Exhibit 99.1
N E W S   R E L E A S E

FOR IMMEDIATE RELEASE

AUGUST 6, 2019

CHESAPEAKE ENERGY CORPORATION REPORTS 2019 SECOND QUARTER FINANCIAL AND OPERATIONAL RESULTS

OKLAHOMA CITY, August 6, 2019 – Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operational results for the 2019 second quarter. Highlights include:

• Increasing Oil Production, Enhancing Capital Efficiency, Growing Margins and Progressing Toward Sustainable Free Cash Flow

◦ Delivered record oil production of 122,000 barrels (bbls) of oil per day, year-over-year growth of 36%, or 10% adjusted for asset purchases and sales; record oil mix of 25%

◦ Operating cost reductions further enhance margins

▪ Reduced cash operating expenses consisting of production, gathering, processing and transportation (GP&T) and general and administrative expenses by $57 million, or approximately $0.40 per barrel of oil equivalent (boe), when compared to the prior year quarter

▪ Highest second quarter operating margin per boe since 2014

◦ Capital efficiency improvements redefine economics of Brazos Valley assets

▪ Projected 2019 total savings of $250 to $280 million; eliminated approximately $600,000 in costs per well; recognized up to $2 million in savings on certain wells

▪ Accelerating cycle times, with approximately 45 oil wells planned to be placed to sales in the second half of 2019 compared to 28 wells in the first half

▪ Expanded Eagle Ford higher-margin black oil window by approximately 230 locations

• Maximizing Value of Diverse Portfolio Through Returns-Focused Capital Allocation

◦ Maintaining oil growth trajectory on flat capital

▪ Oil production poised to increase in the second half of 2019 as ~170 oil wells expected to be placed to sales, an increase of approximately 50% over the first half of 2019

▪ Projected to grow oil production by double-digits in 2020 on approximately flat year-over-year capex, yielding approximately flat adjusted EBITDAX at current NYMEX strip pricing and current hedge position    

▪ Reducing capital allocation to gas assets, forecasting double-digit gas decline in 2020

• Prudently Managing Maturities to Maintain Future Liquidity

◦ Exchanged $884 million senior notes maturing 2020 through 2021 into new senior notes maturing 2026

◦ Reduced maturities prior to 2022 to approximately $600 million

◦$1.6 billion of liquidity available under the Chesapeake parent credit facility

◦ Approximately 85% of 2019 forecasted oil, natural gas and NGL revenue hedged at prices significantly above the current strip

Doug Lawler, Chesapeake’s President and Chief Executive Officer, commented, "Driven by the integration of our Brazos Valley asset, steady growth from the PRB and improved base production performance from South Texas and the Mid-Continent, Chesapeake produced approximately 122,000 barrels of oil per day, the highest quarterly oil production in the company’s history, and oil production comprised approximately 25% of our total production mix, also a company record. As highlighted above, we have a significant oil

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

growth runway in 2019 and accordingly, we are raising the mid-point of our full-year oil production guidance by approximately 250,000 barrels. In addition, our focus on cash cost leadership has resulted in reducing our full-year guidance for GP&T and production expenses. We believe the trajectory of our oil volume growth and related higher-margin cash flow from those volumes will move higher as we enter 2020.

"As we formulate our initial 2020 plans, we expect to allocate more capital to oil growth areas, with less capital going toward our gas assets. As a result, with an approximately flat capital program to 2019, we project our 2020 oil volumes will show double-digit percentage growth over 2019, while our gas volumes will show a double-digit percentage decline, yet our projected adjusted EBITDAX remains approximately the same at 2019 levels using today's lower NYMEX strip pricing and current hedge position. We look forward to driving further value from our scale, diverse portfolio and capital discipline in 2020 and beyond."

2019 Second Quarter Results

For the 2019 second quarter, Chesapeake reported net income of $98 million and net income available to common stockholders of $75 million, or $0.05 per diluted share. Adjusting for items typically excluded by securities analysts, the 2019 second quarter adjusted net loss attributable to Chesapeake was $158 million or $0.10 per share while adjusted EBITDAX was $612 million. Reconciliations of financial measures calculated in accordance with GAAP to non-GAAP measures are provided on pages 13-17 of this release.

Average daily production for the 2019 second quarter was approximately 496,000 boe and consisted of approximately 122,000 bbls of oil, 2.034 billion cubic feet (bcf) of natural gas and 35,000 bbls of natural gas liquids (NGL). Average daily production for the 2018 second quarter was approximately 530,000 boe and consisted of approximately 90,000 bbls of oil, 2.311 bcf of natural gas and 55,000 bbls of NGL. Oil production represented approximately 25% of the company's 2019 second quarter aggregate production compared to 17% in the 2018 second quarter.

Despite lower average prices for our oil, natural gas and NGL sold, Chesapeake's cash margins increased significantly in the 2019 second quarter compared to the 2018 second quarter, primarily due to a higher oil production mix and a decrease in GP&T and general and administrative expenses. Chesapeake reduced its cash operating expenses on an absolute basis by $57 million, or approximately $0.40 per boe.

Capital Spending Overview

Chesapeake invested total capital expenditures of approximately $559 million during the 2019 second quarter, including capitalized interest of $6 million, compared to approximately $530 million in the 2018 second quarter. The increase in capital expenditures in the 2019 second quarter was largely attributable to an increase in net wells spud, completed and connected. See tables below for a summary of activity and expenditures.

