Chesapeake Energy Corporation Reports 2018 First Quarter Financial And Operational Results

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May 02, 2018, 07:00 ET

OKLAHOMA CITY, May 2, 2018 /PRNewswire/ -- Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operational results for the 2018 first quarter. Highlights include:

2018 first quarter net income available to common stockholders of $268 million, or $0.29 per diluted share; 2018 first quarter adjusted net income available to common stockholders of $361 million, or $0.34 per diluted share
2018 first quarter net cash provided by operating activities increased $557 million compared to 2017 first quarter
Reduced $581 million principal amount of long-term debt in 2018 first quarter
Average 2018 first quarter production of approximately 554,000 barrels of oil equivalent (boe) per day, up 11 percent compared to 2017 first quarter, adjusted for asset sales
Average 2018 first quarter oil production of approximately 92,000 barrels of oil per day, up 16 percent compared to 2017 first quarter, adjusted for asset sales

Doug Lawler, Chesapeake's Chief Executive Officer, commented, "The strength of our operations and improved cost structure, coupled with higher realized prices, resulted in our best quarterly financial performance in over three years. For the second consecutive quarter, we recorded significant growth in our earnings and cash flow. Notably, our margin improvement, while aided by increases in commodity indices, was primarily driven by strong oil production and a lower cost structure, highlighting the differential profit generated beyond price impacts, and the sustainability of our improving financial performance. The net cash flow provided by operating and investing activities, including net proceeds from asset sales, was $609 million for the quarter and was the highest in more than three years, allowing us to reduce our long-term debt by $581 million. Our results provide further evidence that we are achieving our long term goals of growing cash flow, expanding margins, reducing long term debt and generating higher returns to shareholders."

2018 First Quarter Results

For the 2018 first quarter, Chesapeake reported net income of $294 million and net income available to common stockholders of $268 million, or $0.29 per diluted share. The company's EBITDA for the 2018 first quarter was $703 million. Adjusting for items that are typically excluded by securities analysts, the 2018 first quarter adjusted net income attributable to Chesapeake was $361 million, or $0.34 per diluted share, while the company's adjusted EBITDA was $733 million. Reconciliations of financial measures calculated in accordance with GAAP to non-GAAP measures are provided on pages 11 - 13 of this release.

Production expenses during the 2018 first quarter were $2.94 per boe, while general and administrative expenses (including stock-based compensation) during the 2018 first quarter were $1.44 per boe. The increase in production expenses was primarily the result of increased saltwater disposal costs and workover activity. With regard to general and administrative expenses, lower compensation costs were more than offset by lower overhead allocations, primarily as a result of certain 2017 divestitures. Chesapeake's combined production and general and administrative expenses per boe increased by 5 percent year over year. However, the company's gathering, processing, and transportation expenses decreased by 4 percent year over year to $7.15 per boe during the 2018 first quarter, resulting in lower overall expenses per unit of production on a combined basis.

Capital Spending Overview

Chesapeake's total capital expenditures (including accruals) were approximately $611 million during the 2018 first quarter, including capitalized interest of $43 million, compared to approximately $576 million in the 2017 first quarter. A summary is provided in the table below.

	Three Months Ended March 31,
	2018		2017
Operated activity comparison
Average rig count	15		16
Gross wells spud	77		87
Gross wells completed	76		99
Gross wells connected	57		76

Type of cost ($ in millions)
Drilling and completion capital expenditures	$	539	$	506
Exploration costs, leasehold and additions to other PP&E	29		19
Subtotal capital expenditures	$	568	$	525
Capitalized interest	43		51
Total capital expenditures	$	611	$	576

Balance Sheet and Liquidity

As of March 31, 2018, Chesapeake's principal debt balance was approximately $9.400 billion, compared to $9.981 billion as of December 31, 2017. Also, as of March 31, 2018, the company had $200 million of outstanding borrowings and had used $157 million for various letters of credit under the senior secured revolving credit facility resulting in approximately $3.4 billion of available liquidity under the facility.

