[PEABODY ENERGY CORPORATION LETTERHEAD]

June 20, 2017

VIA EDGAR

Mr. John Reynolds

Assistant Director

Office of Beverages, Apparel and Mining

Securities and Exchange Commission

Division of Corporation Finance

100 F Street N.E.

Washington, D.C. 20549

Re: Peabody Energy Corporation

Amended Registration Statement on Form S-1

Filed May 26, 2017

File No. 333-217242

Amended Form 8-K filed May 26, 2017

File No. 001-16463

Dear Mr. Reynolds:

Peabody Energy Corporation (“Peabody Energy” or the “Company”) is submitting this letter in response to the comments of the staff (the “Staff”) of the Division of Corporation Finance of the Securities and Exchange Commission contained in the Staff’s letter (the “Peabody Comment Letter”) dated June 12, 2017, relating to the Company’s Registration Statement on Form S-1 initially filed on April 11, 2017 (the “Registration Statement”) and as amended on May 26, 2017 (the “Form S-1 Amendment No. 1”), the Company’s Current Report on Form 8-K, initially filed on April 11, 2017 (the “Form 8-K”) and as amended on May 26, 2017 (the “Form 8-K Amendment No. 1”), and the proposed amendments to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016 (the “Form 10-K”), as included with and described in the Company’s May 26, 2017 response to the Staff’s May 8, 2017 comment letter.

Simultaneously herewith, the Company is filing Amendment No. 2 to the Form 8-K (the “Form 8-K Amendment No. 2”). The Form 8-K Amendment No. 2 reflects responses to the Staff’s comments. The Company will file Amendment No. 1 to the Form 10-K (the “Form 10-K Amendment”) reflecting responses to the Staff’s comments prior to requesting acceleration of the effectiveness of the Registration Statement. The Company will also file Amendment No. 2 to the Registration Statement (the “Form S-1 Amendment No. 2”), which will incorporate by reference the Form 8-K Amendment No. 2 and the Form 10-K Amendment and also include other changes that are intended to update, clarify, and render more complete the information contained therein, prior to requesting acceleration of the effectiveness of the Registration Statement.

Capitalized terms used but not defined herein have the meanings set forth in the Form S-1 Amendment No. 1, the Form 8-K Amendment No. 2 or the Form 10-K, as applicable.

United States Securities and Exchange Commission

Division of Corporation Finance

June 20, 2017

Page 2

The headings and numbered paragraphs of this letter correspond to the headings and paragraph numbers contained in the Peabody Comment Letter and, to facilitate your review, the Company has reproduced the text of the Staff’s comments in italics below. Unless otherwise noted, references to page numbers and section headings in the Company’s responses below refer to page numbers and sections headings in the applicable amended filing.

Form 8-K/A filed May 26, 2017

Exhibit 99.1 Unaudited Pro Forma Condensed Consolidated Financial Data

Unaudited Pro Forma Condensed Consolidated Balance Sheet

Notes to the Unaudited Condensed Financial Data

Adjustments to Unaudited Pro Forma Condense Consolidated Balance Sheet, page 5

1. We have reviewed your revised disclosure in response to our comment one. We note your disclosure in adjustment G as it relates to common stock is based on a “hypothetical number of shares to be issued” and the value for the preferred stock is based on “the estimated fair value”. Per the guidance in Article 11-02(b)(6), pro forma adjustments should be factually supportable and the assumptions involved for each adjustment should be clearly explained. Please revise your disclosure to clarify how the number of shares to be issued was determined and the assumptions utilized to determine the fair value of the preferred stock. In addition, please provide us with a detailed discussion of how these adjustments relate to the shares issued in connection with your emergence from Chapter 11 as disclosed in Item 3.02 of the Form 8-K filed on April 3, 2017.

The Company acknowledges the Staff’s comment and, as a result, has updated adjustment G in the Form 8-K Amendment No. 2. Please see page 6 of Exhibit 99.1 to the Form 8-K Amendment No. 2.