	Three Months Ended June 30,
	2019		2018
	Net	Gross	Net	Gross
Operated activity comparison
Average rig count	13	18	12	17
Wells spud	67	92	56	79
Wells completed	70	92	56	85
Wells connected	65	85	63	96

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	Three Months Ended June 30,
	2019		2018
Type of cost ($ in millions)
Drilling and completion capital expenditures	$	526	$	513
Leasehold and additions to other PP&E	27		12
Subtotal capital expenditures	$	553	$	525
Capitalized interest	6		5
Total capital expenditures	$	559	$	530

Balance Sheet and Liquidity

As of June 30, 2019, Chesapeake’s principal amount of debt outstanding inclusive of Brazos Valley debt was approximately $10.161 billion, compared to $8.168 billion as of December 31, 2018. The increase in debt outstanding was largely a result of $1.375 billion in debt assumed by Chesapeake and the $353 million of net cash consideration paid as part of the WildHorse acquisition on February 1, 2019. As of June 30, 2019, the company had borrowed $1.372 billion under the $3.0 billion Chesapeake credit facility, utilized approximately $54 million for various letters of credit and had additional borrowing capacity of approximately $1.574 billion. Under the $1.3 billion Brazos Valley credit facility, the company had borrowed $686 million and had additional borrowing capacity of approximately $614 million. The borrowing bases of both credit facilities were re-affirmed in May 2019 with the next re-determination dates scheduled for the 2019 fourth quarter.

During the 2019 second quarter, Chesapeake exchanged approximately $919 million of new 8.0% Senior Notes due 2026 for approximately $884 million aggregate principal amount of its Senior Notes due 2020 and 2021 and repaid approximately $380 million of its Floating Rate Senior Notes due 2019 at maturity. As a result, Chesapeake currently has remaining maturities in 2020 and 2021 of $301 million and $294 million, respectively.

Chesapeake has protected a significant amount of its remaining 2019 revenue through hedging. As of July 31, 2019, including July and August derivative contracts that have settled, approximately 85% of the company's remaining 2019 forecasted oil, natural gas and NGL production revenue was hedged, including approximately 79% and 78% of its remaining 2019 forecasted oil and natural gas production at average prices of $59.38 per bbl and $2.83 per thousand cubic feet (mcf), respectively. Additionally, Chesapeake has basis protection on approximately 4.1 million barrels (mmbbls) of its remaining projected 2019 Eagle Ford oil production at a premium to WTI of approximately $5.85 per bbl.

In 2020, Chesapeake currently has downside protection on approximately 14.8 mmbbls of its projected oil production at an average price of $59.93 per bbl and on approximately 264.7 bcf of its projected gas production at an average price of $2.76 per mcf.

Operations Update

Chesapeake's average daily production for the 2019 second quarter was approximately 496,000 boe compared to approximately 530,000 boe in the 2018 second quarter. The following tables show average daily production and average sales prices received (excluding gains/losses on derivatives) by the company's operating areas for the 2019 and 2018 second quarters.

	Three Months Ended June 30, 2019
	Oil		Natural Gas			NGL		Total
	mbbl per day	$/bbl	mmcf per day		$/mcf	mbbl per day	$/bbl	mboe per day	%		$/boe
Marcellus	—	—	929		2.33	—	—	155	31		13.99
Haynesville	—	—	751		2.39	—	—	125	25		14.36
Eagle Ford	58	65.82	152		2.69	19	12.78	102	21		43.89
Brazos Valley	35	63.34	55		1.81	5	9.33	49	10		47.57
Powder River Basin	20	57.05	89		2.26	5	16.30	40	8		35.58
Mid-Continent	9	58.12	59		2.03	6	16.97	25	5		30.53
Retained assets(a)	122	63.09	2,035		2.35	35	13.50	496	100		26.13
Divested assets	—	—	(1	)	4.66	—	—	—	—		—
Total	122	63.04	2,034		2.35	35	13.43	496	100	%	26.12

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	Three Months Ended June 30, 2018
	Oil		Natural Gas		NGL		Total
	mbbl per day	$/bbl	mmcf per day	$/mcf	mbbl per day	$/bbl	mboe per day	%		$/boe
Marcellus	—	—	805	2.31	—	—	134	25		13.85
Haynesville	—	—	829	2.63	—	—	139	26		15.80
Eagle Ford	61	70.52	143	3.22	19	26.58	103	20		50.70
Powder River Basin	8	67.37	57	2.18	4	27.12	22	4		36.78
Mid-Continent	10	66.77	64	2.38	5	24.41	25	5		36.74
Retained assets(a)	79	69.70	1,898	2.52	28	26.29	423	80		26.03
Divested assets	11	63.50	413	2.76	27	25.18	107	20		23.68
Total	90	68.92	2,311	2.56	55	25.74	530	100	%	25.56

(a) Includes assets retained as of June 30, 2019.

Brazos Valley: Driving significant capital efficiencies, business unit expected to be free cash flow positive in 2019

Chesapeake has driven significant changes and improvements through the first six months of its ownership of the Brazos Valley asset, which was acquired on February 1, 2019. Since taking over daily operations, Chesapeake has realized savings of approximately $600,000 per well, with savings of up to $2 million per well on certain individual wells, compared to the previous operator due to better drilling and completion techniques, faster cycle times and lower oilfield service costs.

The company is currently utilizing four rigs in the Brazos Valley area, placed 24 wells on production (four Austin Chalk gas wells and 20 Eagle Ford oil wells) during the 2019 second quarter and expects to place 26 wells, all in the Eagle Ford oil window, on production during the 2019 third quarter. In 2019, the company has already placed 10 wells to sales that have reached maximum 24-hour production rates of more than 900 bbls of oil per day, compared to three wells that reached that level in the same time period in 2018. Of those 10 wells, seven wells have reached maximum 24-hour production rates of more than 1,000 bbls of oil per day. All but one of these wells incorporated Chesapeake's new enhanced flow back techniques. These results, combined with stronger base production, have resulted in production that has exceeded the company's internal expectations since the acquisition.

