Chesapeake Energy Corporation Reports 2017 First Quarter Financial And Operational Results

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May 04, 2017, 07:00 ET

OKLAHOMA CITY, May 4, 2017 /PRNewswire/ -- Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operational results for the 2017 first quarter plus other recent developments. Highlights include:

Average 2017 first quarter production of 528,000 boe per day, above midpoint of guidance of 515,000 to 535,000 boe per day
Oil production expected to reach 100,000 barrels per day by year-end 2017; average 2017 first quarter oil production of 83,700 barrels per day, above midpoint of guidance of 80,000 to 85,000 barrels per day
Combined production and G&A expenses per boe down 2% quarter over quarter
Gathering, processing and transportation expenses per boe down 6% quarter over quarter

Doug Lawler, Chesapeake's Chief Executive Officer, commented, "Our operational momentum continues to build in our Eagle Ford, Powder River Basin and Mid-Continent oil assets, as we remain on track to reach our production target of 100,000 barrels of oil per day by year-end. We expect our production to grow significantly in the second half of 2017 as we place more wells to sales, and as a result, we have raised the bottom range of our 2017 production guidance. We remain focused on improving our balance sheet and decreasing our cash costs, while improving the capital efficiency from our operations. We look forward to reporting our results as the year progresses."

2017 First Quarter Results

For the 2017 first quarter, Chesapeake's revenues increased by 41% year over year and 36% quarter over quarter primarily due to an increase in the average realized commodity prices for the company's production and unrealized hedging gains, partially offset by a decrease in production volumes sold. Average daily production for the 2017 first quarter of approximately 528,000 barrels of oil equivalent (boe) consisted of approximately 83,700 barrels (bbls) of oil, 2.342 billion cubic feet (bcf) of natural gas and 53,900 bbls of natural gas liquids (NGL).

Average production expenses during the 2017 first quarter were $2.84 per boe, while G&A expenses (including stock-based compensation) during the 2017 first quarter were $1.35 per boe. Combined production and G&A expenses (including stock-based compensation) during the 2017 first quarter were $4.19 per boe, an increase of 1% year over year and a decrease of 2% quarter over quarter. Gathering, processing and transportation expenses during the 2017 first quarter were $7.47 per boe, a decrease of 5% year over year and 6% quarter over quarter, primarily due to the company's Barnett and Devonian divestitures in 2016.

Chesapeake reported net income available to common stockholders of $75 million, or $0.08 per share, while the company's ebitda for the 2017 first quarter was $455 million. Adjusting for unrealized gains on commodity derivatives, impairments related to the reduction of crude transportation commitments on the Seaway Pipeline and other related natural gas transportation obligations of approximately $393 million, the loss on exchange of preferred stock and other items, including those that are typically excluded by securities analysts, the 2017 first quarter adjusted net income attributable to Chesapeake was $212 million, or $0.23 per common share, while the company's adjusted ebitda was $525 million in the 2017 first quarter. Reconciliations of financial measures calculated in accordance with GAAP to non-GAAP measures are provided on pages 11 – 12 of this release.

Capital Spending Overview

Chesapeake's total capital investments were approximately $576 million during the 2017 first quarter, compared to approximately $463 million in the 2016 fourth quarter and $365 million in the 2016 first quarter. A summary of the company's guidance for 2017 is provided under "Management's Outlook as of May 3, 2017," beginning on page 16.

	2017		2016		2016
Operated activity comparison	Q1		Q4		Q1
Average rig count	16		12		8
Gross wells spud	87		60		41
Gross wells completed	99		82		57
Gross wells connected	76		110		80

Type of cost ($ in millions)
Drilling and completion costs	$	506	$	365	$	281
Exploration costs, leasehold and additions to other PP&E	19		38		16
Subtotal capital expenditures	$	525	$	403	$	297
Capitalized interest	51		60		68
Total capital expenditures	$	576	$	463	$	365

Balance Sheet and Liquidity

As of March 31, 2017, Chesapeake's principal debt balance was approximately $9.1 billion with $249 million in cash on hand, compared to $10.0 billion with $882 million in cash on hand as of December 31, 2016. The company's total liquidity as of March 31, 2017 was approximately $3.3 billion, which included cash on hand and borrowing capacity of approximately $3.1 billion under the company's senior secured revolving credit facility, which had no outstanding borrowings and $697 million utilized for various letters of credit (including the $461 million supersedeas bond with respect to the 2014 redemption of Chesapeake's 6.775% Senior Notes due 2019 ("2019 Notes") litigation).