The pro forma adjustment G included in the Form 8-K Amendment No. 1 assumed the following hypothetical shares to be issued on the Plan Effective Date, which can be reconciled to the disclosure in Item 3.02 of the Company’s Current Report on Form 8-K filed on April 3, 2017 and the pro forma balance sheet as of March 31, 2017 included in the Form 8-K Amendment No. 1 as follows:

	Number of Shares (Millions)
Common Stock — Holders of Allowed Claims(1)		11.6
Common Stock — Rights Offering (1)		51.2
Rights Offering (1145) Warrants		2.9
Common Stock — Backstop Commitment Agreement(1)		3.3
Private Warrants — Backstop Commitment Agreement		0.2
As Converted Basis Preferred Shares(2)		46.2
Common Stock — Commitment Premiums under Private Placement Agreement and Backstop Commitment Agreement(1)		4.8

2

United States Securities and Exchange Commission

Division of Corporation Finance

June 20, 2017

Page 3

Private Warrants — Commitment Premiums under Private Placement Agreement and Backstop Commitment Agreement		3.1
Total hypothetical shares of Common Stock per adjustment G		123.3
Common shares attributable to paid-in-kind dividends on Preferred Shares		13.1
Common shares attributable to initial grant under 2017 Incentive Compensation Plan		3.6
Additional common shares reserved for settlement of claims		0.9
Total common share equivalents used for valuation of equity		140.9
Par value per share	$	0.01
Par value of Common Stock per adjustment G	$	1.2

(1) Shares included in calculation of par value of common stock in the Form 8-K Amendment No. 2.

(2) Calculated as $750.0 million divided by $16.25 per share conversion price.

Adjustment G included in the Form 8-K Amendment No. 1 assumed that each warrant had been exercised and each preferred share had been converted on the Plan Effective Date.

In the Form 8-K Amendment No. 2, the Company excluded from the shares used to calculate the par value of common stock those common shares issuable upon exercise of the warrants and conversion of the preferred shares, as those common shares were not issued on the Plan Effective Date. Thus, the Company calculated the par value of common stock after giving effect to the issuance on the Plan Effective Date of approximately 71.0 million common shares with a par value of approximately $0.7 million. The difference in par value of approximately $0.5 million had an equal and offsetting impact to the amount of the adjustment to additional paid-in capital.

The estimated fair value of the preferred stock issued in accordance with the Plan is based upon the $750.0 million cash raised upon emergence from bankruptcy through the Private Placement, plus a premium to account for the fair value of the preferred shares’ conversion and dividend features. Each preferred share is convertible, at the holder’s election or upon the occurrence of certain triggering events, into common shares at a 35% discount relative to the initial per share purchase price of $25.00 and provides for three years of guaranteed paid-in-kind dividends, payable semiannually, at a rate of 8.5% per annum. The 46.2 million shares of common stock issuable upon conversion of the preferred shares issued under the Plan and the additional 13.1 million shares of common stock attributable to such preferred shares’ guaranteed paid-in-kind dividend feature constitute approximately 42% ownership of the total equity value of $3,105.0 million in the reorganized Company, and thus have a fair value of $1,305.4 million.

Form 10-K filed March 22, 2017

2. We note your response to comment 6 stating you will provide clarifying disclosure regarding the modifying factors. You also state you do not use a specific coal price to estimate your reserves, but that your reserves are economically recoverable when the coal price exceeds the mining and selling costs. Please explain how your Australian metallurgical coal reserves may be considered economic using these criteria. In addition,

3

United States Securities and Exchange Commission

Division of Corporation Finance

June 20, 2017

Page 4

please disclose in the filing for each mine, the pricing and cost information you used to demonstrate your reserves are economically recoverable.

The Company acknowledges the Staff’s comments. In response to the Staff’s request for an explanation of how the Company’s Australian metallurgical coal reserves may be considered economic, the Company notes that as of December 31, 2016, its Australian metallurgical coal reserves included 192 million tons of assigned reserves related to mines that were active during 2016 and an additional 226 million tons of unassigned reserves. Both assigned and unassigned reserves are evaluated using the applicable Life-of-Mine plan and utilizing the methods and processes described in detail below to estimate prices and costs. Based on the methods and processes applied to its Australian metallurgical coal mines, the Company believes the reserves are economically recoverable when comparing price and cost forecasts.

In response to the Staff’s request to provide disclosure of information regarding pricing and costs used to demonstrate that the Company’s reserves are economically recoverable, the Company intends to include the following disclosure in Part 1, Item 2. “Properties” in the Form 10-K Amendment:

For each mine or future mine, we employ a market-driven, risk adjusted capital allocation process to guide long-term mine planning of active operations and development projects for economically mineable coal. We refer to this process as Life-of-Mine (LOM) planning. The LOM plan projects, among other things, annual quantities and qualities for each coal product. The saleable product mix for a mine may include multiple thermal and metallurgical products with different targeted qualities. The expected volumes for each mine and product, as well as annual pricing forecasts for each product, developed as described below, and related cost forecasts, developed as described below, are then evaluated annually to determine the economically recoverable coal in the LOM plan.

