Exhibit

EX-99.1 2 chk-ex_991x20170930x8kxpr.htm EXHIBIT 99.1 Exhibit



	Exhibit 99.1
N E W S R E L E A S E

FOR IMMEDIATE RELEASE

NOVEMBER 2, 2017

CHESAPEAKE ENERGY CORPORATION REPORTS 2017 THIRD QUARTER FINANCIAL AND OPERATIONAL RESULTS

OKLAHOMA CITY, November 2, 2017 – Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operational results for the 2017 third quarter plus other recent developments. Highlights include:


•	Average 2017 third quarter production of 541,600 boe per day and average 2017 third quarter oil production of 86,000 barrels per day, as previously announced


•	Total production reached approximately 584,000 boe per day, including 99,000 barrels of oil, on October 30, 2017


•	On track to meet goal of averaging 100,000 barrels of oil per day in the 2017 fourth quarter


•	Upper Marcellus Shale enhanced completions yield rates exceeding expectations; competitive with Lower Marcellus core position

Doug Lawler, Chesapeake’s Chief Executive Officer, commented, “We continue to improve our capital efficiency and cost structure as we drive toward free cash flow neutrality. We have recognized greater productivity across our diverse portfolio through technical innovation and the tenacity of our employees and, accordingly, we are expanding our core position in every operated play. On October 30, 2017, total production reached 584,000 boe per day, including 99,000 barrels of oil and we remain on track to average 100,000 barrels of oil per day in the fourth quarter. As further evidence of our progress, we are pleased to announce the results of two new wells with enhanced completions in the Upper Marcellus that are producing at rates of approximately 30 million cubic feet of gas per day, exceeding expectations and competitive with our world class Lower Marcellus position.”

Lawler continued, “As we look toward 2018, our priorities remain unchanged as we focus on further improving our balance sheet, increasing our margins and driving toward cash flow neutrality. While we have not announced details regarding our 2018 capital program, we will maintain a disciplined approach that provides the flexibility necessary to respond to changes in commodity prices. As of today, we anticipate spending less capital in 2018 than 2017 and, given our asset quality and industry-leading capital efficiency, we expect to deliver flat to modest production growth on a lower capital expenditure. We look forward to reporting more on our progress in the coming months.”




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

2017 Third Quarter Results

For the 2017 third quarter, Chesapeake reported a net loss available to common stockholders of $41 million, or $0.05 per diluted share, while the company's EBITDA for the 2017 third quarter was $345 million. Adjusting for unrealized losses on commodity derivatives and other items that are typically excluded by securities analysts, the 2017 third quarter adjusted net income attributable to Chesapeake was $106 million, or $0.12 per diluted share, while the company's adjusted EBITDA was $468 million. Reconciliations of financial measures calculated in accordance with GAAP to non-GAAP measures are provided on pages 12 – 18 of this release.

Chesapeake’s oil, natural gas and natural gas liquids (NGL) unhedged revenue was approximately unchanged year over year despite a 15% reduction in volume, mainly driven by asset sales. Chesapeake’s oil, natural gas and NGL unhedged revenue decreased 3% quarter over quarter due to a decrease in the average commodity prices for the company's natural gas production, partially offset by an increase in natural gas and NGL production volumes sold. Average daily production for the 2017 third quarter of approximately 541,600 barrels of oil equivalent (boe) increased by 4% sequentially, adjusted for asset sales, and consisted of approximately 86,000 barrels (bbls) of oil, 2.382 billion cubic feet (bcf) of natural gas and 58,600 bbls of NGL.

Average production expenses during the 2017 third quarter were $3.03 per boe, while general and administrative (G&A) expenses (including stock-based compensation) during the 2017 third quarter were $1.08 per boe. Combined production and G&A expenses (including stock-based compensation) during the 2017 third quarter were $4.11 per boe, an increase of 6% year over year and a decrease of 6% quarter over quarter. Gathering, processing and transportation expenses during the 2017 third quarter were $7.40 per boe, a decrease of 8% year over year and a nominal decrease quarter over quarter.

Capital Spending Overview

Chesapeake’s total capital investments were approximately $692 million during the 2017 third quarter, compared to approximately $667 million in the 2017 second quarter and $412 million in the 2016 third quarter. As a result of the company's year-to-date capital investment, along with its projected capital outlay in the 2017 fourth quarter, Chesapeake's current guidance range for total capital investments was raised to $2.3 to $2.5 billion from $2.1 to $2.5 billion. A summary of the company’s guidance for 2017 is provided under "Management's Outlook as of November 2, 2017," beginning on page 20.



	2017		2017		2016
Operated activity comparison	Q3		Q2		Q3
Average rig count	17		19		11
Gross wells spud	86		102		63
Gross wells completed	120		107		80
Gross wells connected	122		94		105

Type of cost ($ in millions)
Drilling and completion costs	$	626	$	596	$	332
Exploration costs, leasehold and additions to other PP&E	17		24		21
Subtotal capital expenditures	$	643	$	620	$	353
Capitalized interest	49		47		59
Total capital expenditures	$	692	$	667	$	412

Balance Sheet and Liquidity

As of September 30, 2017, Chesapeake’s principal debt balance was approximately $9.8 billion, compared to $10.0 billion as of December 31, 2016. The company’s total liquidity as of September 30, 2017 was approximately $3.0 billion, which included cash on hand and a borrowing capacity of approximately $3.0 billion under the company’s senior secured revolving credit facility. As of September 30, 2017, the company had $645 million of outstanding borrowings under the revolving credit facility and had used $97 million of the revolving credit facility for various letters of credit.