During the 2018 first quarter, the company closed certain property sales for net proceeds of approximately $387 million. In addition, in February 2018 Chesapeake sold approximately 4.3 million shares of FTS International (NYSE: FTSI) for approximately $74 million in net proceeds and continues to hold approximately 22.0 million shares in the publicly traded company. FTSI is a provider of hydraulic fracturing services in North America. Chesapeake used the $461 million in aggregate proceeds described above to reduce its outstanding borrowings under its revolving credit facility. Subsequent to the 2018 first quarter, in April the company closed an additional asset sale for properties in the Mid-Continent for approximately $60 million in net proceeds which reduced Chesapeake's outstanding borrowings under its revolving credit facility.

Operations Update

Chesapeake's average daily production for the 2018 first quarter was approximately 554,000 boe compared to approximately 528,000 boe in the 2017 first quarter. The following tables show average daily production and average daily sales prices received by the company's operating divisions for the 2018 and 2017 first quarters, respectively.

	Three Months Ended March 31, 2018
	Oil		Natural Gas		NGL		Total
	mbbl per day	$/bbl	mmcf per day	$/mcf	mbbl per day	$/bbl	mboe per day	%		$/boe
Marcellus	—	—	873	3.74	—	—	146	26		22.46
Haynesville	—	—	833	2.80	—	—	139	25		16.86
Eagle Ford	61	66.16	141	3.30	18	24.72	102	19		48.22
Utica	11	59.82	440	2.94	23	25.03	107	19		23.39
Mid-Continent	9	62.04	87	2.70	5	26.15	28	5		32.46
Powder River Basin	7	62.86	47	2.82	3	28.77	18	3		37.68
Retained assets^(a)	88	64.66	2,421	3.19	49	25.24	540	97		27.10
Divested assets	4	63.60	45	2.81	2	30.07	14	3		33.53
Total	92	64.61	2,466	3.18	51	25.45	554	100	%	27.27

	Three Months Ended March 31, 2017
	Oil		Natural Gas		NGL		Total
	mbbl per day	$/bbl	mmcf per day	$/mcf	mbbl per day	$/bbl	mboe per day	%		$/boe
Marcellus	—	—	837	3.01	—	—	139	27		18.04
Haynesville	—	—	682	2.98	—	—	114	22		17.86
Eagle Ford	56	50.90	135	3.40	17	21.38	96	18		38.52
Utica	8	45.42	380	3.50	25	25.65	96	18		24.16
Mid-Continent	7	49.64	92	3.04	6	22.45	28	5		26.73
Powder River Basin	5	49.70	29	3.33	2	25.58	12	2		32.67
Retained assets^(a)	76	50.16	2,155	3.11	50	23.81	485	92		24.13
Divested assets	8	50.96	187	2.88	4	23.43	43	8		24.06
Total	84	50.24	2,342	3.10	54	23.78	528	100	%	24.13


(a)	Includes assets retained as of March 31, 2018.

In the Powder River Basin (PRB) in Wyoming, Chesapeake is currently utilizing four rigs, all of which are drilling in the Turner formation. Chesapeake placed six wells on production during the 2018 first quarter in the PRB and expects to place 12 wells on production during the 2018 second quarter and up to 35 wells for the full-year 2018.

As part of a reduced Turner spacing test, six of the company's 12 second quarter wells were placed on production in April 2018 and spaced at approximately 1,980 to 2,300 feet apart. While currently on conservative choke settings between 20 and 22/64ths, the six wells have ranged from 6 to 19 days on production with current flowing tubing pressures ranging from 2,750 to 3,050 pounds. The company is encouraged by initial results from these tighter-spaced wells, as the bounded middle well spaced at approximately 1,980 feet has already reached a production rate of approximately ~2,000 boe per day (46% oil) after 18 days on production. The company expects significantly higher rates as these wells clean up over the next 30 days.

In the company's Mid-Continent operating area in Oklahoma, Chesapeake is currently utilizing two drilling rigs and placed eight wells on production during the 2018 first quarter and expects to place nine wells on production during the 2018 second quarter and up to 35 wells for the full-year 2018. Chesapeake has drilled its first horizontal well targeting the Chester formation in Woods County in April 2018 and expects to place this well on production later this quarter. While one rig will continue to drill appraisal opportunities on the company's approximately 800,000 net acre position during 2018, the second rig will continue developing the Oswego oil play.

