Chesapeake Energy Corporation Reports 2017 Second Quarter Financial And Operational Results

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Aug 03, 2017, 07:00 ET

OKLAHOMA CITY, Aug. 3, 2017 /PRNewswire/ -- Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operational results for the 2017 second quarter plus other recent developments. Highlights include:

Average 2017 second quarter production of 527,600 boe per day, flat sequentially
Average 2017 second quarter oil production of 88,400 barrels per day, up 6% sequentially
Total production averaged approximately 548,300 boe per day, including a peak rate of 90,400 barrels of oil, in July; goal of reaching 100,000 barrels of oil per day by year-end on track
Actively managing capital expenditures program for remainder of 2017, dropping to 14 rigs by year-end 2017 from 18 rigs today
Approximately $360 million of expected asset sales closed or under signed purchase and sale agreements year to date
Marcellus Shale well achieves record rate of more than 61,000 mcf per day

Doug Lawler, Chesapeake's Chief Executive Officer, commented, "Our assets continue to deliver improving well results due to longer laterals and enhanced completion techniques, with a new record operated well in the Marcellus being a prime example of this. We expect our total production to move higher throughout the year, driven by large turn-in-line projects underway in the Eagle Ford, Utica and Powder River Basin operating areas. This has already started, as we averaged approximately 548,300 barrels of oil equivalent per day, including a peak rate of 90,400 barrels of oil production, for the month of July.

"Despite our anticipated growth, we are actively managing our 2017 capital program to the highest-return investments in our portfolio or reducing spending in certain areas altogether. Our planned activity levels result in a reduction of our rig count and wells placed on production during the last six months of the year, as our 2017 capital program has been focused on restoring our cash flow generating capability, improving our margins and growing value. Improving our balance sheet is our number one priority at Chesapeake, and we will remain flexible in our capital spending program, both for the remainder of 2017 and in 2018, as we continue to drive toward cash flow neutrality."

2017 Second Quarter Results

For the 2017 second quarter, Chesapeake's revenues increased by 41% year over year 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. Chesapeake's revenues decreased 17% quarter over quarter due to a decrease in the average realized commodity prices for the company's production, primarily the seasonal decrease in natural gas prices and lower unrealized hedging gains. Average daily production for the 2017 second quarter of approximately 527,600 barrels of oil equivalent (boe) increased by 2% sequentially, adjusted for asset sales, and consisted of approximately 88,400 barrels (bbls) of oil, 2.294 billion cubic feet (bcf) of natural gas and 56,900 bbls of natural gas liquids (NGL).

Average production expenses during the 2017 second quarter were $2.92 per boe, while G&A expenses (including stock-based compensation) during the 2017 second quarter were $1.45 per boe. Combined production and G&A expenses (including stock-based compensation) during the 2017 second quarter were $4.37 per boe, an increase of 7% year over year and an increase of 4% quarter over quarter driven by a decrease in producing well count due to divestitures resulting in reduced cost recovery in G&A. Gathering, processing and transportation expenses during the 2017 second quarter were $7.44 per boe, a decrease of 7% year over year and a nominal decrease quarter over quarter.

Chesapeake reported net income available to common stockholders of $470 million, or $0.47 per diluted share, while the company's EBITDA for the 2017 second quarter was $812 million. Adjusting for unrealized gains on commodity derivatives, impairments related to the reduction of transportation commitments on the Gulf Crossing pipeline, the gain on repurchase of debt and other items that are typically excluded by securities analysts, the 2017 second quarter adjusted net income attributable to Chesapeake was $146 million, or $0.18 per diluted share, while the company's adjusted EBITDA was $461 million. Reconciliations of financial measures calculated in accordance with GAAP to non-GAAP measures are provided on pages 12 – 18 of this release.

Capital Spending Overview

Chesapeake's total capital investments were approximately $667 million during the 2017 second quarter, compared to approximately $576 million in the 2017 first quarter and $456 million in the 2016 second quarter. A summary of the company's guidance for 2017 is provided under "Management's Outlook as of August 3, 2017," beginning on page 20.