Additionally, Chesapeake has redefined its understanding of the fluid windows on the acreage, resulting in a larger Eagle Ford oil window than originally thought. The expansion of the black oil window, based on subsurface analytics and validated by production data from wells drilled in the 2019 first quarter, increased the company’s confidence of approximately 230 additional locations in the black oil window. With an expected higher oil cut from these locations, the economics of these wells are projected to be significantly stronger when compared to the company's wells in the volatile oil window or dry gas window areas of the play.

Chesapeake is evaluating options to be a shipper on a crude pipeline that will deliver the company’s Brazos Valley oil volumes into the Houston, Texas market beginning in the 2020 fourth quarter. Chesapeake is also pursuing a new gathering agreement in the area that would reduce the current reliance on trucking oil volumes and improve its cost structure in the region. The company expects to have this new gathering agreement in place for the operating area during the second half of 2019.

Eagle Ford Shale: Stronger base production exceeds internal forecasts

In the company’s Eagle Ford Shale position in South Texas, base production performance has been strong due to adjusted well-spacing and optimized completion designs. Chesapeake’s operated sales volumes were affected by planned third-party processing plant maintenance, which reduced sales volumes for approximately one week in June, yet the business unit was still able to exceed internal forecasts for the quarter due to its stronger base production. Chesapeake is currently utilizing four rigs in the area, which were located on large ranch projects during the 2019 second quarter. As a result, 17 wells were placed

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on production during the 2019 second quarter and the pace will accelerate to 42 wells to be placed on production during the 2019 third quarter as these larger projects are completed.

Powder River Basin: Steadily growing high-margin oil production

In the PRB, where the company moved a sixth rig in April 2019, Chesapeake placed 16 wells on production during the 2019 second quarter and expects to place 26 wells on production during the 2019 third quarter. Development in the Turner formation continues on pace and the field's gas-to-oil ratio is moving lower as more wells are focused on the oil window. Appraisal well results continue to expand field limits, including the company's first "wine rack" test in the western portion of the Turner area in an attempt to better access stacked pays. Chesapeake recently completed the first new Niobrara well in the northern area of the field since 2014 and production testing will take place in August 2019, with two more Niobrara wells planned for later in the year. The company's first Mowry volatile oil window test is also scheduled for later in 2019.

In the 2019 second quarter, Chesapeake connected its first pads into a new oil gathering pipeline system that transports volumes to Guernsey, Wyoming. New and existing pads across the field are being connected to the gathering system weekly, resulting in meaningful GP&T expense savings going forward. As a result, more than 50% of the company's produced PRB oil is now flowing on the gathering system and is expected to grow up to 75% in the second half of the year. Also during the quarter, Chesapeake secured transportation that allows its PRB oil volumes to receive Gulf Coast pricing. Beginning in the 2020 fourth quarter, the company expects to be able to deliver certain oil volumes on a pipeline system, which has the ability to access both markets in Cushing, Oklahoma and Corpus Christi, Texas.

Marcellus Shale: Improving capital efficiency through disciplined capital spending

Chesapeake continues to create significant free cash flow in the Marcellus Shale in northeast Pennsylvania, driven by strong new well performance as a result of refined spacing, longer laterals and optimized completion designs. These capital efficient volumes, coupled with base production strength and access to better realized in-basin pricing, continue to make this a strong free cash flow generator for Chesapeake. The company is currently utilizing two drilling rigs, placed 14 wells on production during the 2019 second quarter and expects to place 12 wells on production during the 2019 third quarter. The company expects to keep its gas-weighted capital spending at prudent levels in 2020, including in its Marcellus operating area. At the current activity level, Chesapeake has approximately 10 years of drilling inventory at a break-even of $1.50 to $1.75/mcf.

Haynesville Shale: Focused on optimizing base production

In the Haynesville Shale in Louisiana, Chesapeake is currently operating one rig, placed nine wells on production during the 2019 second quarter and expects to place five wells on production during the 2019 third quarter. The company currently expects to reduce its Haynesville Shale dry gas area rig count to zero in the near future.

Mid-Continent: Capital allocated to higher-return areas, high-graded program focused on 2020 activity

In the company's Mid-Continent operating area in Oklahoma, Chesapeake placed five wells on production during the 2019 second quarter. The company dropped its only operated rig in April 2019 and expects to place no more wells on production through the end of the year.

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Key Financial and Operational Results

The table below summarizes Chesapeake’s key financial and operational results during the 2019 second quarter as compared to results in prior periods. The three months ended June 30, 2019 include Brazos Valley operations. The three months ended June 30, 2018 do not include Brazos Valley operations.