In the Eagle Ford Shale, Chesapeake is currently utilizing five drilling rigs and placed 23 wells on production during the 2018 first quarter and expects to place approximately 50 wells on production during the 2018 second quarter and up to 150 wells for the full-year 2018.

In the Utica Shale in Ohio, Chesapeake is currently utilizing two drilling rigs and placed ten wells on production during the 2018 first quarter. The company has recently changed its completion methodologies resulting in 30-day average daily production rates that have increased by approximately 65 percent for its first six wells in 2018 under this new program. Chesapeake expects to place seven wells on production during the 2018 second quarter and up to 35 wells for the full-year 2018.

In the Marcellus Shale, Chesapeake is currently utilizing one drilling rig and placed six wells on production during the 2018 first quarter and expects to place 17 wells on production during the 2018 second quarter and up to 50 wells for the full-year 2018.

In the Haynesville Shale in Louisiana, Chesapeake is currently utilizing three drilling rigs and placed four wells on production during the 2018 first quarter and expects to place eight wells on production during the 2018 second quarter and up to 25 wells for the full-year 2018.

Key Financial and Operational Results

The table below summarizes Chesapeake's key financial and operational results during the 2018 first quarter as compared to results in prior periods.

	Three Months Ended March 31,
	2018	2017
Barrels of oil equivalent production (in mboe)	49,879	47,516
Barrels of oil equivalent production (mboe/d)	554	528
Oil production (in mbbl/d)	92	84
Average realized oil price ($/bbl)^(a)	56.89	51.72
Natural gas production (in mmcf/d)	2,466	2,342
Average realized natural gas price ($/mcf)^(a)	3.49	3.02
NGL production (in mbbl/d)	51	54
Average realized NGL price ($/bbl)^(a)	25.36	24.04
Production expenses ($/boe)	2.94	2.84
Gathering, processing and transportation expenses ($/boe)	7.15	7.47
Oil - ($/bbl)	4.18	3.85
Natural Gas - ($/mcf)	1.27	1.35
NGL - ($/bbl)	8.83	8.47
Production taxes ($/boe)	0.62	0.47
General and administrative expenses ($/boe)^(b)	1.30	1.18
General and administrative expenses (stock-based compensation) (non-cash) ($/boe)	0.14	0.17
DD&A of oil and natural gas properties ($/boe)	5.38	4.15
DD&A of other assets ($/boe)	0.36	0.44
Interest expense ($/boe)^(a)	2.45	1.97
Marketing net margin ($ in millions)	(22)	(44)
Net cash provided by operating activities ($ in millions)	656	99
Net cash provided by operating activities ($/boe)	13.15	2.06
Operating cash flow ($ in millions)^(c)	552	(14)
Operating cash flow ($/boe)	11.07	(0.29)
Net income ($ in millions)	294	141
Net income available to common stockholders ($ in millions)	268	75
Net income per share available to common stockholders – diluted ($)	0.29	0.08
Adjusted EBITDA ($ in millions)^(d)	733	525
Adjusted EBITDA ($/boe)	14.70	11.05
Adjusted net income attributable to Chesapeake ($ in millions)^(e)	361	212
Adjusted net income attributable to Chesapeake per share - diluted ($ in millions)^(f)	0.34	0.23

(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)	Defined as cash flow provided by operating activities before changes in components of working capital and other assets and liabilities. This is a non-GAAP measure. See reconciliation to cash provided by (used in) operating activities on page 12.

(d)	Defined as net income (loss) before interest expense, income taxes and depreciation, depletion and amortization expense, as adjusted to remove the effects of certain items detailed on page 13. This is a non-GAAP measure. See reconciliation of net income (loss) to EBITDA on page 12 and reconciliation of EBITDA to adjusted EBITDA on page 13.

(e)	Defined as net income (loss) attributable to Chesapeake, as adjusted to remove the effects of certain items detailed on page 11. This is a non-GAAP measure. See reconciliation of net income to adjusted net income (loss) available to Chesapeake on page 11.