	2017		2017		2016
Operated activity comparison	Q2		Q1		Q2
Average rig count	19		16		9
Gross wells spud	102		87		49
Gross wells completed	107		99		131
Gross wells connected	94		76		141

Type of cost ($ in millions)
Drilling and completion costs	$	596	$	506	$	337
Exploration costs, leasehold and additions to other PP&E	24		19		56
Subtotal capital expenditures	$	620	$	525	$	393
Capitalized interest	47		51		63
Total capital expenditures	$	667	$	576	$	456

Balance Sheet and Liquidity

As of June 30, 2017, Chesapeake's principal debt balance was approximately $9.7 billion with $13 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 June 30, 2017 was approximately $3.1 billion, which included cash on hand and a borrowing capacity of approximately $3.1 billion under the company's senior secured revolving credit facility. At June 30, 2017, the company had $575 million of outstanding borrowings under the revolving credit facility and had used $100 million of the revolving credit facility for various letters of credit. The company's borrowing base under the senior secured revolving credit facility was reaffirmed by the lenders at $3.785 billion on June 15, 2017.

Asset Divestitures Update

Year to date, Chesapeake has sold or agreed to sell multiple producing properties for approximately $360 million to various private buyers, excluding the proceeds from the company's Haynesville Shale divestitures announced in December 2016 that closed in 2017. As of June 30, 2017, Chesapeake has closed $95 million in asset sales with approximately $265 million pending and expected to close by the end of the 2017 third quarter, subject to certain customary post-closing adjustments.

Operations Update

Chesapeake's average daily production for the 2017 second quarter was approximately 527,600 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	2017	2016
Operating area net production (mboe/day)	Q2	Q1	Q2
Eagle Ford	100	96	92
Haynesville	121	121	126
Marcellus	135	146	134
Utica	97	96	137
Mid-Continent	59	57	78
Powder River Basin	16	12	16
Barnett	—	—	65
Other	—	—	9
Total production	528	528	657

Chesapeake is currently utilizing 18 drilling rigs (below the 2017 second quarter average of 19) across its operating areas, seven of which are located in the Eagle Ford Shale, four in the Mid-Continent area, three in the Haynesville Shale, two in the Powder River Basin (PRB) and two in Northeast Appalachia. Chesapeake plans to exit 2017 utilizing 14 rigs and intends to place on production approximately 20 fewer gross operated wells in 2017.

In the Eagle Ford Shale, Chesapeake placed its first Upper Eagle Ford Shale well, the Blakeway 3D DIM 2H, on production in June 2017 at a peak rate of 1,759 boe per day (86% oil). Chesapeake expects to place on production up to 100 wells in South Texas in the second half of 2017, compared to 61 wells in the first half of 2017.

In the PRB, Chesapeake's first well targeting the Mowry formation, the Combs 17-33-70 USA B MW 40H, was drilled with a 4,200-foot lateral and placed on production in July 2017. This well was drilled in the gas window to test productivity, permeability and pressure and near current pipe infrastructure to minimize cycle time. This well has reached a peak rate of 6,629 thousand cubic feet (mcf) of natural gas per day and is expected to climb as it unloads fracture stimulation fluid. Chesapeake's next Mowry tests are planned to be drilled in 2018 in the wet gas window with longer laterals.

The company's second Turner well, the Rankin 5-33-68 A TR 1H, was placed on production in May 2017 and reached a peak rate of 2,886 boe per day (51% oil). Chesapeake plans to place on production up to four additional wells in the Turner formation by year-end 2017. The company also expects to place up to 14 new wells targeting the Sussex formation by year-end 2017. Currently, Chesapeake plans to add a third rig in the PRB operating area in October 2017 and expects to place on production up to 19 wells in the second half of 2017, compared to nine wells in the first half of 2017.

In the Marcellus Shale, the company placed the McGavin E WYO 6H well on production with a 10,429-foot lateral and enhanced completion. This well has reached a peak rate of 61,759 mcf of gas per day after six days of production, making it the highest-rate operated well in the Marcellus Shale in the company's history. Chesapeake has approximately 2.2 bcf of gas per day of gross productive capacity and expects to maintain its gross production at or around its total capacity through the remainder of 2017, depending on gas prices. Chesapeake expects to place on production up to 40 wells in the Marcellus Shale in the second half of 2017, compared to 11 wells in the first half of 2017.

In the Haynesville Shale, the Hunter 20&17-12-12 1H ALT well located in DeSoto Parish was placed on production in July 2017 with a 7,495-foot lateral. This well reached a peak rate of 38,840 mcf of gas per day, resulting in one of the highest rates per lateral foot in the company's history from the area. Chesapeake expects to place on production up to 23 wells in the Haynesville Shale in the second half of 2017, compared to 17 wells in the first half of 2017.