	Three Months Ended June 30,
	2019		2018
Barrels of oil equivalent production (in mboe)	45,165		48,263
Barrels of oil equivalent production (mboe/d)	496		530
Oil production (in mbbl/d)	122		90
Average realized oil price ($/bbl)(a)	61.44		57.16
Natural gas production (in mmcf/d)	2,034		2,311
Average realized natural gas price ($/mcf)(a)	2.48		2.64
NGL production (in mbbl/d)	35		55
Average realized NGL price ($/bbl)(a)	13.43		24.97
Production expenses ($/boe)	3.68		2.86
Gathering, processing and transportation expenses ($/boe)	6.00		7.04
Oil - ($/bbl)	2.42		3.22
Natural Gas - ($/mcf)	1.23		1.29
NGL - ($/bbl)	5.01		8.46
Production taxes ($/boe)	0.88		0.55
Exploration expenses ($ in millions)	15		20
General and administrative expenses ($/boe)(b)	1.79		1.98
General and administrative expenses (stock-based compensation) (non-cash) ($/boe)	0.20		0.19
Depreciation, depletion, and amortization ($/boe)	12.84		9.74
Interest expense ($/boe)(c)	3.85		3.21
Marketing net margin ($ in millions)(d)	(19	)	(14	)
Net cash provided by operating activities ($ in millions)	397		363
Net cash provided by operating activities ($/boe)	8.79		7.52
Net income (loss) ($ in millions)	98		(249	)
Net income (loss) available to common stockholders ($ in millions)	75		(272	)
Net income (loss) per share available to common stockholders – diluted ($)	0.05		(0.30	)
Adjusted EBITDAX ($ in millions)(e)	612		518
Adjusted EBITDAX ($/boe)	13.55		10.73
Adjusted net loss attributable to Chesapeake ($ in millions)(f)	(158	)	(118	)
Adjusted net loss attributable to Chesapeake per share - diluted ($)(g)	(0.10	)	(0.13	)

(a) Includes the effects of realized gains (losses) from hedging, but excludes the effects of unrealized gains (losses) from hedging.

(b) Excludes expenses associated with stock-based compensation, which are recorded in general and administrative expenses in Chesapeake's Condensed Consolidated Statement of Operations.

(c) Includes the effects of realized (gains) losses from interest rate derivatives, excludes the effects of unrealized (gains) losses from interest rate derivatives and is shown net of amounts capitalized.

(d) Marketing net margin is marketing gross margin of ($24) million and ($19) million for the three months ended June 30, 2019 and 2018, excluding non-cash amortization of $5 million related to the buy down of a transportation agreement.

(e) Defined as net income (loss) before interest expense, income taxes, depreciation, depletion and amortization expense, and exploration expense, as adjusted to remove the effects of certain items detailed on page 17. This is a non-GAAP measure. See reconciliation of cash provided by operating activities to adjusted EBITDAX on page 16.

(f) Defined as net income (loss) attributable to Chesapeake, as adjusted to remove the effects of certain items detailed on page 13. This is a non-GAAP measure. See reconciliations of net income (loss) to adjusted net income (loss) available to Chesapeake on pages 13 - 15.

(g) Our presentation of diluted adjusted net loss attributable to Chesapeake per share excludes 207 million shares for the three months ended June 30, 2019 and 2018, which are considered antidilutive when calculating diluted earnings per share.

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2019 Second Quarter Financial and Operational Results Conference Call Update

The conference call to discuss the company's financial and operational results has been scheduled on Tuesday, August 6 at 9:00 am EDT. The telephone number to access the conference call is 1-888-317-6003 or 1-412-317-6061 for international callers. The passcode for the call is 6482113. The conference call will be webcast and can be found at www.chk.com in the “Investors” section of the company’s website.

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.

This news release and the accompanying outlook include "forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are statements other than statements of historical fact. 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, expected lateral lengths of wells, anticipated timing and number of wells to be placed into production, anticipated timing of the Brazos Valley business unit becoming cash flow positive, expected oil growth trajectory, anticipated timing of execution of new gathering agreement, expected oil volume growth in connection with new oil gathering system and pipeline system, general and administrative expenses, capital expenditures, 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.

Factors that could cause actual results to differ materially from expected results include those described under "Risk Factors” in Item 1A of our annual report on Form 10-K and any updates to those factors set forth in Chesapeake's subsequent quarterly reports on Form 10-Q or current reports on Form 8-K (available at http://www.chk.com/investors/sec-filings). 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 may not be completed in the time frame anticipated or at all. We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this news release, and we undertake no obligation to update any of the information provided in this release or the accompanying Outlook, except as required by applicable law. In addition, this news release contains time-sensitive information that reflects management's best judgment only as of the date of this news release.

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CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS ($ in millions except per share data) (unaudited)
	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018*			2019			2018*
REVENUES AND OTHER:
Oil, natural gas and NGL(a)	$	1,454		$	982		$	2,383		$	2,225
Marketing	916			1,273			2,149			2,519
Total Revenues	2,370			2,255			4,532			4,744
Other	15			16			30			32
Gains on sales of assets	1			18			20			37
Total Revenues and Other	2,386			2,289			4,582			4,813
OPERATING EXPENSES:
Oil, natural gas and NGL production	166			138			298			285
Oil, natural gas and NGL gathering, processing and transportation	271			340			545			696
Production taxes	40			26			74			57
Exploration	15			20			39			101
Marketing	940			1,292			2,170			2,560
General and administrative	89			105			192			192
Restructuring and other termination costs	—			—			—			38
Provision for legal contingencies, net	3			4			3			9
Depreciation, depletion and amortization	580			471			1,099			930
Impairments	1			54			2			64
Other operating (income) expense	3			(1		)	64			(1		)
Total Operating Expenses	2,108			2,449			4,486			4,931
INCOME (LOSS) FROM OPERATIONS	278			(160		)	96			(118		)
OTHER INCOME (EXPENSE):
Interest expense	(175		)	(155		)	(336		)	(317		)
Gains (losses) on investments	(23		)	—			(24		)	139
Other income	18			57			27			56
Total Other Expense	(180		)	(98		)	(333		)	(122		)
INCOME (LOSS) BEFORE INCOME TAXES	98			(258		)	(237		)	(240		)
Income tax benefit	—			(9		)	(314		)	(9		)
NET INCOME (LOSS)	98			(249		)	77			(231		)
Net income attributable to noncontrolling interests	—			—			—			(1		)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	98			(249		)	77			(232		)
Preferred stock dividends	(23		)	(23		)	(46		)	(46		)
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$	75		$	(272	)	$	31		$	(278	)
EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	0.05		$	(0.30	)	$	0.02		$	(0.31	)
Diluted	$	0.05		$	(0.30	)	$	0.02		$	(0.31	)
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic	1,628			909			1,505			908
Diluted	1,628			909			1,505			908

* Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting.

