8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): January 9, 2019

CHESAPEAKE ENERGY CORPORATION
(Exact name of Registrant as specified in its Charter)
Oklahoma		1-13726	73-1395733
(State or other jurisdiction of incorporation)		(Commission File No.)	(IRS Employer Identification No.)
6100 North Western Avenue, Oklahoma City, Oklahoma			73118
(Address of principal executive offices)			(Zip Code)
	(405) 848-8000
	(Registrant’s telephone number, including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

x Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§ 230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§ 240.12b-2 of this chapter).
	Emerging growth company	o
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.		o

Item 2.02 Results of Operations and Financial Condition.

On January 9, 2019, Chesapeake Energy Corporation issued a press release providing preliminary unaudited financial and operational results for the fourth quarter of 2018. A copy of the press release is attached as Exhibit 99.1 to this Current Report on Form 8-K.

The information contained in Item 2.02 of this report and Exhibit 99.1 attached hereto shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except as expressly set forth by specific reference in such a filing.

Item 7.01 Regulation FD Disclosure.

The management of Chesapeake Energy Corporation will present at the Goldman Sachs Global Energy Conference on January 9, 2019. A slide presentation of materials to be presented at the conference is attached hereto as Exhibit 99.2 and will also be accessible via the Investor Presentations section of the company’s website: http://www.chk.com/investors/presentations.

The information contained in Item 7.01 of this report and Exhibit 99.2 attached hereto shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except as expressly set forth by specific reference in such a filing.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits.

Exhibit No.	Document Description
99.1	Chesapeake Energy Corporation press release dated January 9, 2019
99.2	Chesapeake Energy Corporation Investor Presentation

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	CHESAPEAKE ENERGY CORPORATION
By:	/s/ James R. Webb
	James R. Webb
	Executive Vice President - General Counsel and Corporate Secretary

Date: January 9, 2019

EX-99.1

Exhibit 99.1

N E W S   R E L E A S E

FOR IMMEDIATE RELEASE

JANUARY 9, 2019

CHESAPEAKE ENERGY CORPORATION REPORTS SELECTED PRELIMINARY 2018 FOURTH QUARTER RESULTS AND OPERATIONAL UPDATE

OKLAHOMA CITY, January 9, 2019 - Chesapeake Energy Corporation (NYSE:CHK) today reported selected financial and operational results for the 2018 fourth quarter. Highlights include:

• Estimated average 2018 fourth quarter production range of approximately 462,000 to 464,000 barrels of oil equivalent (boe) per day

• Estimated average 2018 fourth quarter oil production range of approximately 86,000 to 87,000 barrels (bbls) of oil per day; divested Utica oil volumes have been completely replaced by oil volume growth in the Powder River Basin and Eagle Ford Shale in the two months following the sale

• Achieved year-end 2018 Powder River Basin net production exit rate of approximately 38,500 boe per day (approximately 47 percent oil)

• Estimated 2018 fourth quarter capital expenditures of approximately $545 million, including $50 million of capitalized interest and Utica investments

• Utica Shale divestment and debt refinancing eliminated approximately $2.6 billion in secured leverage, positioning the company with ample liquidity and no significant near-term debt maturities; debt balance as of December 31, 2018 of approximately $8.2 billion including $419 million drawn on revolving credit facility

Doug Lawler, Chesapeake’s President and Chief Executive Officer, commented, “Chesapeake continues to advance our strategic priorities of improving margins, reducing debt and achieving sustainable cash flow neutrality. In 2018, asset divestitures generated more than $2 billion in net proceeds which facilitated the retirement of our term loan and senior secured second lien debt. Total debt was reduced by approximately $1.8 billion from year-end 2017. Importantly, the divested daily oil volumes associated with the Utica sale, which represented 10% of our third quarter oil production, were replaced in the last two months of the year through our legacy South Texas and emerging Powder River Basin oil engines.

“Looking forward to 2019, we are confident in our ability to drive further competitive performance through the quality of our investments and our capital and operating discipline. We have secured a strong hedge position for gas and oil which provides stability and certainty in our cash generating capability. We plan to reduce our 2019 capital expenditures by lowering our rig count by approximately 20 percent, expecting to average 14 rigs versus our current rig count of 18. Further, we expect our capital efficiency to improve in 2019 as total net capital per rig line is projected to decrease by 15 to 20 percent compared to 2018. The improvement in our capital efficiency, along with our focus on our high-margin oil investments, should result in higher operating cash flow and stronger margins in 2019 compared to 2018.

INVESTOR CONTACT:	MEDIA CONTACT:	CHESAPEAKE ENERGY CORPORATION
Brad Sylvester, CFA (405) 935-8870 ir@chk.com	Gordon Pennoyer (405) 935-8878 media@chk.com	6100 North Western Avenue P.O. Box 18496 Oklahoma City, OK 73154

“We look forward to consummating the merger with WildHorse Resources and further strengthening our portfolio and competitiveness with another strong oil growth asset. We plan to provide detailed capital guidance for the combined company later in the 2019 first quarter, but at present we anticipate operating four rigs on the WildHorse acreage in 2019. We look forward to further building on our track record of performance in 2019 and are excited to continue demonstrating our leadership and differential competitiveness.”

Operations Update

In the Powder River Basin (PRB), Chesapeake achieved a net production exit rate of approximately 38,500 boe per day (approximately 47 percent oil and 60 percent total liquids) in December. Volumes are expected to accelerate during 2019, resulting in annual net production from the basin to more than double compared to 2018. Chesapeake is operating five rigs in the PRB, all of which are currently drilling the Turner formation.

The Eagle Ford Shale in Texas continues to deliver the highest margins in the company, primarily driven by premium Gulf Coast crude oil pricing. Despite the lingering effects of regional flooding in the area, the combination of strong well performance, greater volumes transported via pipeline compared to trucking and new field technologies resulted in Eagle Ford net production averaging approximately 105,000 boe per day (approximately 58 percent oil) for the 2018 fourth quarter, which is better than previously expected. During the 2018 fourth quarter, the company continued its Austin Chalk and Upper Eagle Ford appraisal programs and anticipates updating these results at the end of the 2019 first quarter. The company is currently utilizing four rigs in the Eagle Ford.

In the Marcellus Shale in Pennsylvania, Chesapeake continues to create significant free cash flow due to higher realized in-basin gas prices. Two new Lower Marcellus records were set in northern Sullivan County during the 2018 fourth quarter, demonstrating that appropriate development spacing along with longer laterals and better steering within the target zone can deliver exceptional value. The JOEGUSWA 4HC well had a lateral length of 13,803 feet and set a 24-hour initial production record of 62.6 million cubic feet of gas (mmcf) per day with a 2,600 psi flowing pressure. This well performance surpassed the current 24-hour initial production record from the McGavin well of approximately 61.8 mmcf per day. The JOEGUSWA 5HC well with a lateral length of 9,808 feet set a 24-hour initial production record of 73.4 mmcf per day at a 3,000 psi flowing pressure. While both wells had fracture stimulations using approximately 1,600 pounds of sand per foot of lateral, both wells were also bounded by previously drilled wells that were approximately 1,300 feet away, pointing to the advantage and opportunity that Chesapeake’s acreage position provides in its ability to properly space future drilling locations.

Balance Sheet and Hedge Position Update

As of December 31, 2018, Chesapeake’s principal amount of debt outstanding was approximately $8.167 billion, compared to $9.981 billion as of December 31, 2017. Additionally, the company has approximately $2.5 billion of available liquidity under its senior secured revolving credit facility.