On April 24, 2017, Chesapeake received notice from the U.S. Supreme Court that it would not review its appeal related to the company's 2019 Notes litigation. As a result of this decision, the company satisfied the judgment of $441 million on April 28, 2017, with cash on hand and from the company's revolving credit facility. While the company is disappointed in the Supreme Court's decision, it had posted a supersedeas bond for the full amount (reflected as an outstanding letter of credit under the company's revolving credit facility described above), and therefore the judgment had no further impact on liquidity. As of May 1, 2017, after making the judgment payment and pro forma the relief of the associated letters of credit, Chesapeake's liquidity was approximately $3.3 billion.

Operations Update

Chesapeake's average daily production for the 2017 first quarter was approximately 528,000 boe and is further detailed in the table below. Chesapeake's projected production volumes and capital expenditure program are subject to capital allocation decisions throughout the year and may be adjusted based on prevailing market conditions.

	2017	2016	2016
Operating area net production (mboe/day)	Q1	Q4	Q1
Eagle Ford	96	104	91
Haynesville ⁽¹⁾	121	135	112
Marcellus	146	134	144
Utica	96	108	138
Mid-Continent	57	53	93
Powder River Basin	12	12	17
Barnett	—	19	69
Other	—	10	8
Total production	528	575	672


(1)	Properties sold during the 2017 first quarter contributed approximately 14 mboe/day in the 2016 fourth quarter.

Chesapeake is currently utilizing 19 drilling rigs (above the 2017 first quarter average of 16) across its operating areas, seven of which are located in the Eagle Ford Shale, five in the Mid-Continent area, three in the Haynesville Shale, two in the Powder River Basin and two in Northeast Appalachia. Chesapeake plans to utilize an average of 17 rigs throughout the year and intends to spud and place on production approximately 400 and 450 gross operated wells, respectively, in 2017.

In the Eagle Ford Shale, Chesapeake placed the Blakeway 1C DIM 2H well in production in March 2017 and it reached a peak production rate of approximately 2,800 bbls of oil per day (3,184 boe per day). The Blakeway well had a 9,800' lateral and was completed with higher proppant concentration per foot of lateral and reduced cluster spacing compared to the company's historical completion methods. The company expects to place several more wells on production with these enhanced completion techniques in 2017. The company also drilled its first Upper Eagle Ford Shale well, the Blakeway 3D DIM 2H, with an 11,300' lateral. This well was fracture stimulated and placed in production on May 3, 2017. The company expects to report a production test rate on this well later this month.

In the Powder River Basin (PRB), Chesapeake's first Turner well, the Sundquist 9-34-71 USA A TR 13H, was drilled with a 7,100' lateral and placed in production in March 2017, reaching a peak rate of 2,560 boe per day (78% oil). Average daily gross cumulative production from the Sundquist well was approximately 1,522 boe per day during its first 30 days of production, resulting in cumulative gross oil production of approximately 36,000 bbls over that time. The company expects to place its second Turner well, the Rankin 5-33-68 A TR 1H drilled with a 4,500' lateral, on production soon and report a production test rate on this well later this month. Chesapeake plans to drill up to 10 additional wells in the Turner formation in 2017. Chesapeake also placed on production its first of two scheduled Parkman wells this year, the Sundquist 9-34-71 USA A PK 15H, with a 7,000' lateral which, while currently production constrained, has reached a peak rate of 714 bbls of oil per day (763 boe per day). Chesapeake also placed three notable Niobrara wells on production during the 2017 first quarter which had been drilled, but uncompleted, that had peak rates of approximately 750, 1,155 and 1,215 bbls of oil per day (1,575, 1,650 and 1,930 boe per day), respectively. Chesapeake expects additional results from these and other formations in the PRB, including the Sussex and a deeper Mowry test, later this year.