(a) See page 12 for a reconciliation of oil, natural gas and NGL revenue before and after the effect of financial derivatives.

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CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS ($ in millions) (unaudited)
	June 30, 2019		December 31, 2018
Cash and cash equivalents	$	4	$	4
Other current assets	1,380		1,594
Total Current Assets	1,384		1,598
Property and equipment, net	14,845		10,818
Other long-term assets	311		319
Total Assets	$	16,540	$	12,735
Current liabilities	$	2,220	$	2,887
Long-term debt, net	9,701		7,341
Other long-term liabilities	389		374
Total Liabilities	12,310		10,602
Preferred stock	1,671		1,671
Noncontrolling interests	39		41
Common stock and other stockholders’ equity	2,520		421
Total Equity	4,230		2,133
Total Liabilities and Equity	$	16,540	$	12,735

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CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED CASH FLOW DATA ($ in millions) (unaudited)
	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018*			2019			2018*
Beginning cash and cash equivalents	$	8		$	4		$	4		$	5
Net cash provided by operating activities	397			363			853			951
Cash flows from investing activities:
Drilling and completion costs(a)	(555		)	(508		)	(1,070		)	(928		)
Business combination, net	—			—			(353		)	—
Acquisitions of proved and unproved properties	(11		)	(85		)	(17		)	(102		)
Proceeds from divestitures of proved and unproved properties	56			65			82			384
Additions to other property and equipment	(9		)	(2		)	(18		)	(5		)
Proceeds from sales of other property and equipment	3			6			4			74
Proceeds from sales of investments	—			—			—			74
Net cash used in investing activities	(516		)	(524		)	(1,372		)	(503		)
Net cash provided by (used in) financing activities	115			160			519			(450		)
Change in cash and cash equivalents	(4		)	(1		)	—			(2		)
Ending cash and cash equivalents	$	4		$	3		$	4		$	3

* Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting.

(a) Includes capitalized interest of $6 million and $5 million for the three months ended June 30, 2019 and 2018, respectively, and includes capitalized interest of $12 million and $9 million for the six months ended June 30, 2019 and 2018, respectively.

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CHESAPEAKE ENERGY CORPORATION SUPPLEMENTAL DATA – OIL, NATURAL GAS AND NGL PRODUCTION AND SALES PRICES (unaudited)
	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Net Production:
Oil (mmbbl)	11			8			21			16
Natural gas (bcf)	185			210			367			432
NGL (mmbbl)	3			5			7			10
Oil equivalent (mmboe)	45			48			89			98
Average daily production (mboe)	496			530			490			542
Oil, Natural Gas and NGL Sales ($ in millions):
Oil sales	$	700		$	567		$	1,266		$	1,104
Natural gas sales	436			538			1,031			1,244
NGL sales	43			128			112			245
Total oil, natural gas and NGL sales	$	1,179		$	1,233		$	2,409		$	2,593
Financial Derivatives:
Oil derivatives – realized losses(a)	$	(18	)	$	(97	)	$	(8	)	(161		)
Natural gas derivatives – realized gains (losses)(a)	24			17			(12		)	84
NGL derivatives – realized losses(a)	—			(3		)	—			(4		)
Total realized gains (losses) on financial derivatives	$	6		$	(83	)	$	(20	)	$	(81	)
Oil derivatives – unrealized gains (losses)(b)	104			(105		)	(165		)	(127		)
Natural gas derivatives – unrealized gains (losses)(b)	165			(52		)	159			(151		)
NGL derivatives – unrealized losses(b)	—			(11		)	—			(9		)
Total unrealized gains (losses) on financial derivatives	$	269		$	(168	)	$	(6	)	$	(287	)
Total financial derivatives	$	275		$	(251	)	$	(26	)	$	(368	)
Total oil, natural gas and NGL sales	$	1,454		$	982		$	2,383		$	2,225
Average Sales Price (excluding gains (losses) on derivatives):
Oil ($ per bbl)	$	63.04		$	68.92		$	60.59		$	66.76
Natural gas ($ per mcf)	$	2.35		$	2.56		$	2.81		$	2.88
NGL ($ per bbl)	$	13.43		$	25.74		$	16.86		$	25.60
Oil equivalent ($ per boe)	$	26.12		$	25.56		$	27.15		$	26.43
Average Sales Price (excluding unrealized gains (losses) on derivatives):
Oil ($ per bbl)	$	61.44		$	57.16		$	60.23		$	57.03
Natural gas ($ per mcf)	$	2.48		$	2.64		$	2.77		$	3.07
NGL ($ per bbl)	$	13.43		$	24.97		$	16.86		$	25.16
Oil equivalent ($ per boe)	$	26.25		$	23.82		$	26.92		$	25.60

(a) Realized gains (losses) include the following items: (i) settlements and accruals for settlements of undesignated derivatives related to current period production revenues, (ii) prior period settlements for option premiums and for early-terminated derivatives originally scheduled to settle against current period production revenues, and (iii) gains (losses) related to de-designated cash flow hedges originally designated to settle against current period production revenues. Although we no longer designate our derivatives as cash flow hedges for accounting purposes, we believe these definitions are useful to management and investors in determining the effectiveness of our price risk management program.