During the 2018 fourth quarter, the company was very active in hedging 2019 oil and gas volumes and at December 31, 2018, Chesapeake had downside protection on approximately 590 billion cubic feet (bcf) of its forecasted 2019 gas production at $2.85 per thousand cubic feet (mcf). Additionally, the company has downside protection on approximately 16 million barrels (mmbbls) of its forecasted 2019 oil production at $58.61 per barrel and oil basis protection on approximately 7 mmbbls of its forecasted 2019 Eagle Ford oil production at a premium to WTI of more than $6.00 per barrel.

Headquartered in Oklahoma City, Chesapeake Energy Corporation's (NYSE: CHK) operations are focused on discovering and developing its large and geographically diverse resource base of unconventional oil and natural gas assets onshore in the United States. The company also owns an oil and natural gas marketing business.

Forward-Looking Statements

This communication may contain certain forward-looking statements, including certain plans, expectations, goals, projections, and statements about the benefits of the proposed business combination transaction (the “Transaction”) between WildHorse Resource Development Corporation (“WildHorse”) and Chesapeake Energy Corporation (“Chesapeake”), WildHorse’s and Chesapeake’s plans, objectives, expectations and intentions, the expected timing of completion of the Transaction, capital expenditures, future operating results and other statements that are not historical facts. Such statements are subject to numerous assumptions, risks, and uncertainties. Statements that do not describe historical or current facts, including statements about beliefs and expectations, are forward-looking statements. Forward-looking statements may be identified by words such as expect, anticipate, believe, intend, estimate, plan, target, goal, or similar expressions, or future or conditional verbs such as will, may, might, should, would, could, or similar variations. The forward-looking statements are intended to be subject to the safe harbor provided by Section 27A of the Securities Act of 1933, Section 21E of the Securities Exchange Act of 1934, and the Private Securities Litigation Reform Act of 1995. They include statements that give our current expectations, management's outlook guidance or forecasts of future events, production and well connection forecasts, estimates of operating costs, anticipated capital and operational efficiencies, planned development drilling and expected drilling cost reductions, anticipated timing of wells to be placed into production, general and administrative expenses, capital expenditures, the timing of anticipated asset sales and proceeds to be received therefrom, the expected use of proceeds of anticipated asset sales, projected cash flow and liquidity, our ability to enhance our cash flow and financial flexibility, plans and objectives for future operations, the ability of our employees, portfolio strength and operational leadership to create long-term value, and the assumptions on which such statements are based. Although we believe the expectations and forecasts reflected in the forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate or changed assumptions or by known or unknown risks and uncertainties.

While there is no assurance that any list of risks and uncertainties or risk factors is complete, below are certain factors which could cause actual results to differ materially from those contained or implied in the forward-looking statements: the possibility that the Transaction does not close when expected or at all because required regulatory, shareholder or other approvals are not received or other conditions to the closing are not satisfied on a timely basis or at all; the risk that regulatory approvals required for the Transaction are not obtained or are obtained subject to conditions that are not anticipated; potential adverse reactions or changes to business or employee relationships, including those resulting from the announcement or completion of the Transaction; uncertainties as to the timing of the Transaction; competitive responses to the Transaction; the possibility that the anticipated benefits of the Transaction are not realized when expected or at all, including as a result of the impact of, or problems arising from, the integration of the two companies; the possibility that the Transaction may be more expensive to complete than anticipated, including as a result of unexpected factors or events; diversion of management’s attention from ongoing business operations and opportunities; the ability of Chesapeake to complete the acquisition and integration of WildHorse successfully; litigation relating to the Transaction; and other factors that may affect future results of WildHorse and Chesapeake.

Additional factors that could cause results to differ materially from those described above can be found in WildHorse’s Annual Report on Form 10-K for the year ended December 31, 2017 and in its subsequent Quarterly Reports on Form 10-Q, each of which is on file with the SEC and available in the “Investor Relations” section of WildHorse’s website, http://www.wildhorserd.com/, under the subsection “SEC Filings” and in other documents WildHorse files with the SEC, and in Chesapeake’s Annual Report on Form 10-K for the year ended December 31, 2017 and in its subsequent Quarterly Reports on Form 10-Q, each of which is on file with the SEC and available in the “Investors” section of Chesapeake’s website, https://www.chk.com/, under the heading “SEC Filings” and in other documents Chesapeake files with the SEC.

These risk factors include the volatility of oil, natural gas and NGL prices; the limitations our level of indebtedness may have on our financial flexibility; our inability to access the capital markets on favorable terms; the availability of cash flows from operations and other funds to finance reserve replacement costs or satisfy our debt obligations; downgrade in our credit rating requiring us to post more collateral under certain commercial arrangements; write-downs of our oil and natural gas asset carrying values due to low commodity prices; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and projecting future rates of production and the amount and timing of development expenditures; our ability to generate profits or achieve targeted results in drilling and well operations; leasehold terms expiring before production can be established; commodity derivative activities resulting in lower prices realized on oil, natural gas and NGL sales; the need to secure derivative liabilities and the inability of counterparties to satisfy their obligations; adverse developments or losses from pending or future litigation and regulatory proceedings, including royalty claims; charges incurred in response to market conditions and in connection with our ongoing actions to reduce financial leverage and complexity; drilling and operating risks and resulting liabilities; effects of environmental protection laws and regulation on our business; legislative and regulatory initiatives further regulating hydraulic fracturing; our need to secure adequate supplies of water for our drilling operations and to dispose of or recycle the water used; impacts of potential legislative and regulatory actions addressing climate change; federal and state tax proposals affecting our industry; potential OTC derivatives regulation limiting our ability to hedge against commodity price fluctuations; competition in the oil and gas exploration and production industry; a deterioration in general economic, business or industry conditions; negative public perceptions of our industry; limited control over properties we do not operate; pipeline and gathering system capacity constraints and transportation interruptions; terrorist activities and cyber-attacks adversely impacting our operations; an interruption in operations at our headquarters due to a catastrophic event; certain anti-takeover provisions that affect shareholder rights; and our inability to increase or maintain our liquidity through debt repurchases, capital exchanges, asset sales, joint ventures, farmouts or other means.

In addition, disclosures concerning the estimated contribution of derivative contracts to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility. Our production forecasts are also dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Expected asset sales and the Transaction may not be completed in the time frame anticipated or at all.

All forward-looking statements speak only as of the date they are made and are based on information available at that time. Neither WildHorse nor Chesapeake assumes any obligation to update forward-looking statements to reflect circumstances or events that occur after the date the forward-looking statements were made or to reflect the occurrence of unanticipated events except as required by federal securities laws. As forward-looking statements involve significant risks and uncertainties, caution should be exercised against placing undue reliance on such statements.

Important Additional Information

This communication is for informational purposes only and does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval, in any jurisdiction, pursuant to the Transaction or otherwise, nor shall there be any sale, issuance, exchange or transfer of the securities referred to in this document in any jurisdiction in contravention of applicable law.