(f)	Our presentation of diluted adjusted net income (loss) attributable to Chesapeake per share excludes 60 million and 208 million shares for the three months ended March 31, 2018 and 2017, respectively, considered antidilutive when calculating diluted earnings per share.

2018 First Quarter Financial and Operational Results Conference Call Information

A conference call to discuss this release has been scheduled on Wednesday, May 2, 2018 at 9:00 am EDT. The telephone number to access the conference call is 323-794-2093 or toll-free 866-548-4713. The passcode for the call is 2838919. The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112 and the passcode for the replay is 2838919. The conference call will be webcast and can be found at www.chk.com in the "Investors" section of the company's website. The webcast of the conference will be available on the website for one year.

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, 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.

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.

INVESTOR CONTACT:

MEDIA CONTACT:

Brad Sylvester, CFA

(405) 935-8870

[email protected]

Gordon Pennoyer

(405) 935-8878

[email protected]

CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS ($ in millions except per share data) (unaudited)
	Three Months Ended March 31,
	2018		2017
REVENUES:
Oil, natural gas and NGL	$	1,243	$	1,469
Marketing	1,246		1,284
Total Revenues	2,489		2,753
OPERATING EXPENSES:
Oil, natural gas and NGL production	147		135
Oil, natural gas and NGL gathering, processing and transportation	356		355
Production taxes	31		22
Marketing	1,268		1,328
General and administrative	72		65
Restructuring and other termination costs	38		—
Provision for legal contingencies, net	5		(2)
Oil, natural gas and NGL depreciation, depletion and amortization	268		197
Depreciation and amortization of other assets	18		21
Other operating expense	—		391
Net losses on sales of fixed assets	8		—
Total Operating Expenses	2,211		2,512
INCOME FROM OPERATIONS	278		241
OTHER INCOME (EXPENSE):
Interest expense	(123)		(95)
Gains on investments	139		—
Losses on purchases or exchanges of debt	—		(7)
Other income	—		3
Total Other Income (Expense)	16		(99)
INCOME BEFORE INCOME TAXES	294		142
Income tax expense	—		1
NET INCOME	294		141
Net income attributable to noncontrolling interests	(1)		(1)
NET INCOME ATTRIBUTABLE TO CHESAPEAKE	293		140
Preferred stock dividends	(23)		(23)
Loss on exchange of preferred stock	—		(41)
Earnings allocated to participating securities	(2)		(1)
NET INCOME AVAILABLE TO COMMON STOCKHOLDERS	$	268	$	75
EARNINGS PER COMMON SHARE:
Basic	$	0.30	$	0.08
Diluted	$	0.29	$	0.08
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic	907		906
Diluted	1,053		907

CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS ($ in millions) (unaudited)
	March 31, 2018		December 31, 2017

Cash and cash equivalents	$	4	$	5
Other current assets	1,220		1,520
Total Current Assets	1,224		1,525

Property and equipment, net	10,592		10,680
Other long-term assets	270		220
Total Assets	$	12,086	$	12,425

Current liabilities	$	2,354	$	2,356
Long-term debt, net	9,325		9,921
Other long-term liabilities	504		520
Total Liabilities	12,183		12,797

Preferred stock	1,671		1,671
Noncontrolling interests	123		124
Common stock and other stockholders' equity (deficit)	(1,891)		(2,167)
Total Equity (Deficit)	(97)		(372)

Total Liabilities and Equity	$	12,086	$	12,425

Common shares outstanding (in millions)	912		909
Principal amount of debt outstanding	$	9,400	$	9,981

CHESAPEAKE ENERGY CORPORATION SUPPLEMENTAL DATA – OIL, NATURAL GAS AND NGL PRODUCTION, SALES AND INTEREST EXPENSE (unaudited)
	Three Months Ended March 31,
	2018		2017
Net Production:
Oil (mmbbl)	8		8
Natural gas (bcf)	222		211
NGL (mmbbl)	5		5
Oil equivalent (mmboe)	50		48
Average daily production (mboe)	554		528
Oil, natural gas and NGL Sales ($ in millions):
Oil sales	$	537	$	378
Natural gas sales	706		653
NGL sales	117		116
Total oil, natural gas and NGL sales	$	1,360	$	1,147