(b) Unrealized gains (losses) include the change in fair value of open derivatives scheduled to settle against future period production revenues (including current period settlements for option premiums and early terminated derivatives) offset by amounts reclassified as realized gains (losses) during the period. Although we no longer designate our derivatives as cash flow hedges for accounting purposes, we believe these definitions are useful to management and investors in determining the effectiveness of our price risk management program.

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CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS ($ in millions) (unaudited)
	Three Months Ended June 30,
	2019						2018
	$			$/Share			$			$/Share
Net income (loss) available to common stockholders (GAAP)	$	75		$	0.05		$	(272	)	$	(0.30	)
Effect of dilutive securities	—			—			—			—
Diluted earnings (losses) available to common stockholders (GAAP)(a)	$	75		$	0.05		$	(272	)	$	(0.30	)
Adjustments:
Unrealized (gains) losses on oil, natural gas and NGL derivatives	(268		)	(0.16		)	168			0.18
Provision for legal contingencies, net	3			—			4			—
Gains on sales of assets	(1		)	—			(18		)	(0.02		)
Other operating (income) expense	3			—			(1		)	—
Impairments	1			—			54			0.06
Losses on investments	23			0.01			—			—
Other revenue (VPP deferred revenue)	(15		)	(0.01		)	(16		)	(0.02		)
Other	(2		)	—			(60		)	(0.06		)
Income tax benefit(b)	—			—			—			—
Adjusted net loss available to common stockholders(c) (Non-GAAP)	(181		)	(0.11		)	(141		)	(0.16		)
Preferred stock dividends	23			0.01			23			0.03
Earnings allocated to participating securities	—			—			—			—
Total adjusted net loss attributable to Chesapeake(a)(c) (Non-GAAP)	$	(158	)	$	(0.10	)	$	(118	)	$	(0.13	)

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CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS ($ in millions) (unaudited)
	Six Months Ended June 30,
	2019						2018
	$			$/Share			$			$/Share
Net income (loss) available to common stockholders (GAAP)	$	31		$	0.02		$	(278	)	$	(0.31	)
Effect of dilutive securities	—			—			—			—
Diluted earnings (losses) available to common stockholders (GAAP)(a)	$	31		$	0.02		$	(278	)	$	(0.31	)
Adjustments:
Unrealized losses on oil, natural gas and NGL derivatives	13			0.01			287			0.32
Restructuring and other termination costs	—			—			38			0.04
Provision for legal contingencies, net	3			—			9			0.01
Gains on sales of assets	(20		)	(0.01		)	(37		)	(0.04		)
Other operating (income) expense(d)	64			0.04			(1		)	—
Impairments	2			—			64			0.07
(Gains) losses on investments	24			0.02			(139		)	(0.15		)
Other revenue (VPP deferred revenue)	(30		)	(0.02		)	(32		)	(0.04		)
Other	(4		)	—			(59		)	(0.06		)
Income tax benefit(e)	(314		)	(0.21		)	—			—
Adjusted net loss available to common stockholders(c) (Non-GAAP)	(231		)	(0.15		)	(148		)	(0.16		)
Preferred stock dividends	46			0.03			46			0.05
Earnings allocated to participating securities	—			—			—			—
Total adjusted net loss attributable to Chesapeake(a)(c) (Non-GAAP)	$	(185	)	$	(0.12	)	$	(102	)	$	(0.11	)

(a) Our presentation of diluted net earnings (losses) available to common stockholders per share and diluted adjusted net loss per share excludes 207 million shares considered antidilutive for the three months and six months ended June 30, 2019 and 2018. The number of shares used for the non-GAAP calculation was determined in a manner consistent with GAAP.

(b) No income tax effect from the adjustments has been included in determining adjusted net income for the three months ended June 30, 2019 and 2018. Our effective tax rate was 0% due to our valuation allowance position.

(c) Adjusted net loss available to common stockholders and total adjusted net loss attributable to Chesapeake, both in the aggregate and per dilutive share, are not measures of financial performance under GAAP, and should not be considered as an alternative to, or more meaningful than, net income (loss) available to common stockholders or earnings (loss) per share. Adjusted net income (loss) available to common stockholders and adjusted earnings (loss) per share exclude certain items that management believes affect the comparability of operating results. The company believes these adjusted financial measures are a useful adjunct to earnings calculated in accordance with GAAP because:

(i) Management uses adjusted net income (loss) available to common stockholders to evaluate the company's operational trends and performance relative to other oil and natural gas producing companies.

(ii) Adjusted net income (loss) available to common stockholders is more comparable to earnings estimates provided by securities analysts.

(iii) Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items.

Because adjusted net loss available to common stockholders and total adjusted net loss attributable to Chesapeake exclude some, but not all, items that affect net income (loss) available to common stockholders our calculations of adjusted net loss available to common stockholders and total adjusted net loss attributable to Chesapeake may not be comparable to similarly titled measures of other companies.

(d) The six months ended June 30, 2019 includes $26MM in integration and acquisition costs as a result of Chesapeake's merger with WildHorse Resource Development Corporation (WRD). Additionally, most WRD executives and employees were terminated and entitled to severance benefits of approximately $38 million in accordance with certain provisions of existing employment agreements that were triggered by the change in control.