In connection with the Transaction, Chesapeake has filed with the SEC a registration statement on Form S-4 that includes a joint proxy statement of Chesapeake and WildHorse and a prospectus of Chesapeake, as well as other relevant documents concerning the Transaction. The registration statement was declared effective by the SEC on December 21, 2018 and WildHorse and Chesapeake commenced mailing the definitive joint proxy statement/prospectus to WildHorse’s stockholders and Chesapeake’s shareholders, respectively, for their consideration on or about December 26, 2018. STOCKHOLDERS OF WILDHORSE AND SHAREHOLDERS OF CHESAPEAKE ARE URGED TO READ THE JOINT PROXY STATEMENT/PROSPECTUS REGARDING THE TRANSACTION AND ANY OTHER RELEVANT DOCUMENTS FILED WITH THE SEC, AS WELL AS ANY AMENDMENTS OR SUPPLEMENTS TO THOSE DOCUMENTS, BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION. Investors will be able to obtain a free copy of the registration statement and the joint proxy statement/prospectus, as well as other filings containing information about WildHorse and Chesapeake, without charge, at the SEC’s website (http://www.sec.gov). Copies of the documents filed with the SEC can also be obtained, without charge, by directing a request to Investor Relations, WildHorse, P.O. Box 79588, Houston, Texas 77279, Tel. No. (713) 255-9327 or to Investor Relations, Chesapeake, 6100 North Western Avenue, Oklahoma City, Oklahoma, 73118, Tel. No. (405) 848-8000.

Participants in the Solicitation

WildHorse, Chesapeake and certain of their respective directors, executive officers and employees may be deemed to be participants in the solicitation of proxies in respect of the Transaction. Information regarding WildHorse’s directors and executive officers is available in its definitive proxy statement, which was filed with the SEC on April 2, 2018, and certain of its Current Reports on Form 8-K. Information regarding Chesapeake’s directors and executive officers is available in its definitive proxy statement, which was filed with the SEC on April 6, 2018, and certain of its Current Reports on Form 8-K. Other information regarding the participants in the proxy solicitation and a description of their direct and indirect interests, by security holdings or otherwise, is contained in the definitive joint proxy statement/prospectus and other relevant materials filed with the SEC. Free copies of this document may be obtained as described in the preceding paragraph.

EX-99.2

Exhibit 99.2 JANUARY 2019 UPDATE

FORWARD-LOOKING STATEMENT Cautionary Statement Regarding Forward-Looking Information This communication may contain certain forward-looking statements, including certain plans, expectations, goals, projections, and statements about the benefits of the proposed transaction, WildHorse’s and Chesapeake’s plans, objectives, expectations and intentions, the expected timing of completion of the transaction, and other statements that are not historical facts. Such statements are subject to numerous assumptions, risks, and uncertainties. Statements that do not describe historical or current facts, including statements about beliefs and expectations, are forward-looking statements. Forward-looking statements may be identified by words such as expect, anticipate, believe, intend, estimate, plan, target, goal, or similar expressions, or future or conditional verbs such as will, may, might, should, would, could, or similar variations. The forward-looking statements are intended to be subject to the safe harbor provided by Section 27A of the Securities Act of 1933, Section 21E of the Securities Exchange Act of 1934, and the Private Securities Litigation Reform Act of 1995. While there is no assurance that any list of risks and uncertainties or risk factors is complete, below are certain factors which could cause actual results to differ materially from those contained or implied in the forward-looking statements: the possibility that the proposed transaction does not close when expected or at all because required regulatory, shareholder or other approvals are not received or other conditions to the closing are not satisfied on a timely basis or at all; the risk that regulatory approvals required for the proposed merger are not obtained or are obtained subject to conditions that are not anticipated; potential adverse reactions or changes to business or employee relationships, including those resulting from the announcement or completion of the transaction; uncertainties as to the timing of the transaction; competitive responses to the transaction; the possibility that the anticipated benefits of the transaction are not realized when expected or at all, including as a result of the impact of, or problems arising from, the integration of the two companies; the possibility that the transaction may be more expensive to complete than anticipated, including as a result of unexpected factors or events; diversion of management’s attention from ongoing business operations and opportunities; the ability of Chesapeake to complete the acquisition and integration of WildHorse successfully; litigation relating to the transaction; and other factors that may affect future results of WildHorse and Chesapeake. Additional factors that could cause results to differ materially from those described above can be found in WildHorse’s Annual Report on Form 10-K for the year ended December 31, 2017 and in its subsequent Quarterly Reports on Form 10-Q for the quarters ended March 31, 2018, June 30, 2018, and September 30, 2018, each of which is on file with the SEC and available in the “Investor Relations” section of WildHorse’s website, http://www.wildhorserd.com/, under the subsection “SEC Filings” and in other documents WildHorse files with the SEC, and in Chesapeake’s Annual Report on Form 10-K for the year ended December 31, 2017 and in its subsequent Quarterly Reports on Form 10-Q for the quarters ended March 31, 2018, June 30, 2018 and September 30, 2018 each of which is on file with the SEC and available in the “Investors” section of Chesapeake’s website, https://www.chk.com/, under the heading “SEC Filings” and in other documents Chesapeake files with the SEC. All forward-looking statements speak only as of the date they are made and are based on information available at that time. Neither WildHorse nor Chesapeake assumes any obligation to update forward-looking statements to reflect circumstances or events that occur after the date the forward-looking statements were made or to reflect the occurrence of unanticipated events except as required by federal securities laws. As forward-looking statements involve significant risks and uncertainties, caution should be exercised against placing undue reliance on such statements. We use certain terms in this presentation such as “Resource Potential,” “Net Resource,” “Net Reserves” and similar terms that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. These terms include reserves with substantially less certainty, and no discount or other adjustment is included in the presentation of such reserve numbers. U.S. investors are urged to consider closely the disclosure in our Form 10-K for the year ended December 31, 2017, File No. 1-13726 and in our other filings with the SEC, available from us at 6100 North Western Avenue, Oklahoma City, Oklahoma 73118. These forms can also be obtained from the SEC by calling 1-800-SEC-0330. Important Additional Information This communication relates to a proposed business combination transaction (the “Transaction”) between WildHorse Resource Development Corporation (“WildHorse”) and Chesapeake Energy Corporation (“Chesapeake”). This communication is for informational purposes only and does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval, in any jurisdiction, pursuant to the Transaction or otherwise, nor shall there be any sale, issuance, exchange or transfer of the securities referred to in this document in any jurisdiction in contravention of applicable law. In connection with the Transaction, Chesapeake has filed with the SEC a registration statement on Form S-4 that includes a joint proxy statement of Chesapeake and WildHorse and a prospectus of Chesapeake, as well as other relevant documents concerning the Transaction. The registration statement was declared effective by the SEC on December 21, 2018 and WildHorse and Chesapeake commenced mailing the definitive joint proxy statement/prospectus to WildHorse’s stockholders and Chesapeake’s shareholders, respectively, for their consideration on or about December 26, 2018. STOCKHOLDERS OF WILDHORSE AND SHAREHOLDERS OF CHESAPEAKE ARE URGED TO READ THE JOINT PROXY STATEMENT/PROSPECTUS REGARDING THE TRANSACTION AND ANY OTHER RELEVANT DOCUMENTS FILED WITH THE SEC, AS WELL AS ANY AMENDMENTS OR SUPPLEMENTS TO THOSE DOCUMENTS, BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION. Investors will be able to obtain a free copy of the registration statement and the joint proxy statement/prospectus, as well as other filings containing information about WildHorse and Chesapeake, without charge, at the SEC’s website (http://www.sec.gov). Copies of the documents filed with the SEC can also be obtained, without charge, by directing a request to Investor Relations, WildHorse, P.O. Box 79588, Houston, Texas 77279, Tel. No. (713) 255-9327 or to Investor Relations, Chesapeake, 6100 North Western Avenue, Oklahoma City, Oklahoma, 73118, Tel. No. (405) 848-8000. Participants in the Solicitation WildHorse, Chesapeake and certain of their respective directors, executive officers and employees may be deemed to be participants in the solicitation of proxies in respect of the Transaction. Information regarding WildHorse’s directors and executive officers is available in its definitive proxy statement, which was filed with the SEC on April 2, 2018, and certain of its Current Reports on Form 8-K. Information regarding Chesapeake’s directors and executive officers is available in its definitive proxy statement, which was filed with the SEC on April 6, 2018, and certain of its Current Reports on Form 8-K. Other information regarding the participants in the proxy solicitation and a description of their direct and indirect interests, by security holdings or otherwise, is contained in the definitive joint proxy statement/prospectus and other relevant materials filed with the SEC. Free copies of this document may be obtained as described in the preceding paragraph. January 2019 Update 2