In the Mid-Continent, Chesapeake drilled its first extended-lateral well in Major County targeting the Saint Genevieve formation (Meramec silt). This well had a completed lateral length of 9,900' and was placed in production in late April of 2017. The company expects to report a production test rate on this well later this month. Chesapeake expects to drill up to 20 additional extended-lateral wells in the Saint Genevieve formation in 2017. The company also expects to test additional formations in its Mid-Continent area, including the Chester limestone and sandstone formations, later this year. Chesapeake controls approximately 230,000 net acres that it believes are prospective for the Chester and has drilled and collected two full core samples of the section earlier this year to help optimize its completion designs. The company expects first results from the Chester in the third and fourth quarters of 2017.

Key Financial and Operational Results

The table below summarizes Chesapeake's key financial and operational results during the 2017 first quarter compared to results in prior periods.

	Three Months Ended
	03/31/17	12/31/16	03/31/16
Oil equivalent production (in mmboe)	48	53	61
Oil production (in mmbbls)	8	8	9
Average realized oil price ($/bbl)^(a)	51.72	47.37	37.74
Natural gas production (in bcf)	211	236	276
Average realized natural gas price ($/mcf)^(a)	3.02	2.41	2.29
NGL production (in mmbbls)	5	5	6
Average realized NGL price ($/bbl)^(a)	24.04	20.90	11.44
Production expenses ($/boe)	(2.84)	(2.98)	(3.36)
Gathering, processing and transportation expenses ($/boe)	(7.47)	(7.92)	(7.88)
Oil - ($/bbl)	(3.85)	(3.87)	(3.29)
Natural Gas - ($/mcf)	(1.35)	(1.46)	(1.46)
NGL - ($/bbl)	(8.47)	(8.05)	(7.59)
Production taxes ($/boe)	(0.47)	(0.38)	(0.30)
General and administrative expenses ($/boe)^(b)	(1.18)	(1.11)	(0.66)
Stock-based compensation ($/boe)	(0.17)	(0.17)	(0.13)
DD&A of oil and natural gas properties ($/boe)	(4.15)	(4.03)	(4.30)
DD&A of other assets ($/boe)	(0.44)	(0.40)	(0.48)
Interest expense ($/boe)^(a)	(1.97)	(1.61)	(0.98)
Marketing, gathering and compression net margin ($ in millions)^(c)	(44)	(25)	18
Net cash provided by (used in) operating activities ($ in millions)	99	(254)	(421)
Net cash provided by (used in) operating activities ($/boe)	2.06	(4.79)	(6.90)
Operating cash flow ($ in millions)^(d)	(14)	(120)	263
Operating cash flow ($/boe)	(0.29)	(2.27)	4.29
Adjusted ebitda ($ in millions)^(e)	525	385	282
Adjusted ebitda ($/boe)	11.05	7.28	4.61
Net income (loss) available to common stockholders ($ in millions)	75	(740)	(1,111)
Income (loss) per share – diluted ($)	0.08	(0.83)	(1.66)
Adjusted net income (loss) attributable to Chesapeake ($ in millions)^(f)	212	64	(69)
Adjusted income (loss) per share ($)^(g)	0.23	0.07	(0.11)


(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 and restructuring and other termination costs.
(c)	Includes revenue, operating expenses and for the three months ended March 31, 2016, unrealized gains (losses) on supply contract derivatives, but excludes depreciation and amortization of other assets. For the three months ended March 31, 2016, unrealized gains were $20 million. No other period had such gains (losses).
(d)	Defined as cash flow provided by operating activities before changes in assets and liabilities. Operating cash flow for the three months ended March 31, 2017 includes $290 million paid to assign an oil transportation agreement to a third party and $103 million paid to terminate future natural gas transportation commitments.
(e)	Defined as net income before interest expense, income taxes and depreciation, depletion and amortization expense, as adjusted to remove the effects of certain items detailed on page 14.
(f)	Defined as net income (loss) attributable to Chesapeake, as adjusted to remove the effects of certain items detailed on pages 11 - 12.
(g)	Our presentation of diluted adjusted net income (loss) per share excludes shares considered antidilutive when calculating diluted earnings per share in accordance with GAAP.