Chesapeake re-completed its first Haynesville well utilizing a new production liner in July 2017. After installing the new liner, Chesapeake re-stimulated the well and returned it to production at a peak rate of approximately 9,043 mcf of gas per day, compared to producing 65 mcf of gas per day before the re-stimulation treatment. This recompletion was performed on one of the first wells Chesapeake drilled in the Haynesville. Drilled in 2008, the well had an initial peak production of 4,705 mcf of gas per day producing from a 2,990-foot lateral in 2008.

Key Financial and Operational Results

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

	Three Months Ended
	06/30/17	03/31/17	06/30/16
Oil equivalent production (in mmboe)	48	48	60
Oil production (in mmbbls)	8	8	8
Average realized oil price ($/bbl)^(a)	51.65	51.72	44.31
Natural gas production (in bcf)	209	211	269
Average realized natural gas price ($/mcf)^(a)	2.71	3.02	1.97
NGL production (in mmbbls)	5	5	7
Average realized NGL price ($/bbl)^(a)	18.51	24.04	12.88
Production expenses ($/boe)	(2.92)	(2.84)	(3.05)
Gathering, processing and transportation expenses ($/boe)	(7.44)	(7.47)	(8.04)
Oil - ($/bbl)	(3.70)	(3.85)	(3.64)
Natural Gas - ($/mcf)	(1.37)	(1.35)	(1.48)
NGL - ($/bbl)	(7.87)	(8.47)	(7.61)
Production taxes ($/boe)	(0.42)	(0.47)	(0.32)
General and administrative expenses ($/boe)^(b)	(1.20)	(1.18)	(0.86)
Stock-based compensation ($/boe)	(0.25)	(0.17)	(0.16)
DD&A of oil and natural gas properties ($/boe)	(4.21)	(4.15)	(4.64)
DD&A of other assets ($/boe)	(0.43)	(0.44)	(0.48)
Interest expense ($/boe)^(a)	(1.92)	(1.97)	(1.00)
Marketing, gathering and compression net margin ($ in millions)^(c)	(25)	(44)	(25)
Net cash provided by (used in) operating activities ($ in millions)	(157)	99	95
Net cash provided by (used in) operating activities ($/boe)	(3.27)	2.06	1.58
Operating cash flow ($ in millions)^(d)	303	(14)	176
Operating cash flow ($/boe)	6.31	(0.29)	2.94
Adjusted ebitda ($ in millions)^(e)	461	525	252
Adjusted ebitda ($/boe)	9.60	11.05	4.21
Net income (loss) available to common stockholders ($ in millions)	470	75	(1,818)
Income (loss) per share – diluted ($)	0.47	0.08	(2.51)
Adjusted net income (loss) attributable to Chesapeake ($ in millions)^(f)	146	212	(115)
Adjusted income (loss) per share - diluted ($)^(g)	0.18	0.23	(0.16)


(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 June 30, 2016, unrealized gains (losses) on supply contract derivatives, but excludes depreciation and amortization of other assets. For the three months ended June 30, 2016, unrealized losses on supply contract derivatives were $37 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 June 30, 2017 includes $23 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 18.
(f)	Defined as net income (loss) attributable to Chesapeake, as adjusted to remove the effects of certain items detailed on pages 12 - 15.
(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 Second Quarter Financial and Operational Results Conference Call Information

A conference call to discuss this release has been scheduled on Thursday, August 3, 2017 at 9:00 am EDT. The telephone number to access the conference call is 719-785-1749 or toll-free 888-855-5428. The passcode for the call is 9224968. 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 9224968. 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, 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, general and administrative expenses, capital expenditures, the timing of anticipated 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; the effectiveness of our remediation plan for a material weakness; 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:

Brad Sylvester, CFA

(405) 935-8870

[email protected]

MEDIA CONTACT:

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 June 30,
	2017		2016
REVENUES:
Oil, natural gas and NGL	$	1,279	$	440
Marketing, gathering and compression	1,002		1,182
Total Revenues	2,281		1,622
OPERATING EXPENSES:
Oil, natural gas and NGL production	140		182
Oil, natural gas and NGL gathering, processing and transportation	357		481
Production taxes	21		19
Marketing, gathering and compression	1,027		1,207
General and administrative	70		61
Restructuring and other termination costs	—		3
Provision for legal contingencies	17		71
Oil, natural gas and NGL depreciation, depletion and amortization	202		277
Depreciation and amortization of other assets	21		29
Impairment of oil and natural gas properties	—		1,070
Impairments of fixed assets and other	26		6
Net (gains) losses on sales of fixed assets	1		(1)
Total Operating Expenses	1,882		3,405
INCOME (LOSS) FROM OPERATIONS	399		(1,783)
OTHER INCOME (EXPENSE):
Interest expense	(93)		(62)
Losses on investments	—		(2)
Gains on purchases or exchanges of debt	191		68
Other income (expense)	(1)		3
Total Other Income	97		7
INCOME (LOSS) BEFORE INCOME TAXES	496		(1,776)
Income Tax Expense	1		—
NET INCOME (LOSS)	495		(1,776)
Net income attributable to noncontrolling interests	(1)		—
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	494		(1,776)
Preferred stock dividends	(16)		(42)
Earnings allocated to participating securities	(8)		—
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$	470	$	(1,818)
EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	0.52	$	(2.51)
Diluted	$	0.47	$	(2.51)
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic	908		724
Diluted	1,114		724

CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS ($ in millions except per share data) (unaudited)
	Six Months Ended June 30,
	2017		2016
REVENUES:
Oil, natural gas and NGL	$	2,748	$	1,433
Marketing, gathering and compression	2,286		2,142
Total Revenues	5,034		3,575
OPERATING EXPENSES:
Oil, natural gas and NGL production	275		388
Oil, natural gas and NGL gathering, processing and transportation	712		963
Production taxes	43		37
Marketing, gathering and compression	2,355		2,149
General and administrative	135		109
Restructuring and other termination costs	—		3
Provision for legal contingencies	15		104
Oil, natural gas and NGL depreciation, depletion and amortization	399		540
Depreciation and amortization of other assets	42		58
Impairment of oil and natural gas properties	—		2,067
Impairments of fixed assets and other	417		44
Net (gains) losses on sales of fixed assets	1		(5)
Total Operating Expenses	4,394		6,457
INCOME (LOSS) FROM OPERATIONS	640		(2,882)
OTHER INCOME (EXPENSE):
Interest expense	(188)		(124)
Losses on investments	—		(2)
Loss on sale of investment	—		(10)
Gains on purchases or exchanges of debt	184		168
Other income	2		6
Total Other Income (Expense)	(2)		38
INCOME (LOSS) BEFORE INCOME TAXES	638		(2,844)
Income Tax Expense	2		—
NET INCOME (LOSS)	636		(2,844)
Net income attributable to noncontrolling interests	(2)		—
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	634		(2,844)
Preferred stock dividends	(39)		(85)
Loss on exchange of preferred stock	(41)		—
Earnings allocated to participating securities	(7)		—
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$	547	$	(2,929)
EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	0.60	$	(4.21)
Diluted	$	0.59	$	(4.21)
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic	907		695
Diluted	1,053		695

CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS ($ in millions) (unaudited)
	June 30, 2017		December 31, 2016

Cash and cash equivalents	$	13	$	882
Other current assets	1,234		1,260
Total Current Assets	1,247		2,142

Property and equipment, net	10,418		10,609
Other assets	255		277
Total Assets	$	11,920	$	13,028

Current liabilities	$	2,158	$	3,648
Long-term debt, net	9,850		9,938
Other long-term liabilities	596		645
Total Liabilities	12,604		14,231

Preferred stock	1,671		1,771
Noncontrolling interests	254		257
Common stock and other stockholders' equity (deficit)	(2,609)		(3,231)
Total Equity (Deficit)	(684)		(1,203)

Total Liabilities and Equity	$	11,920	$	13,028

Common shares outstanding (in millions)	908		896
Principal amount of debt outstanding	$	9,710	$	9,989

CHESAPEAKE ENERGY CORPORATION SUPPLEMENTAL DATA – OIL, NATURAL GAS AND NGL PRODUCTION, SALES AND INTEREST EXPENSE (unaudited)
	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Net Production:
Oil (mmbbl)	8		8		16		17
Natural gas (bcf)	209		269		420		546
NGL (mmbbl)	5		7		10		13
Oil equivalent (mmboe)	48		60		96		121
Oil, natural gas and NGL Sales ($ in millions):
Oil sales	$	383	$	355	$	761	$	610
Oil derivatives – realized gains (losses)^(a)	33		11		44		84
Oil derivatives – unrealized gains (losses)^(a)	47		(168)		141		(240)
Total oil sales	463		198		946		454

