L. Brent Stottlemyre
Senior Vice President, Controller and
Chief Accounting Officer

June 25, 2007

Ms. Jill Davis
Branch Chief
Securities and Exchange Commission
Division of Corporation Finance
Mail Stop 7010
Washington, DC 20549-7010

Re:	SEC Comment Letter Dated June 12, 2007
	Peabody Energy Corporation Form 10-K
	For the Fiscal Year Ended December 31, 2006
	Filed February 28, 2007
	Response Letter Dated May 17, 2007
	File No. 001-16463

Dear Ms. Davis:

     In response to staff comments, we offer the following:

Form 10-K for the Year Ended December 31, 2006

Note 1 Summary of Significant Accounting Policies, page F-6

Inventory, page F-8

1. We note your response to our prior comment number three of our letter dated May 3, 2007 that indicates advance stripping costs related to post-production are “primarily” expensed as incurred. Please clarify your response to explain instances where you don’t expense such costs as incurred. Please refer to the guidance of paragraph 6 of EITF 04-6.

Response

     Based on discussions with the staff June 15, 2007, the use of “primarily” in our disclosure was simply intended to reflect the fact that the cost basis of produced coal inventory will include an element of advance stripping costs at any balance sheet date. We would propose to modify our disclosure as follows:

F-8 — As a result of the adoption of EITF Issue No. 04-6 on January 1, 2006, advance stripping costs are expensed as incurred except to the extent such costs are included as a component of inventory costs.

Ms. Jill Davis
Securities and Exchange Commission
June 25, 2007
Page 2

2. We note your response to our prior comments numbers four and five of our letter dated May 3, 2007. Please explain why you believe it is appropriate to capitalize initial box cuts or overburden removal associated with new pits within an existing mine that is in the production stage. Please note that the guidance of paragraph 6 of EITF 04-6 states that stripping costs incurred during the production phase of a “mine” are variable production costs.

Response

     We believe the cost of the initial box cut to remove overburden represents a development cost to bring an additional asset (the developed pit) into production. As noted in our May 17, 2007 response, the costs to remove overburden to develop additional pits that operate in a separate and distinct area of the mine (in many cases miles apart) would be capitalized as development costs and amortized over the life of the specific pit. Further, the development of a new pit would require us to recognize an asset retirement obligation that, consistent with existing accounting literature, dictates “Upon initial recognition of a liability for an asset retirement obligation, an entity shall capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability.” Existing accounting literature would suggest “the related long-lived asset” is the newly developed pit.

     As a member of the Mining Industry Working Group, Peabody participated in the deliberations and discussions concerning EITF 04-6. We, and others in that working group, do not believe the guidance of paragraph 6 of EITF 04-6 was intended to limit the initial capitalization of additional assets (pits) that may be developed at a mine. As you may already be aware, mining companies have previously requested clarification concerning terms included in EITF 04-6, and it would appear that additional clarification should be sought from the FASB staff and the Mining Industry Working Group with respect to this issue.

Property, Plant, Equipment and Mine Development, page F-9

3. We note your response to prior comment six of our letter dated May 3, 2007. Included in the book value of coal reserves are mineral rights for leased coal interests including advance royalties and the net book value of these mineral rights was $3.5 billion at December 31, 2006. Please clarify which costs comprise the remaining net book value of coal reserves.

Response

     As discussed with the staff on June 15, 2007, the disclosure noted above stems from prior staff comments concerning mineral rights and the need to differentiate the carrying values associated the types of mineral rights and to comply with disclosures under EITF 04-2 which provides:

The Task Force reached a consensus on Issue 1 that mineral rights, as defined in this Issue, are tangible assets, and, accordingly, an entity should account for mineral rights as tangible assets. The Task Force also concluded that an entity should report the aggregate carrying amount of mineral rights as a separate component of property, plant, and equipment either on the face of the financial statements or in the notes to the financial statements.

