

Proved reserves may be attributed to a prospective zone if a conclusive formation test has been performed or if there is production from the zone at economic rates. It is clear to the SEC staff that wireline recovery of small volumes (e.g. 100 cc) or production of a few hundred barrels per day in remote locations is not necessarily conclusive. Analyses of open-hole well logs which imply that an interval is productive are not sufficient for attribution of proved reserves. If there is an indication of economic producibility by either formation test or production, the reserves in the legal and technically justified drainage area around the well projected down to a known fluid contact or the lowest known hydrocarbons, or LKH may be considered to be proved.

In order to attribute proved reserves to legal locations adjacent to such a well (i.e. offsets), there must be conclusive, unambiguous technical data which supports reasonable certainty of production of such volumes and sufficient legal acreage to economically justify the development without going below the shallower of the fluid contact or the LKH. In the absence of a fluid contact, no offsetting reservoir volume below the LKH from a well penetration shall be classified as proved.

Definitions - Page 1 of 4

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from Securities and Exchange Commission Regulation S-X Rule 4-10(a)

Upon obtaining performance history sufficient to reasonably conclude that more reserves will be recovered than those estimated volumetrically down to LKH, positive reserve revisions should be made. [SEC Interpretations)

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. [SEC Topic 12]

Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

If an improved recovery technique which has not been verified by routine commercial use in the area is to be applied, the hydrocarbon volumes estimated to be recoverable cannot be classified as proved reserves unless the technique has been demonstrated to be technically and economically successful by a pilot project or installed program in that specific rock volume. Such demonstration should validate the feasibility study leading to the project. [SEC Interpretations]

Estimates of proved reserves do not include the following:

(A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Geologic and reservoir characteristic uncertainties such as those relating to permeability, reservoir continuity, sealing nature of faults, structure and other unknown characteristics may prevent reserves from being classified as proved. Economic uncertainties such as the lack of a market (e.g. stranded hydrocarbons), uneconomic prices and marginal reserves that do not show a positive cash flow can also prevent reserves from being classified as proved. Hydrocarbons “manufactured” through extensive treatment of gilsonite, coal and oil shales are mining activities reportable under Industry Guide 7. They cannot be called proved oil and gas reserves. However, coal bed methane gas can be classified as proved reserves if the recovery of such is shown to be economically feasible.

In developing frontier areas, the existence of wells with a formation test or limited production may not be enough to classify those estimated hydrocarbon volumes as proved reserves. Issuers must demonstrate that there is reasonable certainty that a market exists for the hydrocarbons and that an economic method of extracting, treating and transporting them to market exists or is feasible and is likely to exist in the near future. A commitment by the company to develop the necessary production, treatment and transportation infrastructure is essential to the attribution of proved undeveloped reserves. Significant lack of progress on the development of such reserves may be evidence of a lack of such commitment. Affirmation of this commitment may take the form of signed sales contracts for the products; request for proposals to build facilities; signed acceptance of bid proposals; memos of understanding between the appropriate organizations and governments; firm plans and timetables established; approved authorization for expenditures to build facilities;

Definitions - Page 2 of 4

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from Securities and Exchange Commission Regulation S-X Rule 4-10(a)

approved loan documents to finance the required infrastructure; initiation of construction of facilities; approved environmental permits etc. Reasonable certainty of procurement of project financing by the company is a requirement for the attribution of proved reserves. An inordinately long delay in the schedule of development may introduce doubt sufficient to preclude the attribution of proved reserves.

The history of issuance and continued recognition of permits, concessions and commerciality agreements by regulatory bodies and governments should be considered when determining whether hydrocarbon accumulations can be classified as proved reserves. Automatic renewal of such agreements cannot be expected if the regulatory body has the authority to end the agreement unless there is a long and clear track record which supports the conclusion that such approvals and renewal are a matter of course. [SEC Interpretations]

Companies should report reserves of natural gas liquids which are net to their leasehold interests, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instructions to Item 3 of Securities Act Industry Guide 2 and report such reserves separately and describe the nature of the ownership. [SEC Topic 12]

Proved Developed Oil and Gas Reserves.Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Currently producing wells and wells awaiting minor sales connection expenditure, recompletion, additional perforations or bore hole stimulation treatment would be examples of properties with proved developed reserves since the majority of the expenditures to develop the reserves has already been spent.