WILDHORSE ACQUISITION ACCELERATES CHESAPEAKE’S STRATEGIC PLAN Acquisition of WildHorse Margin Enhancement Increases margins from high-value oil production Free Cash Flow Accelerates transition to positive free cash flow Long Term Net Debt / Accelerates deleveraging EBITDA of 2x Chesapeake’s continued commitment EHS Excellence Improving environmental and safety performance January 2019 Update 3

TRANSACTION OVERVIEW > $3.977 billion transaction value • At the election of WildHorse shareholders, 5.989 shares of Chesapeake common Consideration stock per WildHorse share of common stock or 5.336 shares of Chesapeake common stock plus $3.00 per WildHorse share of common stock • Total cash consideration expected to be between $275 – $400 million Pro Forma > Chesapeake’s shareholders will own approximately 55% and WildHorse shareholders Ownership and will own approximately 45% of the combined company Governance > WildHorse will nominate two directors to the Chesapeake Board of Directors > Approval by both Chesapeake and WildHorse shareholders > NGP Energy Capital Management, Carlyle and WRD CEO have entered into a voting Path to Close and support agreement with respect to the transaction > Customary regulatory approvals January 2019 Update 4

STRATEGIC PORTFOLIO ADDITION POSITIONS CHK FOR ADDITIONAL VALUE CREATION ACREAGE POSITION Adds significant premier Eagle Ford asset at an attractive valuation Accelerates cash flow generation with profitable oil growth Materially improves margins and financial profile WildHorse Leasehold CHK Leasehold WildHorse Resource Development Corporation Net acres (84% WI / 66% NRI)(1) ~420,000 ~655,000 Percentage undeveloped acreage 80% – 85% Pro forma Eagle Ford net acreage position Net production 47 mboe/d(2) ASSET ASSET OVERVIEW ~150,000 boe/d (~60% Oil) Liquids / Oil 88% / 73% 2Q’18 Pro forma Eagle Ford production (1) Estimated average interest of future operated locations (2) 2Q’18 Actuals WRD data reflects CHK’s analysis based solely on public information. January 2019 Update 5

ACCELERATING VALUE, DELIVERING ON OUR PROMISES(1) 160165 – 170 30 125130 – 130 25 Improves 19 Enhances 80 oil mix percentage oil production approximately approximately bbls/d % oil % 2x by 2020 60% by 2020 CHK18E(2) PF19E PF20E CHK18E PF19E PF20E Efficiencies drive average annual $200 – $280 million savings total of $1.0 – $1.5 billion by 2023 $19 4.2x $16 3.6x Increases $12 Accelerates 2.8x EBITDA per boe margin deleveraging approximately approximately $ / boe / $ by 2020 by 2020 35% 50% EBITDAadj. / debt Net CHK18E PF19E PF20E CHK18E PF19E PF20E (1) Assumes full year results and strip pricing as of 10/25/2018 (2) Adjusted for Utica disposition as of 1/1/2018 WRD data reflects CHK’s analysis based solely on public information. January 2019 Update 6

COST SAVINGS CREATE SIGNIFICANT SHAREHOLDER VALUE ANNUAL SAVINGS Operational Efficiencies $50 – $80 million Capital Efficiencies $150 – $200 million Total $200 – $280 million Five Year Total Savings(1) $1.0$1.0 –– $1.51.5 billion Operational efficiencies include savings from reduced LOE, G&A and downtime Capital efficiencies include savings from longer laterals and improved well design (1) Realized post closing WRD data reflects CHK’s analysis based solely on public information. January 2019 Update 7

OPPORTUNITIES TO CAPTURE ADDITIONAL MARKETING SYNERGIES Significant synergies available by leveraging Chesapeake’s existing crude transportation options Cooks Point Terminal Large, contiguous Eagle Ford oil position • Abundant pipeline capacity and infrastructure • Advantaged pricing due to proximity Houston Markets to Gulf Coast and export markets 2019 WTI +$5.50 Gardendale Terminal Corpus Christi Terminal 2019 WTI +$5.50 WildHorse Leasehold CHK Leasehold Pipeline WRD data reflects CHK’s analysis based solely on public information. January 2019 Update 8

CREATING AN EAGLE FORD POWERHOUSE Well understood geology similar to existing CHK position ACREAGE POSITION WildHorse Leasehold B CHK Leasehold High on the learning curve Eagle Ford Play • Learnings from more than 2,000 Eagle Ford wells directly transferable to large undeveloped WildHorse position Austin Chalk and improved oil recovery (IOR) offer tangible upside A A Chesapeake WildHorse B Eagle Ford Eagle Ford SW NE Austin Chalk Woodbine Sands 150ʹ – 450ʹ thickness 100ʹ – 500ʹ thickness Eagle Ford 6,000ʹ – 11,000ʹ TVD 6,000ʹ – 11,000ʹ TVD Buda Maverick Basin South Texas Basin Karnes Trough San Marcos Arch East Texas Basin WRD data reflects CHK’s analysis based solely on public information. January 2019 Update 9

THE CHESAPEAKE ADVANTAGE Eagle Ford Lateral Length (mean)(1) Operations Support Center 12,000 10,000 Reservoir Technology Center 8,000 Drilling and completion leadership 6,000 4,000 • >2,000 Eagle Ford wells to date 2,000 Logistics expertise 0 Proven operational performance EHS excellence Eagle Ford D&C $ / Lateral Foot(1) 1,600 1,400 In-house marketing team 1,200 1,000 800 600 Proven expertise helps 400 drive costs down 200 0 (1) Source: RS Energy Group 2017+ TIL as of 9/2018; Peers include: Carrizo, ConocoPhillips, Devon, Encana, Enervest, EOG, EP Energy, Equinor, Lewis Energy Group, Marathon, Murphy, Sanchez, SM Energy; WRD wells could contain science and evaluation capital. WRD data reflects CHK’s analysis based solely on public information. January 2019 Update 10

CHK TODAY: DIVERSE & STRONG PORTFOLIO CORE POSITIONS ACROSS MULTIPLE BASINS Marcellus: Leading the Industry Powder River Basin: Oil-growth Engine Generating ~$350 million in free cash flow(1) in 2018 Oil production will more than double in 2019 Mid-Continent: Growth Optionality Efficient oil volumes, appraising liquid-rich opportunities Gulf Coast: Consistent Performance Access to premium Gulf Coast markets South Texas: Free Cash Flow Machine Generating ~$560 million in free cash flow(1) in 2018 (1) Free cash flow defined as net revenue less all operating costs and capital expenditures. Excludes corporate overhead costs such as capitalized interest and capitalized G&A expenses. WRD data reflects CHK’s analysis based solely on public information. January 2019 Update 11