Financial Derivatives:
Oil derivatives – realized gains (losses)^(a)	$	(64)	11
Natural gas derivatives – realized gains (losses)^(a)	67		(16)
NGL derivatives – realized gains (losses)^(a)	(1)		1
Total realized gains (losses) on financial derivatives	$	2	$	(4)

Oil derivatives – unrealized gains (losses)^(a)	(22)		94
Natural gas derivatives – unrealized gains (losses)^(a)	(99)		231
NGL derivatives – unrealized gains^(a)	2		1
Total unrealized gains (losses) on financial derivatives	$	(119)	$	326

Total financial derivatives	$	(117)	$	322

Total oil, natural gas and NGL sales	$	1,243	$	1,469
Average Sales Price (excluding gains (losses) on derivatives):
Oil ($ per bbl)	$	64.61	$	50.24
Natural gas ($ per mcf)	$	3.18	$	3.10
NGL ($ per bbl)	$	25.45	$	23.78
Oil equivalent ($ per boe)	$	27.27	$	24.13
Average Sales Price (excluding unrealized gains (losses) on derivatives):
Oil ($ per bbl)	$	56.89	$	51.72
Natural gas ($ per mcf)	$	3.49	$	3.02
NGL ($ per bbl)	$	25.36	$	24.04
Oil equivalent ($ per boe)	$	27.31	$	24.06
Interest Expense ($ in millions):
Interest expense^(b)	$	123	$	94
Interest rate derivatives – realized gains^(c)	(1)		(1)
Interest rate derivatives – unrealized losses^(c)	1		2
Total Interest Expense	$	123	$	95


(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. 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.

(b)	Net of amounts capitalized.

(c)	Realized (gains) losses include interest rate derivative settlements related to current period interest and the effect of (gains) losses on early-terminated trades. Settlements of early-terminated trades are reflected in realized (gains) losses over the original life of the hedged item. Unrealized (gains) losses include changes in the fair value of open interest rate derivatives offset by amounts reclassified to realized (gains) losses during the period.

CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED CASH FLOW DATA ($ in millions) (unaudited)
	Three Months Ended March 31,
	2018		2017

Beginning cash and cash equivalents	$	5	$	882

Net cash provided by operating activities	656		99

Cash flows from investing activities:
Drilling and completion costs^(a)	(442)		(433)
Acquisitions of proved and unproved properties^(b)	(63)		(95)
Proceeds from divestitures of proved and unproved properties	319		892
Additions to other property and equipment	(3)		(3)
Proceeds from sales of other property and equipment	68		19
Proceeds from sales of investments	74		—
Net cash provided by (used in) investing activities	(47)		380

Net cash used in financing activities	(610)		(1,112)
Change in cash and cash equivalents	(1)		(633)
Ending cash and cash equivalents	$	4	$	249


(a)	Includes capitalized interest of $2 million and $2 million for the three months ended March 31, 2018 and 2017, respectively.

(b)	Includes capitalized interest of $41 million and $49 million for the three months ended March 31, 2018 and 2017, respectively.

CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS ($ in millions except per share data) (unaudited)
	Three Months Ended March 31,
	2018				2017
	$		$/Share^(b)(c)		$		$/Share^(b)(c)
Net income available to common stockholders (GAAP)	$	268	$	0.30	$	75	$	0.08
Effect of dilutive securities	36				—
Diluted earnings per common stockholder (GAAP)	$	304	$	0.29	$	75	$	0.08

Adjustments:
Unrealized (gains) losses on oil, natural gas and NGL derivatives	119		0.11		(326)		(0.36)
Restructuring and other termination costs	38		0.04		—		—
Provision for legal contingencies, net	5		—		(2)		—
Other operating expense	—		—		391		0.43
Net losses on sales of fixed assets	8		0.01		—		—
Gains on investments	(139)		(0.13)		—		—
Losses on purchases or exchanges of debt	—		—		7		0.01
Loss on exchange of preferred stock	—		—		41		0.05
Other	1		—		2		—
Adjusted net income available to common stockholders^(b) (Non-GAAP)	336		0.32		188		0.21

Preferred stock dividends	23		0.02		23		0.02
Earnings allocated to participating securities	2		—		1		—
Total adjusted net income attributable to Chesapeake^{(b) (c)}(Non-GAAP)	$	361	$	0.34	$	212	$	0.23


(a)	Our effective tax rate in the three months ended March 31, 2018 was 0%. Due to our valuation allowance position, no income tax effect from the adjustments has been included in determining adjusted net income for the three months ended March 31, 2017.