Proved developed reserves from improved recovery techniques can be assigned after either the operation of an installed pilot program shows a positive production response to the technique or the project is fully installed and operational and has shown the production response anticipated by earlier feasibility studies. In the case with a pilot, proved developed reserves can be assigned only to that volume attributable to the pilot’s influence. In the case of the fully installed project, response must be seen from the full project before all the proved developed reserves estimated can be assigned. If a project is not following original forecasts, proved developed reserves can only be assigned to the extent actually supported by the current performance. An important point here is that attribution of incremental proved developed reserves from the application of improved recovery techniques requires the installation of facilities and a production increase [SEC Interpretations]

Proved Developed Producing Reserves.Reserves subcategorized as producing are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Proved Developed Non-Producing Reserves.Reserves subcategorized as non-producing include shut-in and behind-pipe reserves. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production. [SPE/WPC Definitions]

Proved Undeveloped Reserves.Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling unite offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units

Definitions - Page 3 of 4

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from Securities and Exchange Commission Regulation S-X Rule 4-10(a)

can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery techniques is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

The SEC staff points out that this definition contains no mitigating modifier for the word certainty. Also, continuity of production requires more than the technical indication of favorable structure alone (e.g. seismic data) to meet the test for proved undeveloped reserves. Generally, proved undeveloped reserves can be claimed only for legal and technically justified drainage areas offsetting an existing productive well (but structurally no lower than LKH). If there are at least two wells in the same reservoir which are separated by more than one legal location and which show communication (reservoir continuity), proved undeveloped reserves could be claimed between the two wells, even though the location in question might be more than an offset well location away from any of the wells. In this illustration, seismic data could be used to help support this claim by showing reservoir continuity between the wells, but the required data would be the conclusive evidence of communication from production or pressure tests. The SEC staff emphasizes that proved reserves cannot be claimed more than one offset location away from a productive well if there are no other wells in the reservoir, even though seismic data may exist. The use of high-quality, well calibrated seismic data can improve reservoir description for performing volumetrics (e.g. fluid contacts). However, seismic data is not an indicator of continuity of production and, therefore, can not be the sole indicator of additional proved reserves beyond the legal and technically justified drainage areas of wells that were drilled. Continuity of production would have to be demonstrated by something other than seismic data.

In a new reservoir with only a few wells, reservoir simulation or application of generalized hydrocarbon recovery correlations would not be considered a reliable method to show increased proved undeveloped reserves. With only a few wells as data points from which to build a geologic model and little performance history to validate the results with an acceptable history match, the results of a simulation or material balance model would be speculative in nature. The results of such a simulation or material balance model would not be considered to be reasonably certain to occur in the field to the extent that additional proved undeveloped reserves could be recognized. The application of recovery correlations which are not specific to the field under consideration is not reliable enough to be the sole source for proved reserve calculations.

Reserves cannot be classified as proved undeveloped reserves based on improved recovery techniques until such time that they have been proved effective in that reservoir or an analogous reservoir in the same geologic formation in the immediate area. An analogous reservoir is one having at least the same values or better for porosity, permeability, permeability distribution, thickness, continuity and hydrocarbon saturations.

(g) Topic 12 of Accounting Series Release No. 257 of the Staff Accounting Bulletins states:

In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test.

If the combination of data from open-hole logs and core analyses is overwhelmingly in support of economic producibility and the indicated reservoir properties are analogous to similar reservoirs in the same field that have produced or demonstrated the ability to produce on a conclusive formation test, the reserves may be classified as proved. This would probably be a rare event especially in an exploratory situation. The essence of the SEC definition is that in most cases there must at least be a conclusive formation test in a new reservoir before any reserves can be considered to be proved. [SEC Interpretations]

Definitions - Page 4 of 4