ACQUISITION CREATES PREMIER DIVERSIFIED INDEPENDENT WITH SIGNIFICANT HIGH-MARGIN OIL-GROWTH RUNWAY Targeting 80%+ of future drilling and completion activity focused on high-margin oil-growth assets High-margin Oil-growth Assets(1) Powder River Basin ~253,000 Acres 29 mboe/d CHK Eagle Ford ~235,000 Acres 100 mboe/d WRD Eagle Ford ~420,000 Acres 47 mboe/d(2) Cash-generating Gas Assets(1) Gulf Coast ~339,000 Acres 128 mboe/d Appalachia North ~547,000 Acres 135 mboe/d Growth Optionality(1) Mid-Continent ~775,000 Acres 25 mboe/d WildHorse Addition Exploration/Other ~1,521,000 Acres N/A Premier high-margin oil-growth engine (1) Unless otherwise noted, operational statistics are as of 9/30/2018 for acreage totals and total production as of 3Q’18. Acreage and production volumes are net to CHK. (2) Actual production for 2Q’18 WRD data reflects CHK’s analysis based solely on public information. January 2019 Update 12

ACCELERATES CHK’S STRATEGIC AND FINANCIAL PLAN Adds significant premier Eagle Ford asset at attractive valuation Increases cash flow generation with profitable oil growth Materially improves margins and financial profile Positions Chesapeake for greater value creation January 2019 Update 13

WildHorse Technical Review January 2019 Update 14

EASTERN EAGLE FORD EVALUATION INITIATED IN 2012 Chesapeake valuation of Eastern Eagle Ford based on bottoms-up internal regional knowledge and expertise 2012 – 2017: CHK Woodbine team evaluates emerging Eastern Eagle Ford play • Play level subsurface evaluation and detailed reservoir mapping to determine 1Q’18: main controls on production First WRD/CHK • Identified high-potential area in and around Burleson County discussions 2012 2017 2018 T e c h n o l o g y e v o l v e s 1H’17: 1Q’18: Regional assessment highgrades Updated evaluation WRD position in the play with additional well • Subsurface evaluation with proprietary and public data performance and detailed reservoir mapping • Well level economic assessment • Management review May 2017 January 2019 Update 15

CHESAPEAKE’S EVALUATION FOUNDATION Eastern Eagle Ford Data Map Extensive review of WRD’s Eagle Ford position conducted 3D seismic Dense log footprint prior to receipt of proprietary data coverage Existing subsurface and commercial evaluations initiated in 2012 ~1,200 wells with logs • Equivalent to ~2 wells/mi2 WildHorse acreage ~300 producing horizontals • ~145 with Gen 3 completions(1) 10 wells with core data • Analyses available through commercial labs Eagle Ford Producing Well Eagle Ford Core On/Near Acreage Additional Eagle Ford Core 20 miles Eagle Ford Penetration with Logs (1) WRD 2Q’18 earnings deck WRD data reflects CHK’s analysis based solely on public information. January 2019 Update 16

THE WILDHORSE ROCK ADVANTAGE WELL CONSTRAINED RESERVOIR CHARACTERISTICS Organic-rich calcareous mudstone Eastern Eagle Ford Type Log Gamma ray Resistivity • Outer shelf depositional setting Top Austin Eastern Eagle Ford Reservoir Thin Section (1) • Similar to South Texas Eagle Ford Chalk organic-rich calcareous mudstone 6,000 – 11,000' TVD 100 – 500' gross interval thickness ~4% average TOC 4 – 6% effective porosity WildHorse WildHorse pay CHK minimum pay (log analysis) CHKstimulated rock volume 0.5 mm Over-pressured, up to 0.7 psi/ft Top Buda Core porosity measurement varies between labs Lab Lab A RTC (CHK) Lab A Lab B Area STX EGFD STX EGFD Eastern EGFD Eastern EGFD Avg. Porosity 8.0% 5.0% 9.0% 4.5% (1) CoreLab Eagle Ford Shale Study WRD data reflects CHK’s analysis based solely on public information. January 2019 Update 17

WildHorse acreage THE WILDHORSE LOCATION ADVANTAGE A’ POSITIONED IN THE CORE OF THE PLAY Controlling the sweet spot • Optimal thickness, organic content, maturity and clay content A 20 miles Gross thickness c.i. = 100' Eastern Eagle Ford Regional Stratigraphic Cross-Section Shale Gross Thickness A A’ Gamma ray Resistivity 100' Austin Chalk Eagle Ford Lower TOC Thin Highest-quality rock Higher clay Buda WildHorse Acreage WRD data reflects CHK’s analysis based solely on public information. January 2019 Update 18

THE WILDHORSE RESERVOIR ADVANTAGE SIGNIFICANT OIL WINDOW EXPOSURE Overlying Austin Chalk GOR aligns with Eagle Ford maturity trends Validated with Eagle Ford production data Eastern Eagle Ford Maturity and Austin Chalk GOR (1) Interpreted Eastern Eagle Ford Fluid Windows WildHorseWildHorse acreage acreage WildHorse acreage Austin Chalk 6-month GOR <2,000 scf/bbl 2,001 – 3,300 scf/bbl 3,301 – 50,000 scf/bbl Black Oil 50,001 – 100,000 scf/bbl >100,001 scf/bbl Volatile Oil EGFD Maturity Condensate to Wet Gas c.i. = 0.1%Ro (1) Data from IHS Markit WRD data reflects CHK’s analysis based solely on public information. January 2019 Update 19

SUBSURFACE CONFIDENCE, REDUCING UNCERTAINTY History of Eastern Eagle Ford Activity Extensive knowledge Deep regional knowledge of Eastern Eagle Ford Well defined, low-risk subsurface elements Production aligns with mapped subsurface properties Oil window well constrained by existing production and maturity trends Attacking uncertainties WildHorse Leasehold Core analysis CHK Leasehold CHK Drilled Wells • Refine in-place volumes (1992 – 2011) • In-house rock mechanics expertise to optimize PRELIMINARY ASSESSMENT (1) completion design PVT analysis Currently 90% • Fluid properties to optimize spacing and draw down of WRD acreage economic 3D seismic reprocessing with longer laterals • Optimize well planning and geosteering • Build earth and reservoir simulation model ~$35 – $45/bbl Breakeven (1) Pricing of $60/bbl and $2.75/mcf, assumes 10,000' lateral WRD data reflects CHK’s analysis based solely on public information. January 2019 Update 20

CHK’S D&C PERFORMANCE ADVANTAGE Operations Support Center provides 24/7 D&C Cost Per Lateral Foot drilling support • Continuous monitoring of drilling performance (1) ~$1,250 • Improved geosteering = higher percentage in zone ~30% • Drilling parameter optimization (2) ~$1,050 reduction Updated well design (2) • Improved hole cleaning ~$850 • Increased ROP • Eliminate sidetracks Cost/ft($/ft) Improve completions performance by two stages/day • Optimize pump schedule, apply best practices $600 – 900M per well in sand savings • On 10,000' laterals with in-field sand mine Current 6,500' Cost Design Improvements Extended Laterals (1) RS Energy estimate for 2017+ TILs, could contain science and evaluation capital (2) Internal estimates WRD data reflects CHK’s analysis based solely on public information. January 2019 Update 21

PROVEN TRACK RECORD Eagle Ford Appalachia South Appalachia North 21% 41% 36% reduction reduction reduction D&C D&C Cost/ft($/ft) 2014 2015 2016 2017 2014 2015 2016 2017 2014 2015 2016 2017 TIL Year TIL Year TIL Year WildHorse ~30% expected reduction Demonstrated efficiency gains in all operating areas driven by: • CHK’s technical and operational advantage • Longer laterals and enhanced completions D&C Cost/ft ($/ft) D&C Cost/ft 2018E 2019E 2020E 2021E TIL Year WRD data reflects CHK’s analysis based solely on public information. January 2019 Update 22