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

(c)	Our presentation of diluted net income (loss) available to common stockholders and diluted adjusted net income (loss) per share excludes 60 million and 208 million shares considered antidilutive for the three months ended March 31, 2018 and 2017, respectively. The number of shares used for the non-GAAP calculation was determined in a manner consistent with GAAP.

CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF OPERATING CASH FLOW AND EBITDA ($ in millions) (unaudited)
	Three Months Ended March 31,
	2018		2017

CASH PROVIDED BY OPERATING ACTIVITIES (GAAP)	$	656	$	99
Changes in components of working capital and other assets and liabilities	(104)		(113)
OPERATING CASH FLOW (Non-GAAP)^(a)	$	552	$	(14)

	Three Months Ended March 31,
	2018		2017

NET INCOME (GAAP)	$	294	$	141
Interest expense	123		95
Income tax expense	—		1
Depreciation and amortization of other assets	18		21
Oil, natural gas and NGL depreciation, depletion and amortization	268		197
EBITDA (Non-GAAP)^(b)	$	703	$	455

	Three Months Ended March 31,
	2018		2017

CASH PROVIDED BY OPERATING ACTIVITIES (GAAP)	$	656	$	99
Changes in assets and liabilities	(104)		(113)
Interest expense, net of unrealized gains (losses) on derivatives	123		93
Gains (losses) on oil, natural gas and NGL derivatives, net	(117)		322
Cash (receipts) payments on derivative settlements, net	(13)		34
Stock-based compensation	(9)		(11)
Net losses on sales of fixed assets	(8)		—
Gains on investments	139		—
Losses on purchases or exchanges of debt	—		(6)
Other items	36		37
EBITDA (Non-GAAP)^(b)	$	703	$	455


(a)	Operating cash flow represents net cash provided by operating activities before changes in components of working capital and other. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under GAAP and provides useful information to investors for analysis of the Company's ability to generate cash to fund exploration and development, and to service debt. Operating cash flow is widely accepted as a financial indicator of an oil and natural gas company's ability to generate cash that is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies within the oil and natural gas exploration and production industry. Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities as an indicator of cash flows, or as a measure of liquidity. Because operating cash flow excludes some, but not all, items that affect net cash provided by operating activities and may vary among companies, our calculation of operating cash flow may not be comparable to similarly titled measures of other companies. The increase in operating cash flow for the three months ended March 31, 2018 is mainly due to an increase in prices and volumes.

(b)	EBITDA represents net income before interest expense, income tax expense, and depreciation, depletion and amortization expense. EBITDA is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies. EBITDA is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our bank credit agreements and is used in the financial covenants in our bank credit agreements. EBITDA is not a measure of financial performance (or liquidity) under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations or cash flows from operating activities prepared in accordance with GAAP.

CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED EBITDA ($ in millions) (unaudited)
	Three Months Ended March 31,
	2018		2017

EBITDA (Non-GAAP)	$	703	$	455

Adjustments:
Unrealized losses (gains) on oil, natural gas and NGL derivatives	119		(326)
Restructuring and other termination costs	38		—
Provision for legal contingencies, net	5		(2)
Other operating expense	—		391
Net losses on sales of fixed assets	8		—
Gains on investments	(139)		—
Losses on purchases or exchanges of debt	—		7
Net income attributable to noncontrolling interests	(1)		(1)
Other	—		1

Adjusted EBITDA (Non-GAAP)^(a)	$	733	$	525


(a)	Adjusted EBITDA excludes certain items that management believes affect the comparability of operating results. The company believes these non-GAAP financial measures are a useful adjunct to EBITDA because:

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

	(ii)	Adjusted EBITDA 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.