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(e) For the six months ended June 30, 2019, we recorded a net deferred tax liability of $314 million associated with the acquisition of WildHorse Resource Development Corporation. As a result of recording this net deferred tax liability through business combination accounting, we released a corresponding amount of the valuation allowance that we maintain against our net deferred tax asset position. This release resulted in an income tax benefit of $314 million. Further, no income tax expense or benefit is shown for the adjustments being made to arrive at adjusted net income (loss) available to common stockholders as a result of not recording an income tax expense or benefit on current period results due to maintaining a full valuation allowance against our net deferred tax asset position.

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CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF CASH PROVIDED BY OPERATING ACTIVITIES TO ADJUSTED EBITDAX ($ in millions) (unaudited)
	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
CASH PROVIDED BY OPERATING ACTIVITIES (GAAP)	$	397		$	363		$	853		$	951
Adjustments:
Changes in assets and liabilities	44			26			137			(62		)
Other revenue (VPP deferred revenue)	(15		)	(16		)	(30		)	(32		)
Interest expense	175			155			336			317
Exploration	8			15			14			28
Stock-based compensation	(11		)	(9		)	(17		)	(18		)
Restructuring and other termination costs	—			—			—			38
Losses on investments	7			—			6			—
Net income attributable to noncontrolling interest	—			—			—			(1		)
Other items	7			(16		)	(11		)	14
Adjusted EBITDAX (Non-GAAP)(a)	$	612		$	518		$	1,288		$	1,235

(a) Adjusted EBITDAX is not a measure of financial performance under GAAP, and should not be considered as an alternative to, or more meaningful than, cash flow provided by operating activities prepared in accordance with GAAP. Adjusted EBITDAX excludes certain items that management believes affect the comparability of operating results. The company believes this non-GAAP financial measure is a useful adjunct to cash flow provided by operating activities because:

(i) Management uses adjusted EBITDAX to evaluate the company's operational trends and performance relative to other oil and natural gas producing companies.

(ii) Adjusted EBITDAX is more comparable to estimates provided by securities analysts.

(iii) Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items.

Because adjusted EBITDAX excludes some, but not all, items that affect net income (loss), our calculations of adjusted EBITDAX may not be comparable to similarly titled measures of other companies.

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CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF NET INCOME (LOSS) TO ADJUSTED EBITDAX ($ in millions) (unaudited)
	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
NET INCOME (LOSS) (GAAP)	$	98		$	(249	)	$	77		$	(231	)
Adjustments:
Interest expense	175			155			336			317
Income tax benefit	—			(9		)	(314		)	(9		)
Depreciation, depletion and amortization	580			471			1,099			930
Exploration	15			20			39			101
Unrealized (gains) losses on oil, natural gas and NGL derivatives	(268		)	168			13			287
Restructuring and other termination costs	—			—			—			38
Provision for legal contingencies, net	3			4			3			9
Gains on sales of assets	(1		)	(18		)	(20		)	(37		)
Other operating (income) expense	3			(1		)	64			(1		)
Impairments	1			54			2			64
(Gains) losses on investments	23			—			24			(139		)
Net income attributable to noncontrolling interests	—			—			—			(1		)
Other revenue (VPP deferred revenue)	(15		)	(16		)	(30		)	(32		)
Other	(2		)	(61		)	(5		)	(61		)
Adjusted EBITDAX (Non-GAAP)(a)	$	612		$	518		$	1,288		$	1,235

(a) Adjusted EBITDAX is not a measure of financial performance under GAAP, and should not be considered as an alternative to, or more meaningful than, net income (loss) prepared in accordance with GAAP. Adjusted EBITDAX excludes certain items that management believes affect the comparability of operating results. The company believes this non-GAAP financial measure is a useful adjunct to net income (loss) because:

(i) Management uses adjusted EBITDAX to evaluate the company's operational trends and performance relative to other oil and natural gas producing companies.

(ii) Adjusted EBITDAX is more comparable to estimates provided by securities analysts.

(iii) Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items.

Because adjusted EBITDAX excludes some, but not all, items that affect net income (loss), our calculations of adjusted EBITDAX may not be comparable to similarly titled measures of other companies.

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CHESAPEAKE ENERGY CORPORATION

MANAGEMENT’S OUTLOOK AS OF AUGUST 6, 2019

Chesapeake periodically provides guidance on certain factors that affect the company’s future financial performance. New information or changes from the company's May 8, 2019 outlook are italicized bold below.

	Year Ending 12/31/2019
Absolute Production:
Oil - mmbbls	43.0 - 44.5
NGL - mmbbls	13.0 - 15.0
Natural gas - bcf	725 - 750
Total absolute production - mmboe	177 - 184
Absolute daily rate - mboe	484 - 505
Estimated Realized Hedging Effects(a) (based on 7/31/19 strip prices)
Oil - $/bbl	$0.35
Natural gas - $/mcf	$0.14
Estimated Basis to NYMEX Prices:
Oil - $/bbl	$1.95 - $2.15
Natural gas - $/mcf	($0.10) - ($0.20)
NGL - realizations as a % of WTI	25% - 28%
Operating Costs per boe of Projected Production:
Production expense	$3.20 - $3.40
Gathering, processing and transportation expenses	$5.90 - $6.40
Oil - $/bbl	$2.95 - $3.15
Natural Gas - $/mcf	$1.20 - $1.30
Production taxes	$0.80 - $0.90
General and administrative(b)	$1.75 - $1.85
Stock-based compensation (non-cash)	$0.10 - $0.20
Marketing Net Margin and Other ($ in millions)(c)	($15) - ($35)
Adjusted EBITDAX, based on 7/31/19 strip prices ($ in millions)(d)	$2,450 - $2,650
Depreciation, depletion and amortization expense	$12.50 - $13.50
Interest expense	$3.80 - $4.00
Exploration expense ($ in millions, cash only)	$35 - $45
Book Tax Rate	0%
Capital Expenditures ($ in millions)(e)	$2,085 - $2,285
Capitalized Interest ($ in millions)	$20
Total Capital Expenditures ($ in millions)	$2,105 - $2,305

(a) Includes expected settlements for oil, natural gas and NGL derivatives adjusted for option premiums. For derivatives closed early, settlements are reflected in the period of original contract expiration.