2017 First Quarter Financial and Operational Results Conference Call Information

A conference call to discuss this release has been scheduled on Thursday, May 4, 2017 at 9:00 am EDT. The telephone number to access the conference call is 719-325-2224 or toll-free 888-466-4582. The passcode for the call is 6673789. 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 6673789. 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. The company also owns oil and natural gas marketing and natural gas compression businesses.

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, 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, general and administrative expenses, capital expenditures, the timing of anticipated noncore asset sales and proceeds to be received therefrom, projected cash flow and liquidity, our ability to enhance our cash flow and financial flexibility, plans and objectives for future operations (including our ability to optimize base production and execute gas gathering, processing and transportation commitments), 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; potential challenges by Seventy Seven Energy Inc.'s (SSE) former creditors in connection with SSE's recently completed bankruptcy under Chapter 11 of the U.S. Bankruptcy Code; an interruption in operations at our headquarters due to a catastrophic event; the continuation of suspended dividend payments on our common stock; 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,
	2017		2016
REVENUES:
Oil, natural gas and NGL	$	1,469	$	993
Marketing, gathering and compression	1,284		960
Total Revenues	2,753		1,953
OPERATING EXPENSES:
Oil, natural gas and NGL production	135		206
Oil, natural gas and NGL gathering, processing and transportation	355		482
Production taxes	22		18
Marketing, gathering and compression	1,328		942
General and administrative	65		48
Provision for legal contingencies	(2)		33
Oil, natural gas and NGL depreciation, depletion and amortization	197		263
Depreciation and amortization of other assets	21		29
Impairment of oil and natural gas properties	—		997
Impairments of fixed assets and other	391		38
Net gains on sales of fixed assets	—		(4)
Total Operating Expenses	2,512		3,052
INCOME (LOSS) FROM OPERATIONS	241		(1,099)
OTHER INCOME (EXPENSE):
Interest expense	(95)		(62)
Loss on sale of investment	—		(10)
Gains (losses) on purchases or exchanges of debt	(7)		100
Other income	3		3
Total Other Income (Expense)	(99)		31
INCOME (LOSS) BEFORE INCOME TAXES	142		(1,068)
Income Tax Expense	1		—
NET INCOME (LOSS)	141		(1,068)
Net income attributable to noncontrolling interests	(1)		—
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	140		(1,068)
Preferred stock dividends	(23)		(43)
Loss on exchange of preferred stock	(41)		—
Earnings allocated to participating securities	(1)		—
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$	75	$	(1,111)
EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	0.08	$	(1.66)
Diluted	$	0.08	$	(1.66)
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic	906		668
Diluted	907		668

CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
($ in millions)
(unaudited)

	March 31, 2017		December 31, 2016

Cash and cash equivalents	$	249	$	882
Other current assets	1,111		1,260
Total Current Assets	1,360		2,142

Property and equipment, (net)	10,081		10,609
Other assets	258		277
Total Assets	$	11,699	$	13,028

Current liabilities	$	2,788	$	3,648
Long-term debt, net	9,509		9,938
Other long-term liabilities	605		645
Total Liabilities	12,902		14,231

Preferred stock	1,671		1,771
Noncontrolling interests	256		257
Common stock and other stockholders' equity	(3,130)		(3,231)
Total Equity (Deficit)	(1,203)		(1,203)

Total Liabilities and Equity	$	11,699	$	13,028

Common shares outstanding (in millions)	908		896
Principal amount of debt outstanding	$	9,081	$	9,989

CHESAPEAKE ENERGY CORPORATION
SUPPLEMENTAL DATA – OIL, NATURAL GAS AND NGL PRODUCTION, SALES AND INTEREST EXPENSE
(unaudited)