Ms. Jill Davis
Securities and Exchange Commission
June 25, 2007
Page 3

     Because our mineral interests are generally held either in fee ownership or by lease interest, our disclosure was written to only distinguish the carrying value associated with leased coal interests. Based on the staff comments, we would propose the following disclosure to clarify the respective carrying values of our coal interests:

F-9 — Included in the book value of coal reserves are mineral rights for leased coal interests including advance royalties and the net book value of these mineral rights was $3.5 billion and $2.1 billion at December 31, 2006 and 2005, respectively. The remaining net book value of our coal reserves of $1.7 billion and $1.6 billion, at December 31, 2006 and 2005 respectively, relates to coal reserves held by fee ownership.

4. Please modify your accounting policy that is included as part of your audited financial statements to address that your reserve estimates include reductions for recoverability factors.

Response

     We would suggest the following disclosure:

F-9 — Depletion of coal reserves and amortization of advance royalties is computed using the units-of-production method utilizing only proven and probable reserves (as adjusted for recoverability factors) in the depletion base.

5. We note your response to our prior comment numbers seven and eight of our letter dated May 3, 2007. Please clarify your accounting policy associated with drilling and study costs incurred to convert or upgrade mineral resources, including measured, indicated and inferred resources to reserves. Please note, that we believe all drilling and study costs associated with in-fill, step-out, condemnation, geotechnical and confirmation drilling should be expensed as incurred. Please contact us to discuss.

Response

     Based on discussion with the staff June 15, 2007, we confirm that Peabody expenses drilling and study costs incurred to convert or upgrade mineral resources, including measured, indicated and inferred resources to reserves. We would propose the following disclosure:

Costs incurred to maintain current production capacity at a mine and exploration expenditures are charged to operating costs as incurred, including costs related to drilling and study costs incurred to convert or upgrade mineral resources to reserves.

Note 4 Business Combinations, page F-16

6. We note your response to our prior comment number nine that indicates resulting goodwill will be allocated to your Australian operating segment. We re-issue that portion of our prior comment that requested you to address the goodwill allocation to your reporting units and

Ms. Jill Davis
Securities and Exchange Commission
June 25, 2007
Page 4

whether you consider an individual operating mine to constitute a reporting unit. Please refer to paragraph 30 of SFAS 142 and EITF 04-4.

Response

     We understand the provisions noted in paragraph 30 of SFAS 142 and EITF 04-4, and recognize under EITF 04-4 that “goodwill should be allocated to reporting units and an individual operating mine may constitute a reporting unit.” We expect to receive a final valuation report and complete our purchase allocation during Q3 2007 at which time any resulting goodwill will be allocated to reporting units as determined under SFAS 142 and EITF 04-4. We welcome further discussion with the staff related to goodwill allocations in advance of making our final purchase price allocations.

Other Matters

     As discussed with the staff on June 15, 2007, we have noted that certain of our reserve table summary totals on pages 46 and 47 do not correctly foot, and we are submitting changes to those tables.

     We appreciate your consideration of these comments, and should you need additional clarification or assistance please contact Brent Stottlemyre at 314-342-7557.

Sincerely,
 

/s/ L. Brent Stottlemyre  

L. Brent Stottlemyre 

Senior Vice President, Controller and
Chief Accounting Officer 

      The following chart provides a summary, by mining complex, of production for the years ended December 31, 2006 and 2005 and 2004, tonnage of coal reserves that is assigned to our operating mines, our property interest in those reserves and other characteristics of the facilities.

PRODUCTION AND ASSIGNED RESERVES⁽¹⁾

(Tons in millions)