Pricing

The pricing information used to establish our reserves includes internal, proprietary price forecasts and existing contract economics, in each case on a mine-by-mine and product-by-product basis. In general, our price forecasts are based on a thorough analytical process utilizing detailed supply and demand models, global economic indicators, projected foreign exchange rates, analyses of price relationships among various commodities, competing fuels analyses, projected steel demand, analyses of supplier costs, and other variables. Price forecasts, supply and demand models, and other key assumptions and analyses are stress tested against independent third-party research not commissioned by us to confirm the conclusions reached through our analytical processes, and our price forecasts fall within the ranges of the projections included in this third-party research. The development of the analyses, price forecasts, supply and demand models, and related assumptions are subject to multiple levels of management review.

4

United States Securities and Exchange Commission

Division of Corporation Finance

June 20, 2017

Page 5

Below is a description of some of the specific factors that we evaluate in developing our price forecasts for thermal and metallurgical coal products on a mine-by-mine and product-by-product basis. Differences between the assumptions and analyses included in our price forecasts and realized factors could cause actual pricing to differ from our forecasts.

Thermal

Several factors can influence thermal coal supply and demand and pricing. Demand is sensitive to total electric power generation volumes, which are determined in part by the impact of weather on heating and cooling demand, inter-fuel competition in the electric power generation mix, changes in capacity (additions and retirements), inter-basin or inter-country coal competition, coal stockpiles, and policy and regulations. Supply considerations impacting pricing include reserve positions, mining methods, strip ratios, production costs and capacity, and the cost of new supply (greenfield developments or extensions at existing mines).

In the United States, natural gas is the most significant substitute for thermal coal for electricity generation and can be one of the largest drivers of shifts in supply and demand and pricing. The competitiveness of natural gas as a generation fuel source has been strengthened by accelerated growth in domestic natural gas production over the last five years and comparatively low natural gas prices versus historic levels. The build out of renewable generation and subsidized power can also be a key driver of power market pricing and hence coal prices.

Internationally, thermal coal-fueled generation also competes with alternative forms of electric generation. The competiveness and availability of generation fueled by natural gas, oil, nuclear, hydro, wind, solar, and biomass vary by country and region and can have a meaningful impact on coal pricing. Policy and regulations, which vary from country to country, can also influence prices. In addition, seaborne thermal coal import demand can be significantly impacted by the availability of indigenous coal production, particularly in the two leading coal import countries, China and India, and the competitiveness of seaborne supply from leading thermal coal exporting countries, including Indonesia, Australia, Russia, Colombia, and South Africa.

5

United States Securities and Exchange Commission

Division of Corporation Finance

June 20, 2017

Page 6

Metallurgical

Several factors can influence metallurgical coal supply and demand and pricing. Demand is impacted by economic conditions and demand for steel, and is also impacted by competing technologies used to make steel, some of which do not use coal as a manufacturing input. Competition from other types of coal is also a key price consideration and can be impacted by coal quality and characteristics, delivered energy cost (including transportation costs), customer service and support, and reliability of supply.

Seaborne metallurgical coal import demand can also be significantly impacted by the availability of indigenous coal production, particularly in metallurgical coal import countries such as China and India, among others, as well as country-specific policies restricting or promoting domestic supply. The competitiveness of seaborne metallurgical coal supply from coal exporting countries, including Australia, the United States, Russia, Canada, and Mongolia, among others, is also an important price consideration.

In addition to the factors noted above, the prices which may be obtained at each individual mine or future mine can be impacted by factors such as (i) the mine’s location, which impacts the total delivered energy costs to its customers, (ii) quality characteristics, particularly if they are unique relative to competing mines, (iii) assumed transportation costs, and (iv) other mine costs that are contractually passed on to customers in certain commercial relationships.

Costs

The cost estimates we use to establish our reserves are generally estimated according to internal processes that project future costs based on historic costs and expected future trends. The estimated costs normally include mining, processing, transportation, royalty, add-on tax, and other mining-related costs. Our estimated mining and processing costs reflect projected changes in prices of consumable commodities (mainly diesel fuel, explosives and steel), labor costs, geological and mining conditions, targeted product qualities, and other mining-related costs. Estimates for other sales-related costs (mainly transportation, royalty and add-on tax) are based on contractual prices or fixed rates. Specific factors that may impact the cost in our various operations include:

• Geological settings. The geological characteristics of each mine are among the most important factors that determine the mining cost. Our geology department conducts the exploration program and provides geological models for the LOM process. Coal seam depth, thickness, dipping angle, partings, and quality constrain the available mining methods and size of operations. Shallow coal is typically mined by surface mining methods by which the primary cost is overburden removal. Deep coal is typically mined by underground mining methods where the primary costs include coal extraction and conveyance and roof control.