	Three Months Ended March 31,
	2017		2016
Net Production:
Oil (mmbbl)	8		9
Natural gas (bcf)	211		276
NGL (mmbbl)	5		6
Oil equivalent (mmboe)	48		61

Oil, natural gas and NGL Sales ($ in millions):
Oil sales	$	378	$	255
Oil derivatives – realized gains (losses)^(a)	11		73
Oil derivatives – unrealized gains (losses)^(a)	94		(72)
Total oil sales	483		256

Natural gas sales	653		483
Natural gas derivatives – realized gains (losses)^(a)	(16)		150
Natural gas derivatives – unrealized gains (losses)^(a)	231		30
Total natural gas sales	868		663

NGL sales	116		74
NGL derivatives – realized gains (losses)^(a)	1		—
NGL derivatives – unrealized gains (losses)^(a)	1		—
Total NGL sales	118		74
Total oil, natural gas and NGL sales	$	1,469	$	993

Average Sales Price – excluding gains (losses) on derivatives:
Oil ($ per bbl)	$	50.24	$	29.34
Natural gas ($ per mcf)	$	3.10	$	1.75
NGL ($ per bbl)	$	23.78	$	11.44
Oil equivalent ($ per boe)	$	24.13	$	13.28

Average Sales Price – including realized gains (losses) on derivatives:
Oil ($ per bbl)	$	51.72	$	37.74
Natural gas ($ per mcf)	$	3.02	$	2.29
NGL ($ per bbl)	$	24.04	$	11.44
Oil equivalent ($ per boe)	$	24.06	$	16.93

Interest Expense ($ in millions):
Interest expense^(b)	$	94	$	62
Interest rate derivatives – realized (gains) losses^(c)	(1)		(3)
Interest rate derivatives – unrealized (gains) losses^(c)	2		3
Total Interest Expense	$	95	$	62


(a)	Realized gains and losses include the following items: (i) settlements and accruals for settlements of nondesignated 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 and losses related to de-designated cash flow hedges originally designated to settle against current period production revenues. Unrealized gains and losses include the change in fair value of open derivatives scheduled to settle against future period production revenues offset by amounts reclassified as realized gains and 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 settlements related to the current period interest accrual and the effect of (gains) losses on early termination trades. 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, 2017		March 31, 2016

Beginning cash	$	882	$	825

Net cash provided by (used in) operating activities	99		(421)

Cash flows from investing activities:
Drilling and completion costs^(a)	(433)		(265)
Acquisitions of proved and unproved properties^(b)	(95)		(67)
Proceeds from divestitures of proved and unproved properties	892		62
Additions to other property and equipment^(c)	(3)		(10)
Proceeds from sales of other property and equipment	19		9
Other	—		(2)
Net cash provided by (used in) investing activities	380		(273)

Net cash used in financing activities	(1,112)		(115)
Change in cash and cash equivalents	(633)		(809)
Ending cash	$	249	$	16


(a)	Includes capitalized interest of $2 million and $2 million for the three months ended March 31, 2017 and 2016, respectively.
(b)	Includes capitalized interest of $49 million and $64 million for the three months ended March 31, 2017 and 2016, respectively.
(c)	Includes capitalized interest of a nominal amount and $1 million for the three months ended March 31, 2017 and 2016, 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, 2017
	$		Shares^(a)	$/Share^{(c) (d)}
Net income available to common stockholders	$	75	907	$	0.08

Adjustments:
Unrealized gains on commodity derivatives	(326)			(0.36)
Provision for legal contingencies	(2)			—
Impairments of fixed assets and other	391			0.43
Losses on purchases or exchanges of debt	7			0.01
Loss on exchange of preferred stock	41			0.05
Income tax expense (benefit)^(b)	—			—
Other	2			—
Adjusted net income available to common stockholders^(c) (Non-GAAP)	188		907	0.21

Preferred stock dividends	23			0.02
Earnings allocated to participating securities	1			—
Total adjusted net income attributable to Chesapeake^{(c) (d)}(Non-GAAP)	$	212	907	$	0.23