Natural gas sales	601		440		1,254		923
Natural gas derivatives – realized gains (losses)^(a)	(36)		92		(52)		242
Natural gas derivatives – unrealized gains (losses)^(a)	156		(365)		387		(335)
Total natural gas sales	721		167		1,589		830

NGL sales	95		89		211		163
NGL derivatives – realized gains (losses)^(a)	1		(3)		2		(3)
NGL derivatives – unrealized gains (losses)^(a)	(1)		(11)		—		(11)
Total NGL sales	95		75		213		149

Total oil, natural gas and NGL sales	$	1,279	$	440	$	2,748	$	1,433
Average Sales Price (excluding gains (losses) on derivatives):
Oil ($ per bbl)	$	47.51	$	43.00	$	48.83	$	35.98
Natural gas ($ per mcf)	$	2.88	$	1.63	$	2.99	$	1.69
NGL ($ per bbl)	$	18.36	$	13.37	$	20.99	$	12.43
Oil equivalent ($ per boe)	$	22.46	$	14.76	$	23.29	$	14.01
Average Sales Price (including realized gains (losses) on derivatives):
Oil ($ per bbl)	$	51.65	$	44.31	$	51.68	$	40.93
Natural gas ($ per mcf)	$	2.71	$	1.97	$	2.87	$	2.14
NGL ($ per bbl)	$	18.51	$	12.88	$	21.19	$	12.17
Oil equivalent ($ per boe)	$	22.42	$	16.43	$	23.23	$	16.68
Interest Expense ($ in millions):
Interest expense^(b)	$	93	$	63	$	187	$	125
Interest rate derivatives – realized (gains) losses^(c)	(1)		(3)		(2)		(6)
Interest rate derivatives – unrealized (gains) losses^(c)	1		2		3		5
Total Interest Expense	$	93	$	62	$	188	$	124


(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 and 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 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:	June 30, 2017		June 30, 2016

Beginning cash	$	249	$	16

Net cash provided by (used in) operating activities	(157)		95

Cash flows from investing activities:
Drilling and completion costs^(a)	(598)		(344)
Acquisitions of proved and unproved properties^(b)	(67)		(359)
Proceeds from divestitures of proved and unproved properties	59		833
Additions to other property and equipment^(c)	(4)		(15)
Proceeds from sales of other property and equipment	7		61
Other	—		(2)
Net cash provided by (used in) investing activities	(603)		174

Net cash provided by (used in) financing activities	524		(281)
Change in cash and cash equivalents	(236)		(12)
Ending cash	$	13	$	4


(a)	Includes capitalized interest of $3 million and $1 million for the three months ended June 30, 2017 and 2016, respectively.
(b)	Includes capitalized interest of $44 million and $60 million for the three months ended June 30, 2017 and 2016, respectively.
(c)	Includes capitalized interest of a nominal amount for the three months ended June 30, 2017 and 2016, respectively.

CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED CASH FLOW DATA ($ in millions) (unaudited)
SIX MONTHS ENDED:	June 30, 2017		June 30, 2016

Beginning cash	$	882	$	825

Net cash used in operating activities	(58)		(326)

Cash flows from investing activities:
Drilling and completion costs^(a)	(1,031)		(609)
Acquisitions of proved and unproved properties^(b)	(162)		(426)
Proceeds from divestitures of proved and unproved properties	951		964
Additions to other property and equipment^(c)	(7)		(25)
Proceeds from sales of other property and equipment	26		70
Cash paid for title defects	—		(69)
Other	—		(4)
Net cash used in investing activities	(223)		(99)

Net cash used in financing activities	(588)		(396)
Change in cash and cash equivalents	(869)		(821)
Ending cash	$	13	$	4


(a)	Includes capitalized interest of $5 million and $3 million for the six months ended June 30, 2017 and 2016, respectively.
(b)	Includes capitalized interest of $93 million and $124 million for the six months ended June 30, 2017 and 2016, respectively.
(c)	Includes capitalized interest of a nominal amount and $1 million for the six months ended June 30, 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:	June 30, 2017
	$		$/Diluted Share^(b)(c)
Net income available to common stockholders (GAAP)	$	470	$	0.47