											Sulfur Content(2)								As of December 31, 2006
			Production
											<1.2 lbs.		>1.2 to 2.5 lbs.		>2.5 lbs.		As		Assigned
			Year Ended		Year Ended		Year Ended				sulfur dioxide		sulfur dioxide		sulfur dioxide		Received		Proven and
Geographic Region/Mining			Dec. 31,		Dec. 31,		Dec. 31,		Type of		per		per		per		Btu per		Probable
Complex			2006		2005		2004		Coal		Million Btu		Million Btu		Million Btu		pound(3)		Reserves		Owned	Leased		Surface		Underground
Appalachia:
	Federal			4.6		4.1		4.9		Steam		—		—		31		13,300		31	11		20		—		31
	Big Mountain			2.0		1.9		1.9		Steam		4		30		—		12,300		34	—		34		—		34
	Kanawha Eagle(4)			1.9		—		—		Steam/Met.		31		22		—		13,100		53	—		53		—		53
	Harris			1.6		2.0		3.0		Steam/Met.		5		3		—		13,800		8	—		8		—		8
	Rocklick			2.2		2.6		2.0		Steam/Met.		5		7		1		13,100		13	—		13		3		10
	Wells			2.3		2.6		2.6		Steam/Met.		20		29		—		12,800		49	—		49		—		49
		Total		14.6		13.2		14.4				65		91		32				188	11		177		3		185
Midwest:
	Highland			3.7		3.8		3.2		Steam		—		—		88		11,400		88	31		57		—		88
	Patriot			3.9		4.2		4.1		Steam		—		—		41		10,800		41	4		37		3		38
	Air Quality			2.2		2.1		1.8		Steam		—		25		33		10,700		58	5		53		—		58
	Riola/ Vermilion Grove			1.7		2.3		2.3		Steam		—		—		19		10,500		19	—		19		—		19
	Miller Creek			1.6		1.0		0.9		Steam		—		2		28		10,000		30	29		1		30		—
	Francisco Surface			2.0		1.8		2.1		Steam		—		—		6		10,500		6	2		4		6		—
	Francisco Underground			1.1		1.2		0.9		Steam		—		—		22		10,600		22	3		18		—		22
	Farmersburg			3.8		3.8		4.2		Steam		1		11		95		10,300		107	93		14		107		—
	Somerville Central			3.5		3.4		3.2		Steam		—		—		4		10,300		4	2		2		4		—
	Somerville — North			2.4		2.4		2.1		Steam		—		—		7		10,500		7	6		1		7		—
	Somerville — South			2.5		2.4		2.0		Steam		—		—		14		10,000		14	8		6		14		—
	Viking			1.5		1.5		1.5		Steam		—		1		7		10,700		8	—		8		8		—
	Wildcat Hills Surface/Underground			2.4		2.6		2.7		Steam		—		—		10		10,300		10	5		5		10		—
	Willow Lake			3.6		3.7		3.4		Steam		—		—		64		11,200		64	48		17		—		64
	Gateway			2.6		0.5		—		Steam		—		—		20		10,300		20	20		—		—		20
	Dodge Hill			1.1		1.2		1.2		Steam		—		—		8		11,100		8	3		5		—		8
		Total		39.6		37.9		35.6				1		39		466				506	259		247		189		317
Powder River Basin:
	North Antelope/ Rochelle			88.6		82.7		82.5		Steam		1,171		—		—		8,800		1,171	—		1,171		1,171		—
	Caballo			32.8		30.5		26.5		Steam		787		122		22		8,600		931	—		931		931		—
	Rawhide			17.0		12.4		6.9		Steam		290		62		55		8,600		407	—		407		407		—
		Total		138.4		125.6		115.9				2,248		184		77				2,509	—		2,509		2,509		—
Southwest/ Colorado:
	Black Mesa			—		3.9		4.8		Steam		10		1		—		10,600		11	—		11		11		—
	Kayenta			8.2		8.2		8.2		Steam		185		82		3		11,000		270	—		270		270		—
	Lee Ranch			5.5		5.3		5.8		Steam		20		123		12		10,000		155	88		67		155		—
	Twentymile			8.6		9.4		6.4		Steam		73		—		—		10,800		73	14		59		—		73
	Seneca			—		1.1		1.5		Steam		—		—		—		NA		—	—		—		—		—
		Total		22.3		27.9		26.7				288		206		15				509	102		407		436		73