(a)	Weighted average common and common equivalent shares outstanding for GAAP and non-GAAP purposes do not include 208 million shares that were considered antidilutive for calculating earnings per share in accordance with GAAP.
(b)	Due to our valuation allowance position, no income tax effect from the adjustments has been included in determining adjusted net income.
(c)	Adjusted net income and adjusted earnings per common share are not measures of financial performance under accounting principles generally accepted in the United States (GAAP), and should not be considered as an alternative to net income available to common stockholders or earnings per share. Adjusted net income available to common stockholders and adjusted earnings 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 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 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.
(d)	Our presentation of diluted adjusted net income (loss) per share excludes shares considered antidilutive when calculating diluted earnings per share in accordance with GAAP.

CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS
(in millions, except per share data)
(unaudited)

THREE MONTHS ENDED:	March 31, 2016
	$		Shares^(a)	$/Share^{(b) (c)}
Net loss available to common stockholders	$	(1,111)	668	$	(1.66)

Adjustments:
Unrealized losses on commodity derivatives	42			0.06
Unrealized gains on supply contract derivatives	(20)			(0.03)
Provision for legal contingencies	33			0.05
Impairment of oil and natural gas properties	997			1.49
Impairments of fixed assets and other	38			0.06
Net gains on sales of fixed assets	(4)			(0.01)
Loss on sale of investment	10			0.01
Gains on purchases or exchanges of debt	(100)			(0.14)
Income tax expense (benefit)^(b)	—			—
Other	3			—
Adjusted net loss available to common stockholders^(c)(Non-GAAP)	(112)		668	(0.17)

Preferred stock dividends	43			0.06
Total adjusted net loss attributable to Chesapeake^{(c) (d)}(Non-GAAP)	$	(69)	668	$	(0.11)


(a)	Weighted average common and common equivalent shares outstanding for GAAP and non-GAAP purposes do not include 113 million shares that were considered antidilutive for calculating earnings per share in accordance with GAAP.
(b)	Due to our valuation allowance position, no income tax effect from the adjustments has been included in determining adjusted net income.
(c)	Adjusted net income and adjusted earnings per common share are not measures of financial performance under accounting principles generally accepted in the United States (GAAP), and should not be considered as an alternative to net income available to common stockholders or earnings per share. Adjusted net income available to common stockholders and adjusted earnings 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 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 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.
(d)	Our presentation of diluted adjusted net income (loss) per share excludes shares considered antidilutive when calculating diluted earnings per share in accordance with GAAP.

CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
($ in millions)
(unaudited)

THREE MONTHS ENDED:	March 31, 2017		March 31, 2016

CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	99	$	(421)
Changes in assets and liabilities	(113)		684
OPERATING CASH FLOW^(a)	$	(14)	$	263


THREE MONTHS ENDED:	March 31, 2017		March 31, 2016

NET INCOME (LOSS)	$	141	$	(1,068)
Interest expense	95		62
Income tax expense	1		—
Depreciation and amortization of other assets	21		29
Oil, natural gas and NGL depreciation, depletion and amortization	197		263
EBITDA^(b)	$	455	$	(714)


THREE MONTHS ENDED:	March 31, 2017		March 31, 2016

CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	99	$	(421)
Changes in assets and liabilities	(113)		684
Interest expense, net of unrealized gains (losses) on derivatives	93		59
Gains (losses) on commodity derivatives, net	322		181
Gains on supply contract derivatives, net	—		20
Cash (receipts) payments on commodity and supply contract derivative settlements, net	34		(267)
Stock-based compensation	(11)		(12)
Provision for legal contingencies	2		(33)
Impairment of oil and natural gas properties	—		(997)
Impairments of fixed assets and other	3		(33)
Net gains on sales of fixed assets	—		4
Investment activity	—		(10)
Gains (losses) on purchases or exchanges of debt	(6)		100
Other items	32		11
EBITDA^(b)	$	455	$	(714)


(a)	Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under GAAP. 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. Operating cash flow for the three months ended March 31, 2017 includes $290 million paid to assign an oil transportation agreement to a third party and $103 million paid to terminate future natural gas transportation commitments.