EXTENDED LATERALS DRIVE VALUE Existing WRD Opportunity to increase NPV with extended laterals Short Laterals • Largely undeveloped, contiguous position Unparalleled extended lateral experience • Proven performance across all assets Estimated 30 – 100% improvement in NPV per foot Potential CHK Extended Laterals CHK Longest Lateral by Asset Eagle Ford Drilling Performance(1) 20,000 $3.0 18,000 WildHorse 16,000 $2.5 Chesapeake 15,000 14,000 $2.0 12,000 10,00010,000 $1.5 4,000' longer 8,500' 8,000 than peer group Lateral Length (ft.) LengthLateral $1.0 6,000 5,000 4,000 $0.5 2,000 Mean ($mm)Cost,TotalDrilling 00 $0.0 EAGLEEagle FORD GULFGulf COAST APPALACHIAApp MID-CONTINENTMid-Con APPALACHIAApp POWDERPowder RIVER WildhorseWildHorse Average SOUTH NORTH 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 Ford Coast South North River Basin Lateral Length (ft.) (1) RS Energy – Peers include COP, CRZO, DVN, ECA, Enervest, EOG, EPE, EQNR, Lewis, MRO, MUR, NBL, SM, SN, WRD; Represents TILs from 2017 to present, size by number of wells. WRD data reflects CHK’s analysis based solely on public information. January 2019 Update 23

SUBOPTIMAL SPACING DEGRADES 2018 WILDHORSE WELL PERFORMANCE WRD TIL Composition Nearly half of 2018 WRD TILs are 100% 90% Austin Chalk or downspaced Eagle Ford 80% 70% • Versus ~20% in 2017 60% 50% 40% 2018 WRD Eagle Ford performance 30% 20% continues to deliver at 750'+ spacing 10% 0% 2017 2018 Austin Chalk Downspaced Eagle Ford 750'+ Eagle Ford WRD Oil IP90 Performance(1) WRD Oil IP90 Performance(1) (All Wells) (excludes Austin Chalk and Downspacing) 60 60 Completion Degradation 50 Evolution 50 40 40 30 30 No 20 20 Oil IP90 (mbo)IP90 Oil Oil IP90 (mbo)IP90 Oil Degradation 10 10 0 0 TIL Year TIL Year (1) RS Energy (Oil IP90) WRD data reflects CHK’s analysis based solely on public information. January 2019 Update 24

OPTIMIZING WELL SPACING CHK model spacing assumption currently Well Spacing Comparison(1) 1,000' and 10,000' lateral length 180 • 750' spacing probable over most fluid windows • 500' spacing potential with additional evaluation 160 Improved wellbore management 140 • Geosteering in-zone and in-plane 120 Burleson County Example 100 375' Spacing 80 Cumulative Cumulative Oil (mbo) 60 40 20 0 Unbounded 0 5 10 15 750' Spacing Producing Months 375' Spacing 750' Spacing Unbounded (1) RS Energy (production data) WRD data reflects CHK’s analysis based solely on public information. January 2019 Update 25

REDUCING DOWNTIME, IMPROVING BASE PRODUCTION Opportunity to reduce downtime downtime reduction • Operate by intention ~35% since 2015 in CHK STX Eagle Ford • WellTender mobile app Improved artificial lift designs reduce base production decline rates • Leverage expertise from 2,000+ Eagle Ford wells across all fluid windows WRD Downtime ~5.5% ~5.0% ~3.5% Downtime (%) 2017 2018 CHK Projected Downtime January 2019 Update 26

CHESAPEAKE’S VALUE OPPORTUNITY Technical and Operational Excellence Improved Capital NAV Drives Value Recovery Efficiency Impact Drilling and Completions Optimization • Reduced costs through improved performance and execution Extended Laterals • Develop resource with fewer wells • Substantial reduction in cost per foot Base Management • Reducing downtime • Artificial lift design improvements Subsurface Optimization • Maximize NPV per acre with improved well spacing Future Opportunity • Austin Chalk, IOR and optimized development WRD data reflects CHK’s analysis based solely on public information. January 2019 Update 27

CHK’S CURRENT WRD EAGLE FORD ASSUMPTIONS CHK’s WRD Eagle Ford Model Assumptions CHK’s WRD Eagle Ford Type Curve(2) 1,200 Avg. Lateral Length ~10,000' Locations 1,000 – 1,400 1,000 WI / NRI ~84 / 66% 800 EUR 600 – 700 mboe 600 Well Costs $7.5 – $8.5mm 400 NPV per well(1) $5 – $7mm Avg. Daily Rate (boe/d) DailyAvg. 200 Base spacing assumption 1,000' at 10,000' 0 lateral length 0 10 20 30 40 • 750' spacing probable over most fluid windows Producing Months • 500' spacing potential with additional understanding Additional upside in Austin Chalk: 150 – 200 locations Production Mix(3) • Condensate play in Washington County and oil matrix play Natural in various areas of acreage 85% 9% 6% Gas Line of sight on improved economics and well performance Oil NGL • 30% expected reduction in well cost per lateral foot • Increased % in-zone with improved geosteering $1.2B of NPV on PDP to be optimized ~1,200 – 1,600+ • Downtime management • Production optimization Estimated future locations (1) Strip pricing as of 10/25/2018 (2) Type curve represents five-year drilling plan (3) Forecasted production mix for new wells over the next five years WRD data reflects CHK’s analysis based solely on public information. January 2019 Update 28

PREMIER DIVERSIFIED INDEPENDENT WITH SIGNIFICANT HIGH-MARGIN OIL-GROWTH RUNWAY Targeting 80%+ of future drilling and completion activity focused on high-margin oil-growth assets High-margin Oil-growth Assets(1) Powder River Basin ~253,000 Acres 29 mboe/d CHK Eagle Ford ~235,000 Acres 100 mboe/d WRD Eagle Ford ~420,000 Acres 47 mboe/d(2) Cash-generating Gas Assets(1) Gulf Coast ~339,000 Acres 128 mboe/d Appalachia North ~547,000 Acres 135 mboe/d Growth Optionality(1) Mid-Continent ~775,000 Acres 25 mboe/d WildHorse Addition Exploration/Other ~1,521,000 Acres N/A Premier high-margin oil-growth engine (1) Unless otherwise noted, operational statistics are as of 9/30/2018 for acreage totals and total production as of 3Q’18. Acreage and production volumes are net to CHK. (2) Actual production for 2Q’18 WRD data reflects CHK’s analysis based solely on public information. January 2019 Update 29

POWDER RIVER BASIN OIL-GROWTH ENGINE ClickProduction to edit Ramp takeaway Ahead of Schedule ClickTurner to Leads edit thetakeaway Way ~2.6 bboe ClickStacked to Future, edit takeaway Hotspot Advantage Gross resource size ~1.7 bboe net Production Mix (1) 41% 17% 42% Oil NGL Natural Gas (1) Represents average for 3Q’18 January 2019 Update 30