Accordingly, adjusted EBITDA should not be considered as a substitute for net income, income from operations or cash flow provided by operating activities prepared in accordance with GAAP. Because adjusted EBITDA excludes some, but not all, items that affect net income (loss from continuing operations) attributable to common stockholders, our calculations of adjusted EBITDA may not be comparable to similarly titled measures of other companies.

CHESAPEAKE ENERGY CORPORATION
MANAGEMENT'S OUTLOOK AS OF MAY 1, 2018
Chesapeake periodically provides guidance on certain factors that affect the company's future financial performance. New information or changes from the company's February 22, 2018 outlook are *italicized bold* below.

	Year Ending 12/31/2018

Production Growth adjusted for asset sales^(a)	1% to 5%
Absolute Production
Liquids - mmbbls	51.0 - 55.0
Oil - mmbbls	31.0 - 33.0
NGL - mmbbls	20.0 - 22.0
Natural gas - bcf	825 - 875
Total absolute production - mmboe	190 - 200
Absolute daily rate - mboe	515 - 550
Estimated Realized Hedging Effects^(b) (based on 4/27/18 strip prices):
Oil - $/bbl	($10.20)
Natural gas - $/mcf	$0.13
NGL - $/bbl	$(0.13)
Estimated Basis to NYMEX Prices:
Oil - $/bbl	$1.00 - $1.20
Natural gas - $/mcf	($0.10) - ($0.20)
NGL - $/bbl	($5.20) - ($5.60)
Operating Costs per Boe of Projected Production:
Production expense	$2.60 - $2.80
Gathering, processing and transportation expenses	$6.95 - $7.65
Oil - $/bbl	$3.90 - $4.10
Natural Gas - $/mcf	$1.25 - $1.40
NGL - $/bbl	$7.85 - $8.25
Production taxes	$0.50 - $0.60
General and administrative^(c)	$1.25 - $1.35
Stock-based compensation (noncash)	$0.10 - $0.20
DD&A of natural gas and liquids assets	$5.00 - $6.00
Depreciation of other assets	$0.35 - $0.45
Interest expense^(d)	$2.40 - $2.60
Marketing net margin^(e)	($60) - ($40)
Book Tax Rate	0%
Adjusted EBITDA, based on 4/27/18 strip prices ($ in millions)^(f)	*$2,250 - $2,450*
Capital Expenditures ($ in millions)^(g)	$1,800 - $2,200
Capitalized Interest ($ in millions)	$175
Total Capital Expenditures ($ in millions)	$1,975 - $2,375


(a)	Based on 2017 production of 514 mboe per day, adjusted for 2017 asset sales and 2018 asset sales signed to date.

(b)	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.

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

(d)	Excludes unrealized gains (losses) on interest rate derivatives.

(e)	Excludes non-cash amortization of approximately $19 million.

(f)	Adjusted EBITDA 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 EBITDA 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 EBITDA 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 EBITDA include interest expense, income taxes, and depreciation, depletion and amortization expense as well as one-time items or items whose timing or amount cannot be reasonably estimated.

(g)	Includes capital expenditures for drilling and completion, leasehold, geological and geophysical costs, rig termination payments and other property, plant and equipment. Excludes any additional proved property acquisitions.

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 April 27, 2018, including April and May derivative contracts that have settled, the company had downside price protection on a portion of its 2018 oil, natural gas and natural gas liquids production. The company had downside oil price protection through swaps at an average price of $53.78 per bbl, and under three-way collar arrangements based on an average bought put NYMEX price of $47.00 per bbl and exposure below an average sold put NYMEX price of $39.15 per bbl. The company had downside gas price protection through swaps and two-way collars at an average price of $2.96 per mcf. Chesapeake also had downside ethane, propane, butane, isobutane and natural gasoline price protection through swaps at an average price of $0.28, $0.78, $0.88, $0.92 and $1.42 per gallon (as well as a portion of butane at 70.5 percent of WTI), respectively. Further details summarized below.

In addition, the company had downside protection, through open swaps on a portion of its 2019 oil production at an average price of $57.87 per bbl. The company also initiated downside protection on a portion of its 2019 gas production under three-way collar arrangements based on an average bought put NYMEX price of $2.80 per mcf and exposure below an average sold put NYMEX price of $2.50 per mcf.