(b)	Ebitda represents net income before interest expense, income taxes, 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 under GAAP. Accordingly, it 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.

CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED EBITDA
($ in millions)
(unaudited)

THREE MONTHS ENDED:	March 31, 2017		March 31, 2016

EBITDA	$	455	$	(714)

Adjustments:
Unrealized gains on commodity derivatives	(326)		42
Unrealized gains on supply contract derivatives	—		(20)
Provision for legal contingencies	(2)		33
Impairment of oil and natural gas properties	—		997
Impairments of fixed assets and other	391		38
Net (gains) losses on sales of fixed assets	—		(4)
Loss on sale of investment	—		10
(Gains) losses on purchases or exchanges of debt	7		(100)
Net income attributable to noncontrolling interests	(1)		—
Other	1		—

Adjusted EBITDA^(a)	$	525	$	282


(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.

CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF PV-9 AND PV-10 TO STANDARDIZED MEASURE
($ in millions)
(unaudited)

PV-9 is a non-GAAP metric used in the determination of the value of collateral under Chesapeake's credit facility. PV-10 is a non-GAAP metric used by the industry, investors and analysts to estimate the present value, discounted at 10% per annum, of estimated future cash flows of the company's estimated proved reserves before income tax. The following table shows the reconciliation of PV-9 and PV-10 to the company's standardized measure of discounted future net cash flows, the most directly comparable GAAP measure, for the year ended December 31, 2016 and for the interim period ended March 31, 2017. Management believes that PV-9 provides useful information to investors regarding the company's collateral position and that PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, management believes the use of a pre-tax measure is valuable for evaluating the company. Neither PV-9 nor PV-10 should be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP. With respect to PV-9 and PV-10 calculated as of an interim date, it is not practical to calculate taxes for the related interim period because GAAP does not provide for disclosure of standardized measure on an interim basis.

PV-9 – March 31, 2017 @ NYMEX Strip	$	9,237
Less: Change in discount factor from 9 to 10	(503)
PV-10 – March 31, 2017 @ NYMEX Strip	8,734
Less: Change in pricing assumption from NYMEX Strip to SEC	(2,281)
PV-10 – March 31, 2017 @ SEC	6,453
Less: Change in PV-10 from 12/31/16 to 3/31/2017	(2,048)
PV-10 – December 31, 2016 @ SEC	4,405
Less: Present value of future income tax discounted at 10%	(26)
Standardized measure of discounted future cash flows – December 31, 2016	$	4,379

CHESAPEAKE ENERGY CORPORATION
MANAGEMENT'S OUTLOOK AS OF MAY 3, 2017

Chesapeake periodically provides guidance on certain factors that affect the company's future financial performance. New information or changes from the company's February 14, 2017 Outlook are italicized bold below.

	Year Ending 12/31/2017
Adjusted Production Growth^(a)	*0% to 4%*
Absolute Production
Liquids - mmbbls	*52.5 - 55.0*
Oil - mmbbls	*33.5 - 35.0*
NGL - mmbbls	*19.0 - 20.0*
Natural gas - bcf	*870 - 900*
Total absolute production - mmboe	*197.5 - 205.0*
Absolute daily rate - mboe	*541 - 562*
Estimated Realized Hedging Effects^(b) (based on 5/1/17 strip prices):
Oil - $/bbl	$2.51
Natural gas - $/mcf	($0.16)
NGL - $/bbl	$0.10
Estimated Basis to NYMEX Prices:
Oil - $/bbl	*$1.35 - $1.55*
Natural gas - $/mcf	*$0.30 - $0.40*
NGL - $/bbl	*$3.75 - $4.15*
Operating Costs per Boe of Projected Production:
Production expense	$2.50 - $2.70
Gathering, processing and transportation expenses	$7.00 - $7.50
Oil - $/bbl	*$4.05 - $4.25*
Natural Gas - $/mcf	$1.25 - $1.35
NGL - $/bbl	$8.10 - $8.50
Production taxes	$0.40 - $0.50
General and administrative^(c)	$1.20 - $1.30
Stock-based compensation (noncash)	$0.10 - $0.20
DD&A of natural gas and liquids assets	$4.00 - $5.00
Depreciation of other assets	$0.40 - $0.50
Interest expense^(d)	$1.85 - $1.95
Marketing, gathering and compression net margin^(e)	($80) - ($60)
Book Tax Rate	0%
Capital Expenditures ($ in millions)^(f)	*$1,900 - $2,300*
Capitalized Interest ($ in millions)	$200
Total Capital Expenditures ($ in millions)	*$2,100 - $2,500*