• Scale of operations and the equipment sizes. For surface mines, our dragline systems generally have a lower unit cost than truck-and-shovel systems for overburden removal. The longwall operations generally are more cost effective than room-and-pillar operations for underground mines.

6

United States Securities and Exchange Commission

Division of Corporation Finance

June 20, 2017

Page 7

• Commodity prices. For surface mines, the costs of diesel fuel and explosives are major components of the total mining cost. For underground mines, the steel used for roof bolts represents a significant cost. Forecasted commodity prices are used to project those costs in the financial models we use to establish our reserves.

• Target product quality. By targeting a premium quality product, our mining and processing processes may experience more coal losses. By lowering product quality the coal losses can be minimized and therefore a lower cost per ton can be achieved. In our mine plans, the product qualities are estimated to correspond to existing contracts and forecasted market demands.

• Transportation costs. Transportation costs vary by region. Most of our U.S. operations sell coal at mine loadouts. Therefore, no transportation expenses are included in our U.S. cost estimates. Our Australian operations sell coal at designated ports or local power plants. The estimated costs for our Australian operations include rail transportation and related fees at ports.

• Royalty costs. Our royalty costs are based upon contractual agreements for the coal leased from governments or private owners. The royalty rates for coal leased from governments differ by country and, in some cases, by mining method. Estimated add-on taxes and other sales-related costs are determined according to government regulations or historic costs.

• Exchange rates. Costs related to our Australian production are predominantly denominated in Australian dollars, while the Australian coal that we export is sold in U.S. dollars. As a result, Australian/U.S. dollar exchange rates impact the U.S. dollar cost of Australian production.

Based on our evaluations of the estimated prices for our coal, and costs and expenses of mining and selling our coal, which evaluations are performed on a mine-by-mine and product-by-product basis, we have concluded our reserves were economically recoverable as of December 31, 2016.

3. We note your response to comment 7 indicating you will provide additional historical information for your U.S. thermal coal prices. Please clarify, if true, the Illinois market price is the price basis for your Midwestern & Western mine operations, describing the relevant factors that may affect the pricing under your long-term contracts.

The Company acknowledges the Staff’s comment. In this regard, the Company notes that Illinois Basin 11,500 Btu/Lb coal is most closely related to the various coals produced by our Midwestern U.S. Mining segment and is not closely related to coals produced by the Company’s Western U.S. Mining segment. The Company intends to provide additional disclosure of the key factors which may cause our realized pricing to differ from the relevant periodic spot and prompt month pricing by including in the Form 10-K Amendment the disclosure changes marked in the paragraph below.

Spot pricing for Premium HCC, Premium PCI coal, and Newcastle index thermal coal, and prompt month pricing for Powder River Basin (PRB) 8,880 Btu/Lb coal and Illinois

7

United States Securities and Exchange Commission

Division of Corporation Finance

June 20, 2017

Page 8

Basin 11,500 Btu/Lb coal during the year ended December 31, 2016 is set forth in the table below. While these prices are related to our primary operating segments, (with the exception of our Western U.S. Mining segment, for which there is no similar spot or prompt pricing data available) such pricing is not necessarily indicative of the pricing we realized during the year since we generally sell coal under long-term contracts where pricing is determined based on various factors. Such long-term contracts may vary significantly in many respects, including price adjustment features, price reopener terms, coal quality requirements, quantity parameters, permitted sources of supply, treatment of environmental constraints, extension options, force majeure and termination and assignment provisions. Competition from other coal producers and alternative fuels such as natural gas may also impact our realized pricing.

For additional disclosure regarding the factors that may affect the price of coal and, consequently, the prices at which the Company may be able to enter into long-term contracts, the Company respectfully refers the Staff to “Business—Competition” in Part I, Item 1 of the Form 10-K.

*  *  *  *  *

Please call me at (314) 342-3400 should you wish to discuss the matters addressed above or other issues relating to the Registration Statement, the Form 10-K, or the Form 8-K. Thank you for your attention to this matter.

Very truly yours,

/s/ Amy B. Schwetz

Amy B. Schwetz

Executive Vice President and

        Chief Financial Officer

Peabody Energy Corporation

cc: A. Verona Dorch

Peabody Energy Corporation

Edward B. Winslow

Jones Day

Bradley C. Brasser

Jones Day

8