ACCELERATING THE TURNER Delineated BB 1 18H Turner Producing 2,725 Max boe/d Planned TIL 2018 PRB exit rate of 38.5 mboe/d (86% oil) SFU 19 23H Planned 2019 Well 1,479 Max boe/d Turner Exceptional productivity (84% oil) High GOR • 38 TILs to date • Proven, repeatable results • ~60% of Turner acreage delineated • Currently running five rigs WYOMING 36 1H 3,133 Max boe/d (46% oil) CHK Turner vs. Peers NWFU 26 20H RANKIN 5 1H 500,000 CHK COMBS 13 20H Peers 1,900 Max boe/d 2,886 Max boe/d 450,000 1,987 Max boe/d (76% oil) (51% oil) Top Quartile (21% oil) 400,000 350,000 PRB TIL Schedule 300,000 25 21 250,000 20 19 18 200,000 15 14 14 Cumulative Boe Cumulative 150,000 100,000 10 50,000 5 0 0 50 100 150 200 250 300 0 4Q'18A 1Q'19E 2Q'19E 3Q'19E 4Q'19E Days January 2019 Update 31

TURNER SPACING TEST UPDATE Delineated Turner Producing Field test yielding positive initial results Planned TIL Planned 2019 Well through 210 days Turner High GOR Optimal spacing drives maximum field development value Two additional tests underway Spacing Performance Unbounded Downspaced 50 2,300ꞌ 2,300ꞌ 40 30 20 Unbounded 10 1,980ꞌ 1,980ꞌ 0 0 30 60 90 120 150 180 210 Gross Gross Cumulative Production (boe/lateral ft.) Producing Days January 2019 Update 32

POWDER RIVER BASIN PREMIER GROWTH OPPORTUNITY Progress to date • Moved to development phase of the Turner • More than 5,000' of oil-rich, stacked pay opportunities • Continue to appraise new formations 2018 2019 2020+ • Turner spacing tests • Turner development • Appraisal in the Teapot, Parkman, • Successful Turner • Additional Turner Sussex, Frontier step-out tests step-out tests and Mowry • Develop the • Parkman and • Upside spacing tests Turner core Niobrara appraisal (~60% delineated) • Continued Turner development January 2019 Update 33

SOUTH TEXAS FOUNDATIONAL ASSET Consistent High-Margin EBITDA Delivery ~$560 Million FCF(1) in 2018 1.3 bboe Multi-Zone Growth Potential Net resource size(2) Production Mix (3) 58% 22% 20% Oil NGL Natural Gas (1) Free cash flow defined as net revenue less all operating costs and capital expenditures. Excludes corporate overhead costs such as capitalized interest and capitalized G&A expenses. (2) Includes IOR potential (3) Represents average for 3Q’18 January 2019 Update 34

OPTIMIZING SOUTH TEXAS DELIVERING MORE WITH LESS Expected to generate ~$560 million Range of Capex Estimates ($/Lateral Foot)(3) (1) free cash flow in 2018 $1,100 $1.10 RSEG WoodMac $1,000 $1.00 Over 15% improvement in drilling $0.90$900 ft/day reducing cycle time and cost $0.80$800 $0.70$700 Increased lateral length, spacing and Foot $ D&C/Lateral $0.60$600 completions design results in: $0.50$500 (2) CHK Peer Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer Peer 10 • 45% increase in initial well performance Peer 11 • Stabilization of base production CHK Outpaces Basin Peers performance 16,000 in First Six Month Oil Delivery(4) 14,000 Eagle Ford TIL Schedule 53 12,000 46 10,000 8,000 34 30 28 6,000 4,000 First Six Month Oil (bbl/1,000') Oil Month Six First 2,000 0 2014 2015 2016 2017 2018 Peer 1 CHK Peer 2 Peer 3 4Q'18A 1Q'19E 2Q'19E 3Q'19E 4Q'19E (1) Free cash flow defined as net revenue less all operating costs and capital expenditures. Excludes corporate overhead costs such as capitalized interest and capitalized G&A expenses. (2) Cumulative production to date of optimized Blakeway development program vs. historic development of the area at 330ꞌ spacing (3) Peer and CHK data pulled from RS Energy Group from wells turned in line in 2017 – 2018 near CHK’s position. Peers include: Carrizo, EOG, EP Energy, Lewis, Marathon, Murphy, Noble, Sanchez, Silverbow, SM Energy, Venado. (4) Peer and CHK data pulled from RS Energy Group from wells turned in line in 2017 – 2018 near CHK’s position. Peers include: Carrizo, EP Energy, Sanchez. January 2019 Update 35

IMPROVED OIL RECOVERY PUSHING THE ENVELOPE Oil-window opportunity • 1.3 – 1.7x potential improvement in oil recovery Proven technology • Multiple in-basin pilots and up-scaled projects Expected benefits • Adds value to existing well set • Lower capital cost per barrel Potential CHK IOR Project Path forward Industry IOR Project • 65-well project underway Oil CHK Phase I Volatile Oil • First injection: June 2019 Condensate/Wet Gas Dry Gas Evaluating expansion west in 2020 January 2019 Update 36

FAITH RANCH PROJECT BATCH DEVELOPMENT YIELDS CONTINUED SUCCESS Faith Ranch ~21,300 net acres Faith Ranch Phase 1 2018 Development • 283 producing wells Phase 2 (1) ~$33/bbl breakeven 16 Wells • Faith – Toro ~80% ROR(2) Faith-San Pedro • Faith – San Pedro ~45% ROR(2) 29 Wells Faith Production Profile Faith-Toro 35,000 30,000 Base 2018 Wedge 25,000 20,000 15,000 Gross Oil (bbl/d) Oil Gross 45 TILs 10,000 in late 3Q, 4Q 5,000 0 31-Jan-18Jan’18 31-Jul-18Jul’18 31-Jan-19Jan’19E 31-Jul-19Jul’19E (1) Assumes $2.75/mcf gas price (2) Assumes $2.75/mcf and $60/bbl January 2019 Update 37

APPALACHIA NORTH LEADING THE INDUSTRY ~$350 Million FCF(1) in 2018 Premier Position 12.6 tcf Expanding Inventory Net resource size Production Mix (1) 100% Natural Gas (1) Free cash flow defined as net revenue less all operating costs and capital expenditures. Excludes corporate overhead costs such as capitalized interest and capitalized G&A expenses. (2) Represents average for 3Q‘18 January 2019 Update 38

LEADING THE COMPETITION IP30 Expected to generate ~$350 million 70 (Scaled to 10,000ꞌ LL)(2) free cash flow(1) in 2018 60 Median 50 Range Production outpacing competitors 40 • 25 TILs in 4Q 30 Technology changing the play 20 10 • Longer laterals, enhanced completions (mmcf/d)Rate Gas Gross IP30: 0 14 CHK Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 12 10 Six-Month Gross Cumulative 8 (Scaled to 10,000ꞌ LL)(2) 8 6 6 4 4 2 2 Average Gross Cumulative Production (bcf) Production Cumulative Gross Average 0 NA NA 0 5 10 15 20 25 30 35 Production Gross (bcf) Cumulative 0 Normalized Producing Months ChesapeakeCHK Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 McGavin 6H (10,400ꞌ LL) CHK Historical (6,100ꞌ LL) Peers (5,000ꞌ – 8,500ꞌ LL) DPH 3H (6,100ꞌ LL) Wood 3H (12,500ꞌ LL) (1) Free cash flow defined as net revenue less all operating costs and capital expenditures. Excludes corporate overhead costs such as capitalized interest and capitalized G&A expenses (2) Peer and CHK data pulled from IHS for wells turned in line in 2017 and 1Q’18. Peers include: Cabot, Chief, EQT, Repsol, Seneca and SWN. January 2019 Update 39