Adjustments:
Unrealized gains on commodity derivatives	(202)		(0.18)
Provision for legal contingencies	17		0.02
Impairments of fixed assets and other	26		0.02
Net loss on sales of fixed assets	1		—
Gains on purchases or exchanges of debt	(191)		(0.17)
Income tax expense (benefit)^(a)	—		—
Other	1		—
Adjusted net income available to common stockholders^(b) (Non-GAAP)	122		0.16

Preferred stock dividends	16		0.01
Earnings allocated to participating securities	8		0.01
Total adjusted net income attributable to Chesapeake^{(b) (c)}(Non-GAAP)	$	146	$	0.18


(a)	Due to our valuation allowance position, no income tax effect from the adjustments has been included in determining adjusted net income.
(b)	Adjusted net income available to common stockholders and total adjusted net income attributable to Chesapeake, both in the aggregate and per dilutive 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.
(c)	Our presentation of diluted adjusted net income (loss) per share excludes 1 million 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:	June 30, 2016
	$		$/Diluted Share^(b)(c)
Net loss available to common stockholders (GAAP)	$	(1,818)	$	(2.51)

Adjustments:
Unrealized losses on commodity derivatives	544		0.75
Unrealized losses on supply contract derivatives	37		0.05
Restructuring and other termination costs	3		—
Provision for legal contingencies	71		0.10
Impairment of natural gas properties	1,070		1.48
Impairments of fixed assets and other	6		0.01
Net gains on sales of fixed assets	(1)		—
Gains on purchases or exchanges of debt	(68)		(0.09)
Income tax expense (benefit)^(a)	—		—
Other	(1)		—
Adjusted net loss available to common stockholders^(b) (Non-GAAP)	(157)		(0.22)

Preferred stock dividends	42		0.06
Total adjusted net loss attributable to Chesapeake^{(b) (c)}(Non-GAAP)	$	(115)	$	(0.16)


(a)	Due to our valuation allowance position, no income tax effect from the adjustments has been included in determining adjusted net income.
(b)	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 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.
(c)	Our presentation of diluted adjusted net income (loss) per share excludes 114 million 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)
SIX MONTHS ENDED:	June 30, 2017
	$		$/Diluted Share^(b)(c)
Net income available to common stockholders (GAAP)	$	547	$	0.59

Adjustments:
Unrealized gains on commodity derivatives	(528)		(0.51)
Provision for legal contingencies	15		0.01
Impairments of fixed assets and other	417		0.40
Net loss on sales of fixed assets	1		—
Gains on purchases or exchanges of debt	(184)		(0.17)
Loss on exchange of preferred stock	41		0.04
Income tax expense (benefit)^(a)	—		—
Other	3		—
Adjusted net income available to common stockholders^(b) (Non-GAAP)	312		0.36

Preferred stock dividends	39		0.04
Earnings allocated to participating securities	7		0.01
Total adjusted net income attributable to Chesapeake^{(b) (c)}(Non-GAAP)	$	358	$	0.41


(a)	Due to our valuation allowance position, no income tax effect from the adjustments has been included in determining adjusted net income.
(b)	Adjusted net income available to common stockholders and total adjusted net income attributable to Chesapeake, both in the aggregate and per dilutive 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.
(c)	Our presentation of diluted adjusted net income (loss) per share excludes 62 million 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)
SIX MONTHS ENDED:	June 30, 2016
	$		$/Diluted Share^(b)(c)
Net loss available to common stockholders (GAAP)	$	(2,929)	(4.21)

Adjustments:
Unrealized losses on commodity derivatives	586		0.84
Unrealized losses on supply contract derivatives	17		0.02
Restructuring and other termination costs	3		0.01
Provision for legal contingencies	104		0.15
Impairment of natural gas properties	2,067		2.97
Impairments of fixed assets and other	44		0.06
Net gains on sales of fixed assets	(5)		(0.01)
Loss on sale of investment	10		0.01
Gains on purchases or exchanges of debt	(168)		(0.24)
Income tax expense (benefit)^(a)	—		—
Other	3		0.01
Adjusted net loss available to common stockholders^(b) (Non-GAAP)	(268)		(0.39)