(a)	Based on 2016 production of 537 mboe per day, adjusted for 2016 and 2017 sales.
(b)	Includes expected settlements for commodity 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.
(d)	Excludes unrealized gains (losses) on interest rate derivatives.
(e)	Excludes non-cash amortization of approximately $22 million related to the buydown of a transportation agreement.
(f)	Includes capital expenditures for drilling and completion, leasehold, geological and geophysical costs, rig termination payments and other property and plant and equipment. Excludes any additional proved property acquisitions.

Oil, Natural Gas and Natural Gas Liquids Hedging Activities

Chesapeake enters into commodity 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 May 1, 2017, the company had downside protection, through open swaps, on a portion of its remaining 2017 oil production at an average price of $50.25 per bbl. The company had downside price protection, through open swaps and two-way collars, on a portion of its remaining 2017 natural gas production at an average price of $3.05 per mcf. Chesapeake also had downside price protection, through open swaps, on a portion of its remaining 2017 ethane production at an average price of $0.28 per gallon.

In addition, the company had downside protection, through open swaps and two-way collars, on a portion of its 2018 natural gas production at an average price of $3.12 per mcf and a portion of its 2018 oil production at an average price of $51.43 per bbl.

The company's crude oil hedging positions as of May 1, 2017 were as follows:

Open Crude Oil Swaps; Gains (Losses) from Closed
Crude Oil Trades

	Open Swaps (mbbls)	Avg. NYMEX Price of Open Swaps		Total Gains from Closed Trades ($ in millions)
Q2 2017	5,915	$	50.12	$	23
Q3 2017	5,612	$	50.27	23
Q4 2017	5,612	$	50.36	23
Total 2017	17,139	$	50.25	$	69
Total 2018 – 2022	1,825	$	51.43	$	(13)

Crude Oil Net Written Call Options

	Call Options (mbbls)	Avg. NYMEX Strike Price
Q2 2017	1,320	$	83.50
Q3 2017	1,334	$	83.50
Q4 2017	1,334	$	83.50
Total 2017	3,988	$	83.50

The company's natural gas hedging positions as of May 1, 2017 were as follows:

Open Natural Gas Swaps; Losses from Closed
Natural Gas Trades

	Open Swaps (bcf)	Avg. NYMEX Price of Open Swaps		Total Losses from Closed Trades ($ in millions)
Q2 2017	157	$	2.96	$	(1)
Q3 2017	158	$	3.00	(2)
Q4 2017	164	$	3.16	(3)
Total 2017	479	$	3.04	$	(6)
Total 2018 – 2022	191	$	3.15	$	(69)

Natural Gas Two-Way Collars

	Open Collars (bcf)	Avg. NYMEX Bought Put Price		Avg. NYMEX Sold Call Price
Q4 2017	24	$	3.25	$	3.68
Total 2017	24	$	3.25	$	3.68
Total 2018	47	$	3.00	$	3.25

Natural Gas Net Written Call Options

	Call Options (bcf)	Avg. NYMEX Strike Price
Q2 2017	12	$	9.43
Q3 2017	12	$	9.43
Q4 2017	12	$	9.43
Total 2017	36	$	9.43
Total 2018 – 2020	66	$	12.00

Natural Gas Basis Protection Swaps

	Volume (bcf)	Avg. NYMEX plus/(minus)
Q2 2017	5	$	(0.46)
Q3 2017	6	$	(0.46)
Q4 2017	6	$	(0.46)
Total 2017	17	$	(0.46)
Total 2018	1	$	(1.03)