RIGHT-SIZED SPACING & LONGER LATERALS DELIVER RECORD-SETTING PERFORMANCE Two new 24-hour peak rate records • Joeguswa 4HC: 62.6 mmcf/d 2019 Planned IPs • Joeguswa 5HC: 73.4 mmcf/d • Previous record – McGavin 6H: 61.5 mmcf/d 28% <20 mmcf/d 42% Optimized completion design 20 – 40 mmcf/d • Joeguswa: 1,600 pounds per foot >40 mmcf/d 30% • McGavin: 3,000 pounds per foot • ~20% reduction in completion capital per lateral foot Looking forward • Targeting longer laterals and optimized completion designs to improve capital efficiency • Undeveloped acreage position provides ability to properly space future locations January 2019 Update 40

GULF COAST CONSISTENT PERFORMANCE, SIGNIFICANT RUNNING ROOM Completion and Drilling Excellence Redefines Play Expansive Inventory 15 tcf Access to Premium Markets Net resource size Production Mix (1) 100% Natural Gas (1) Represents average for 3Q’18 January 2019 Update 41

HAYNESVILLE FIRST MOVER, INNOVATION LEADER First 15k lateral – GEPH 1HC Existing Planned 15k Well • 7.1 bcf in 230 days 15k Fairway Substantial portfolio of extended reach laterals(1) Driving capital efficiency by increasing lateral length • Currently drilling two additional 15k laterals GEPH 1HC • Potential for five 15k laterals in 2019 Operational advances continue to unlock value GEPH 1HC 60 7.0 10k Fairway 50 6.0 5.0 40 4.0 30 3.0 20 2.0 10 Daily Production Daily Gross Production (mmcf/d) Production Gross Daily 1.0 Cumulative Production (bcf) Production Gross Cumulative 0 0.0 0 20 40 60 80 100 120 140 160 180 Days (1) Includes laterals of 10,000ꞌ or greater in lateral length January 2019 Update 42

MID-CONTINENT REINVENTING A LEGACY ASSET Well-Positioned Acreage Appraising Liquid-Rich Opportunities ~550 mmboe Efficient Oil Volumes Net resource size Production Mix(1) 36% 16% 48% Oil NGL Natural Gas (1) Represents average for 3Q’18 January 2019 Update 43

REINVENTING THE MID-CONTINENT ~775,000 (96% HBP) of Current Rig Location Producing Well multi-zone stacked potential Wedge Planned TIL Oswego Targeting liquid-rich opportunities • Appraising six formations in 2018 Reopening mature plays through modern technology Woods Major Blaine Kingfisher Canadian County County County County County Penn Shales Osage Oil Chester Woodford Meramec Silt Hunton Meramec Lime January 2019 Update August 2018 Update 44

APPENDIX January 2019 Update 45

LEADING PERFORMANCE G&A per boe Lease Operating Expenses (LOE) per boe(1) $7.00 $10.00 $6.00 $8.00 $5.00 $6.00 $4.00 $3.00 $4.00 $2.00 $2.00 $1.00 $0.00 $0.00 Peer 1 Peer 2 CHK Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Peer 1 Peer 2 Peer 3 CHK Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Return on Capital Employed (ROCE) F&D per boe 25.0% $20.00 20.0% $15.00 15.0% $10.00 10.0% $5.00 5.0% 0.0% $0.00 Peer 1 CHK Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Peer 1 Peer 2 Peer 3 CHK Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 -5.0% Peer 1 Peer 2 Peer 3 CHK Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Data pulled from Capital IQ and recent company reported filings and represent last twelve months of performance from 9/30/18; Peer group includes: Apache, Anadarko, Antero Resources, Cimarex Energy, Devon Energy, Encana, EQT Corporation, Newfield Exploration, Noble Energy, Pioneer Natural Resources, Range Resources; F&D defined as total D&C capital over total reserve extensions. (1) LOE is a component of oil, natural gas and NGL production expenses in CHK’s statements of operations January 2019 Update 46

HEDGING POSITION AS OF 12/31/18(1) Commodity Year Trade Type Volume Price NYMEX Henry Hub 2019 Swaps 447 bcf $2.87 / mcf NYMEX Henry Hub 2019 Collars 55 bcf $2.75 x $3.02 / mcf NYMEX Henry Hub 2019 Three-Ways 88 bcf $2.50 x $2.80 x $3.10 / mcf NYMEX Henry Hub 2020 Swaps 176 bcf $2.75 / mcf NYMEX WTI 2019 Swaps 10.02 mmbbls $58.97 / bbl NYMEX WTI 2019 Collars 5.84 mmbbls $58.00 x $67.75 / bbl NYMEX WTI 2020 Swaps 2.20 mmbbls $68.14 / bbl NYMEX WTI 2020 Collars 1.83 mmbbls $65.00 x $83.25 / bbl (1) As of 12/31/18, does not reflect December 2018 oil/NGL or January 2019 gas settlements Includes 25 bcf of 2020 $2.75 swaptions with December 2019 expiry January 2019 Update 47

BASIS HEDGES AS OF 12/31/18 CIG 2019: 11 bcf @ ($0.89) / mcf Argus LLS vs Argus WTI 2019: 4.0 mmbbls @ $6.20 / bbl HSC 2019: 22.5 bcf @ $0.03 / mcf Argus Houston vs Argus WTI 2019: 2.9 mmbbls @ $5.75 / bbl January 2019 Update 48

$mm $ millions 2018OUTLOOK DEBTMATURITY PROFILE Senior Senior Notes $7.7 billion $1,000 $1,200 $1,400 $1,600 $1,800 $200 $400 $600 $800 $0 $380 2019 January2019 Update (1) As 12/31/2018 of (1) $665 2020 WACD 6.7% $814 2021 Revolving Credit Facility million $419 $451 2022 $338 $419 2023 $850 2024 $1,300 2025 Convertibles Unsecured Revolving Credit Facility $1,250 $400 2026 $1,300 2027 49

CORPORATE INFORMATION Headquarters Publicly Traded Securities Cusip Ticker 6100 N. Western Avenue 3mL + 3.25% Senior Notes due 2019 #165167CM7 CHK19 Oklahoma City, OK 73118 6.625% Senior Notes due 2020 #165167CF2 CHK20A WEBSITE: www.chk.com #165167BU0 6.875% Senior Notes due 2020 #165167BT3 CHK20 #U16450AQ8 Corporate Contacts 6.125% Senior Notes Due 2021 #165167CG0 CHK21 BRAD SYLVESTER, CFA 5.375% Senior Notes Due 2021 #165167CK1 CHK21A Vice President – Investor Relations 4.875% Senior Notes Due 2022 #165167CN5 CHK22 and Communications 5.75% Senior Notes Due 2023 #165167CL9 CHK23 7.00% Senior Notes due 2024 #165167DA2 CHK24 DOMENIC J. DELL’OSSO, JR. #165167CT2 Executive Vice President and 8.00% Senior Notes due 2025 #165167CU9 N/A Chief Financial Officer #U16450AU9 7.50% Senior Notes due 2026 #165167DB0 CHK26 Investor Relations department #165167CV7 8.00% Senior Notes due 2027 N/A can be reached at ir@chk.com #U16450AV7 5.50% Contingent Convertible Senior Notes due 2026 #165167CY1 N/A 2.25% Contingent Convertible Senior Notes due 2038 #165167CB1 CHK38 4.5% Cumulative Convertible Preferred Stock #165167842 CHK PrD #165167834 5.0% Cumulative Convertible Preferred Stock (Series 2005B) N/A #165167826 #U16450204 5.75% Cumulative Convertible Preferred Stock #165167776 N/A #165167768 #U16450113 5.75% Cumulative Convertible Preferred Stock (Series A) #165167784 N/A #165167750 Chesapeake Common Stock #165167107 CHK As of November 30, 2018. January 2019 Update 50