Preferred stock dividends	85		0.13
Total adjusted net loss attributable to Chesapeake^{(b) (c)}(Non-GAAP)	$	(183)	$	(0.26)


(a)	Due to our valuation allowance position, no income tax effect from the adjustments has been included in determining adjusted net income.
(b)	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 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.
(c)	Our presentation of diluted adjusted net income (loss) per share excludes 113 million 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:	June 30, 2017		June 30, 2016

CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	(157)	$	95
Changes in assets and liabilities	460		81
OPERATING CASH FLOW^(a)	$	303	$	176

THREE MONTHS ENDED:	June 30, 2017		June 30, 2016

NET INCOME (LOSS)	$	495	$	(1,776)
Interest expense	93		62
Income tax expense	1		—
Depreciation and amortization of other assets	21		29
Oil, natural gas and NGL depreciation, depletion and amortization	202		277
EBITDA^(b)	$	812	$	(1,408)

THREE MONTHS ENDED:	June 30, 2017		June 30, 2016

CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	(157)	$	95
Changes in assets and liabilities	460		81
Interest expense, net of unrealized gains (losses) on derivatives	92		60
Gains (losses) on commodity derivatives, net	200		(444)
Losses on supply contract derivatives, net	—		(37)
Cash (receipts) payments on commodity and supply contract derivative settlements, net	32		(119)
Stock-based compensation	(16)		(13)
Restructuring and other termination costs	—		(3)
Provision for legal contingencies	(17)		(71)
Impairment of oil and natural gas properties	—		(1,070)
Impairments of fixed assets and other	(4)		(1)
Net gains (losses) on sales of fixed assets	(1)		1
Investment activity	—		(2)
Gains on purchases or exchanges of debt	191		68
Other items	32		47
EBITDA^(b)	$	812	$	(1,408)


(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 June 30, 2017 includes $23 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 flows from operating activities prepared in accordance with GAAP.

CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF OPERATING CASH FLOW AND EBITDA ($ in millions) (unaudited)
SIX MONTHS ENDED:	June 30, 2017		June 30, 2016

CASH USED IN OPERATING ACTIVITIES	$	(58)	$	(326)
Changes in assets and liabilities	347		765
OPERATING CASH FLOW^(a)	$	289	$	439

SIX MONTHS ENDED:	June 30, 2017		June 30, 2016

NET INCOME (LOSS)	$	636	$	(2,844)
Interest expense	188		124
Income tax expense	2		—
Depreciation and amortization of other assets	42		58
Oil, natural gas and NGL depreciation, depletion and amortization	399		540
EBITDA^(b)	$	1,267	$	(2,122)

SIX MONTHS ENDED:	June 30, 2017		June 30, 2016

CASH USED IN OPERATING ACTIVITIES	$	(58)	$	(326)
Changes in assets and liabilities	347		765
Interest expense, net of unrealized gains (losses) on derivatives	185		119
Gains (losses) on commodity derivatives, net	522		(263)
Losses on supply contract derivatives, net	—		(17)
Cash (receipts) payments on commodity and supply contract derivative settlements, net	66		(386)
Stock-based compensation	(27)		(25)
Restructuring and other termination costs	—		(3)
Provision for legal contingencies	(15)		(104)
Impairment of oil and natural gas properties	—		(2,067)
Impairments of fixed assets and other	(1)		(34)
Net gains (losses) on sales of fixed assets	(1)		5
Investment activity	—		(12)
Gains on purchases or exchanges of debt	185		168
Other items	64		58
EBITDA^(b)	$	1,267	$	(2,122)


(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 six months ended June 30, 2017 includes $290 million paid to assign an oil transportation agreement to a third party and $126 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 flows from operating activities prepared in accordance with GAAP.

CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED EBITDA ($ in millions) (unaudited)
THREE MONTHS ENDED:	June 30, 2017		June 30, 2016

EBITDA	$	812	$	(1,408)

Adjustments:
Unrealized (gains) losses on commodity derivatives	(202)		544
Unrealized losses on supply contract derivatives	—		37
Restructuring and other termination costs	—		3
Provision for legal contingencies	17		71
Impairment of oil and natural gas properties	—		1,070
Impairments of fixed assets and other	26		6
Net (gains) losses on sales of fixed assets	1		(1)
Gains on purchases or exchanges of debt	(191)		(68)
Net income attributable to noncontrolling interests	(1)		—
Other	(1)		(2)