(b) Excludes expenses associated with stock-based compensation, which are recorded in general and administrative expenses in Chesapeake's Condensed Consolidated Statement of Operations.

(c) Excludes non-cash amortization of approximately $8.7 million related to the buydown of a transportation agreement.

(d) Adjusted EBITDAX is a non-GAAP measure used by management to evaluate the company's operational trends and performance relative to other oil and natural gas producing companies. Adjusted EBITDAX excludes certain items that management believes affect the comparability of operating results. The most directly comparable GAAP measure is net income but, it is not possible, without unreasonable efforts, to identify the amount or significance of events or transactions that may be included in future GAAP net income but that management does not believe to be representative of underlying business performance. The company further believes that providing estimates of the amounts that would be required to reconcile forecasted adjusted EBITDAX to forecasted GAAP net income would imply a degree of precision that may be confusing or misleading to investors. Items excluded from net income to arrive at adjusted EBITDAX include interest expense, income taxes, and depreciation, depletion and amortization expense, exploration expense as well as one-time items or items whose timing or amount cannot be reasonably estimated.

17

(e) Includes capital expenditures for drilling and completion, leasehold, developmental geological and geophysical costs, rig termination payments and other property, plant and equipment. Excludes any additional proved property acquisitions and expenditures classified as exploration expense.

18

Oil, Natural Gas and Natural Gas Liquids Hedging Activities

Chesapeake enters into oil, natural gas and NGL derivative transactions in order to mitigate a portion of its exposure to adverse changes in market prices. Please see the quarterly reports on Form 10-Q and annual reports on Form 10-K filed by Chesapeake with the SEC for detailed information about derivative instruments the company uses, its quarter-end derivative positions and accounting for oil, natural gas and natural gas liquids derivatives.

As of July 31, 2019, including July and August derivative contracts that have settled, approximately 85% of the company's 2019 forecasted oil, natural gas and NGL production revenue was hedged, including approximately 79% and 78% of its remaining 2019 forecasted oil and natural gas production at average prices of $59.38 per bbl and $2.83 per mcf, respectively.

In addition, the company had downside protection on a portion of its 2020 oil production at an average price of $59.93 per bbl and on a portion of its 2020 gas production at an average price of $2.76 per mcf.

The company’s crude oil hedging positions were as follows:

Open Crude Oil Swaps
	Volume (mmbbls)	Avg. NYMEX Price of Swaps
Q3 2019	7	$	60.16
Q4 2019	7	$	60.24
Total 2019	14	$	60.20
Total 2020	13	$	59.21

Oil Two-Way Collars
	Volume (mmbbls)	Avg. NYMEX Bought Put Price		Avg. NYMEX Sold Call Price
Q3 2019	2	$	58.00	$	67.75
Q4 2019	1	$	58.00	$	67.75
Total 2019	3	$	58.00	$	67.75
Total 2020	2	$	65.00	$	83.25

Oil Puts
	Volume (mmbbls)	Avg. NYMEX Bought Put Price
Total 2019	1	$	54.13

Oil Swaptions
	Volume (mmbbls)	Avg. NYMEX Strike Price
Total 2020	2	$	63.15

19

Oil Basis Protection Swaps
	Volume (mmbbls)	Avg. NYMEX plus/(minus)
Q3 2019	2	$	5.97
Q4 2019	2	$	5.67
Total 2019	4	$	5.85

The company’s natural gas hedging positions were as follows:

Open Natural Gas Swaps
	Volume (bcf)	Avg. NYMEX Price of Swaps
Q3 2019	137	$	2.83
Q4 2019	118	$	2.84
Total 2019	255	$	2.84
Total 2020	265	$	2.76

Natural Gas Two-Way Collars
	Volume (bcf)	Avg. NYMEX Bought Put Price		Avg. NYMEX Sold Call Price
Q3 2019	9	$	2.75	$	2.91
Q4 2019	9	$	2.75	$	2.91
Total 2019	18	$	2.75	$	2.91

Natural Gas Three-Way Collars
	Volume (bcf)	Avg. NYMEX Sold Put Price		Avg. NYMEX Bought Put Price		Avg. NYMEX Sold Call Price
Q4 2019	15	$	2.50	$	2.80	$	3.10
Total 2019	15	$	2.50	$	2.80	$	3.10

Natural Gas Net Written Call Options
	Volume (bcf)	Avg. NYMEX Strike Price
Q3 2019	6	$	12.00
Q4 2019	5	$	12.00
Total 2019	11	$	12.00
Total 2020	22	$	12.00

20

Natural Gas Net Written Call Swaptions
	Volume (bcf)	Avg. NYMEX Strike Price
Total 2020	106	$	2.77
Total 2021	15	$	2.80
Total 2022	15	$	2.80

Natural Gas Basis Protection Swaps
	Volume (bcf)	Avg. NYMEX plus/(minus)
Q3 2019	11	$	0.20
Q4 2019	15	$	(0.23	)
Total 2019	26	$	(0.05	)
Total 2020	15	$	(0.19	)

21