45

											Sulfur Content(2)								As of December 31, 2006
			Production
											<1.2 lbs.		>1.2 to 2.5 lbs.		>2.5 lbs.		As		Assigned
			Year Ended		Year Ended		Year Ended				sulfur dioxide		sulfur dioxide		sulfur dioxide		Received		Proven and
Geographic Region/Mining			Dec. 31,		Dec. 31,		Dec. 31,		Type of		per		per		per		Btu per		Probable
Complex			2006		2005		2004		Coal		Million Btu		Million Btu		Million Btu		pound(3)		Reserves		Owned	Leased		Surface		Underground
Australia:
	North Goonyella/ Eaglefield			2.2		2.1		1.7		Met.		48		—		—		12,800		48	—		48		2		46
	Metropolitan			0.4		—		—		Met.		40		—		—		12,700		40	—		40		—		40
	Wilkie Creek			2.0		1.9		1.4		Steam		223		—		—		10,800		223	—		223		223		—
	Chain Valley (80.0%)(5)			0.2		—		—		Steam		17		—		—		11,900		17	—		17		—		17
	Wambo Open Cut(4)			1.2		—		—		Steam		106		—		—		12,400		106	—		106		106		—
	Burton (95.0%)(5)			4.3		4.4		3.2		Steam/Met.		38		—		—		12,400		38	—		38		38		—
	Baralaba(4)			0.2		—		—		Steam/Met.		—		2		—		12,200		2	—		2		2		—
	Wilpinjong			0.3		—		—		Steam		—		165		—		9,900		165	—		165		165		—
	Millennium(4)			0.1		—		—		Met.		26		—		—		12,800		26	—		26		26		—
		Total		10.9		8.4		6.3				498		167		—				665	—		665		562		103
Total				225.8		213.0		198.9				3,100		687		590				4,377	372		4,005		3,699		678

46

     The following chart provides a summary of the amount of our proven and probable coal reserves in each U.S. state and Australia state, the predominant type of coal mined in the applicable location, our property interest in the reserves and other characteristics of the facilities.

ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES

As of December 31, 2006

(Tons in millions)

													Sulfur Content(2)
													<1.2 lbs.		>1.2 to 2.5 lbs.		>2.5 lbs.		As
		Total Tons				Proven and							sulfur dioxide		sulfur dioxide		sulfur dioxide		Received		Reserve Control				Mining Method
						Probable						Type of	per		per		per		Btu per
Coal Seam Location		Assigned		Unassigned		Reserves(6)		Proven		Probable		Coal	Million Btu		Million Btu		Million Btu		pound(3)		Owned		Leased		Surface		Underground
Appalachia:
	Ohio		—		25		25		19		6	Steam		—		—		25		11,300		25		—		—		25
	West Virginia		188		342		530		310		220	Steam/Met.		141		190		199		13,000		224		306		15		515
	Appalachia		188		367		555		329		226			141		190		224				249		306		15		540
Midwest:
	Illinois		113		2,292		2,405		1,190		1,215	Steam		5		38		2,362		10,400		2,195		210		78		2,327
	Indiana		255		353		608		410		198	Steam		1		40		567		10,300		402		206		258		350
	Kentucky		138		1,019		1,157		622		535	Steam		—		1		1,156		10,800		673		484		105		1,052
	Midwest		506		3,664		4,170		2,222		1,948			6		79		4,085				3,270		900		441		3,729
Powder River Basin:
	Montana		—		162		162		158		4	Steam		15		117		30		8,600		67		95		162		—
	Wyoming		2,509		796		3,305		3,226		79	Steam		3,020		183		102		8,700		—		3,305		3,305		—
	Powder River Basin		2,509		958		3,467		3,384		83			3,035		300		132				67		3,400		3,467		—
Southwest/ Colorado:
	Arizona		281		—		281		281		—	Steam		195		83		3		10,900		—		281		281		—
	Colorado		73		154		227		165		62	Steam		139		—		88		10,600		43		184		—		227
	New Mexico		155		544		699		636		63	Steam		91		344		264		9,200		617		82		699		—
	Southwest		509		698		1,207		1,082		125			425		427		355				660		547		980		227
Australia:
	New South Wales		328		138		466		253		213	Steam/Met.		466		—		—		12,400		—		466		271		195
	Queensland		337		—		337		104		233	Steam/Met.		335		2		—		11,200		—		337		291		46
	Australia		665		138		803		357		446			801		2		—				—		803		562		241
Total Proven and Probable			4,377		5,825		10,202		7,374		2,828			4,408		998		4,796				4,246		5,956		5,465		4,737

47