Adjusted EBITDA^(a)	$	461	$	252

CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED EBITDA ($ in millions) (unaudited)
SIX MONTHS ENDED:	June 30, 2017		June 30, 2016

EBITDA	$	1,267	$	(2,122)

Adjustments:
Unrealized (gains) losses on commodity derivatives	(528)		586
Unrealized losses on supply contract derivatives	—		17
Restructuring and other termination costs	—		3
Provision for legal contingencies	15		104
Impairment of oil and natural gas properties	—		2,067
Impairments of fixed assets and other	417		44
Net (gains) losses on sales of fixed assets	1		(5)
Loss on sale of investment	—		10
Gains on purchases or exchanges of debt	(184)		(168)
Net income attributable to noncontrolling interests	(2)		—
Other	—		(2)

Adjusted EBITDA^(a)	$	986	$	534


(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 June 30, 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 – June 30, 2017 @ NYMEX Strip	$	8,960
Less: Change in discount factor from 9 to 10	(512)
PV-10 – June 30, 2017 @ NYMEX Strip	8,448
Less: Change in pricing assumption from NYMEX Strip to SEC	(587)
PV-10 – June 30, 2017 @ SEC	7,861
Less: Change in PV-10 from 12/31/16 to 6/30/2017	(3,456)
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 AUGUST 2, 2017

Chesapeake periodically provides guidance on certain factors that affect the company's future financial performance. New information or changes from the company's May 3, 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 7/31/17 strip prices):
Oil - $/bbl	$2.87
Natural gas - $/mcf	($0.01)
NGL - $/bbl	$0.04
Estimated Basis to NYMEX Prices:
Oil - $/bbl	*$1.05 - $1.25*
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	*$4.00 - $4.20*
Natural Gas - $/mcf	$1.25 - $1.35
NGL - $/bbl	*$8.00 - $8.40*
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)	*$2.00 - $2.10*
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 529 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 July 31, 2017, the company had downside protection, through open swaps, on a portion of its remaining 2017 oil production at an average price of $50.32 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 $3.09 per mcf. Chesapeake also had downside price protection, through open swaps, on a portion of its remaining 2017 propane production at an average price of $0.66 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 $3.09 per mcf. Chesapeake also had downside price protection through open swaps on a portion of its 2018 oil production at an average price of $51.78 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's crude oil hedging positions as of July 31, 2017 were as follows:

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

Q3 2017	5,612	$	50.27	$	23
Q4 2017	5,612	$	50.36	23
Total 2017	11,224	$	50.32	$	46

Q1 2018	900	$	51.96	$	(1)
Q2 2018	910	$	51.96	(1)
Q3 2018	460	$	51.43	(1)
Q4 2018	460	$	51.43	(1)
Total 2018	2,730	$	51.78	$	(4)
Total 2019 – 2022				$	(8)

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

Q3 2017	1,334	$	83.50
Q4 2017	1,334	$	83.50
Total 2017	2,668	$	83.50

Q3 2018	460	$	52.49
Q4 2018	460	$	52.49
Total 2018	920	$	52.49

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

Q1 2018	450	$	39.15	$	47.00	$	55.00
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	1,825	$	39.15	$	47.00	$	55.00

The company's natural gas hedging positions as of July 31, 2017 were as follows:

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

Q3 2017	158	$	3.00	$	(1)
Q4 2017	164	$	3.16	(3)
Total 2017	322	$	3.08	$	(4)

Q1 2018	163	$	3.45	$	(6)
Q1 2018	107	$	2.89	(4)
Q3 2018	109	$	2.90	(4)
Q4 2018	109	$	2.98	(6)
Total 2018	488	$	3.10	$	(20)
Total 2019 – 2022				$	(49)

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

Q1 2018	11	$	3.00	$	3.25
Q2 2018	12	$	3.00	$	3.25
Q3 2018	12	$	3.00	$	3.25
Q4 2018	12	$	3.00	$	3.25
Total 2018	47	$	3.00	$	3.25

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

Q3 2017	12	$	9.43
Q4 2017	12	$	9.43
Total 2017	24	$	9.43

Total 2018 – 2020	66	$	12.00

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

Q3 2017	6	$	(0.46)
Q4 2017	6	$	(0.46)
Total 2017	12	$	(0.46)

Total 2018 – 2022	1	$	(1.03)