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

Crude Oil Swaps Gains (Losses) from Closed Crude Oil Trades
	Swaps (mbbls)	Avg. NYMEX Price of Swaps		Gains/Losses from Closed Trades ($ in millions)

Q2 2018	5,886	$	52.80	$	(1)
Q3 2018	5,612	$	54.30	(1)
Q4 2018	5,612	$	54.30	(1)
Total 2018	17,110	$	53.78	$	(3)

Total 2019	11,661	$	57.87	$	(8)

Crude Oil Net Written Call Options
	Call Options (mbbls)	Avg. NYMEX Strike Price

Q3 2018	920	$	52.87
Q4 2018	920	$	52.87
Total 2018	1,840	$	52.87

Crude Oil Three-Way Collars
	Collars (mbbls)	Avg. NYMEX Sold Put Price		Avg. NYMEX Bought Put Price		Avg. NYMEX Sold Call Price

Q2 2018	455	$	39.15	$	47.00	$	55.00
Q3 2018	460	$	39.15	$	47.00	$	55.00
Q4 2018	460	$	39.15	$	47.00	$	55.00
Total 2018	1,375	$	39.15	$	47.00	$	55.00

Oil Basis Protection Swaps
	Volume (mbbls)	Avg. NYMEX plus/(minus)

Q2 2018	2,639	$	3.21
Q3 2018	2,760	$	3.42
Q4 2018	2,760	$	3.42
Total 2018	8,159	$	3.35

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

Natural Gas Swaps Losses from Closed Natural Gas Trades
	Swaps (bcf)	Avg. NYMEX Price of Swaps		Losses from Closed Trades ($ in millions)

Q2 2018	118	$	2.92	$	(4)
Q3 2018	120	$	2.94	(4)
Q4 2018	120	$	3.00	(6)
Total 2018	358	$	2.95	$	(14)

Total 2019 - 2022				$	(49)

Natural Gas Two-Way Collars
	Collars (bcf)	Avg. NYMEX Bought Put Price		Avg. NYMEX Sold Call Price

Q2 2018	12	$	3.00	$	3.25
Q3 2018	12	$	3.00	$	3.25
Q4 2018	12	$	3.00	$	3.25
Total 2018	36	$	3.00	$	3.25

Natural Gas Three-Way Collars
	Collars (bcf)	Avg. NYMEX Sold Put Price		Avg. NYMEX Bought Put Price		Avg. NYMEX Sold Call Price

Total 2019	87	$	2.50	$	2.80	$	3.10

Natural Gas Net Written Call Options
	Call Options (bcf)	Avg. NYMEX Strike Price

Q2 2018	16	$	6.27
Q3 2018	17	$	6.27
Q4 2018	17	$	6.27
Total 2018	50	$	6.27

Total 2019 – 2020	44	$	12.00

Natural Gas Basis Protection Swaps
	Volume (bcf)	Avg. NYMEX plus/(minus)

Q2 2018	18	$	(0.77)
Q3 2018	17	$	(0.77)
Q4 2018	6	$	(0.77)
Total 2018	41	$	(0.77)

Total 2019	4	$	2.24

The company's natural gas liquids hedging positions were as follows:

Ethane Swaps
	Volume (mmgal)	Avg. NYMEX Price of Swaps

Q2 2018	4	$	0.28
Total 2018	4	$	0.28

Propane Swaps
	Volume (mmgal)	Avg. NYMEX Price of Swaps

Q2 2018	12	$	0.78
Q3 2018	15	$	0.79
Q4 2018	15	$	0.79
Total 2018	42	$	0.79

Butane Swaps
	Volume (mmgal)	Avg. NYMEX Price of Swaps

Q2 2018	1	$	0.88
Q3 2018	1	$	0.88
Q4 2018	2	$	0.88
Total 2018	4	$	0.88

Butane Swaps Priced as a Percentage of WTI
	Volume (mmgal)	Avg. NYMEX as a % of WTI Swaps

Q2 2018	1	70.5	%
Q3 2018	1	70.5	%
Q4 2018	2	70.5	%
Total 2018	4	70.5	%