On October 12, 2017, Chesapeake issued through a private placement an aggregate of $850 million of 8.00% Senior Notes due 2025 and 2027 with proceeds to be used to repurchase debt. On October 13, 2017, approximately $320 million principal amount of the company’s 8.00% Senior Secured Second Lien Notes due 2022 and $193 million principal amount in various Senior Notes due 2020 and 2021 were tendered. In addition, Chesapeake also repurchased in the open market approximately $237 million principal amount of the company’s secured term loan due 2021 in October 2017. As a result, Chesapeake has further reduced the principal amount of its secured debt by approximately $557 million since June 30, for a total reduction in the principal amount of secured debt of approximately $1.2 billion year to date. The company’s total debt balance on October 31, 2017 was approximately $9.9 billion, including $643 million drawn on its revolving credit facility and the company's total liquidity was approximately $3.1 billion.

On October 30, 2017, the administrative agent under the company’s senior revolving credit agreement, in addition to other lenders under the agreement, notified Chesapeake that the borrowing base had been reaffirmed at $3.785 billion.

Operations Update

Chesapeake's average daily production for the 2017 third quarter was approximately 541,600 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 remainder of the year and may be adjusted based on prevailing market conditions.



	2017	2017	2016
Operating area net production (mboe/day)	Q3	Q2	Q3
Eagle Ford	93	100	101
Haynesville	134	121	139
Marcellus	126	135	134
Utica	120	97	127
Mid-Continent	56	59	55
Powder River Basin	13	16	14
Barnett	—	—	59
Other	—	—	9
Total production	542	528	638

Chesapeake is currently utilizing 14 drilling rigs (below the 2017 third quarter average of 17) across its operating areas, five of which are located in the Eagle Ford Shale, three in the Powder River Basin (PRB), three in the Haynesville Shale, two in Northeast Appalachia and one in the Mid-Continent area. Chesapeake plans to average 14 rigs in the 2017 fourth quarter.

In the Eagle Ford Shale, Chesapeake placed 31 wells on production in the 2017 third quarter. Included in this number were 20 wells in the company’s Faith Ranch development area, of which 14 wells reached peak production of more than 1,000 bbls of oil per day. In total, the Faith Ranch wells achieved peak production of approximately 18,000 bbls of oil per day. Additionally, in October, Chesapeake placed 11 wells on production from its Vesper development area, yielding approximately 13,000 bbls of oil per day, highlighted by the Vesper Unit IV DIM H 3H well which featured a three-mile lateral and enhanced

completion, and yielded an initial production of more than 2,000 bbls of oil per day. Chesapeake expects to place on production up to 73 wells in the Eagle Ford in the 2017 fourth quarter.

In the PRB, Chesapeake’s third Turner well, the Graham 23-35-71 15H, was completed with a 4,500-foot lateral and placed on production in September 2017, achieving a peak rate of 1,737 boe per day (82% oil). On October 31, 2017, Chesapeake placed two additional Turner wells on production from its York pad, averaging approximately 8,500 feet in lateral length each. The company expects to provide updated results from these Turner wells later in the month. Chesapeake added a third rig in October 2017 and expects to place on production up to 11 wells in the 2017 fourth quarter, compared to seven wells in the 2017 third quarter.

In the Marcellus Shale, Chesapeake has begun to deploy its enhanced completion techniques on the Upper Marcellus formation, yielding rates that have exceeded internal expectations. The company placed two Upper Marcellus wells from its Maris pad located in Susquehanna County on production in September 2017. These wells achieved peak rates of 29,800 and 29,600 thousand cubic feet (mcf) of gas per day, respectively, more than 50% higher than the company's previous Upper Marcellus record rate of 18,700 mcf of gas per day from a well drilled in 2015. These wells have produced with pressures as expected with minimal depletion from offset wells in the Lower Marcellus, including one that was offset at 375 feet. These results confirmed positive delineation of the company’s Upper Marcellus resource potential in areas where Lower Marcellus production had already existed, and have the potential to significantly increase the company’s core position in the play. Chesapeake also placed the DPH SW WYO 3H well targeting the Lower Marcellus and located in the southern edge of the company's Wyoming County acreage on production, achieving a peak rate of 37,900 mcf of gas per day from a 6,100-foot lateral with an enhanced completion in October 2017. Chesapeake expects to place on production up to 17 wells in the 2017 fourth quarter, compared to 25 wells in the 2017 third quarter.

In the Utica Shale, enhanced completions techniques have yielded an approximately 25% improvement in 120-day cumulative production compared to the type curve. In July 2017, the eight-well Ellie pad was placed on production yielding an average per well initial production rate of 1,100 boe per day, 65% of which was liquids. The dry gas portion of the Utica is also delivering positive results. Chesapeake is in the initial flowback period for the Schiappa Trust A pad in Jefferson County and has seen initial production rates of 20,000 mcf of gas per well per day. Chesapeake plans to continue testing new completions designs in the 2017 fourth quarter.

In the Haynesville Shale, Chesapeake turned 12 wells on production in the 2017 third quarter, averaging lateral lengths of 8,440 feet and initial production of 31,840 mcf of gas per day. Of note, the company placed four wells from its BSNR pad located in De Soto Parish on production in September 2017, averaging 9,800-foot laterals. While these wells separately achieved peak rates ranging from 29,600 mcf to 37,200 mcf of gas per day, the combined peak rate from the BSNR pad reached approximately 134,000 mcf of gas per day. In October, the company also placed three wells from its PKY pad on production, all with 8,500-foot laterals, which achieved a combined peak rate of approximately 95,000 mcf of gas per day. As a result, last week Chesapeake's net production from the Haynesville reached 1 bcf of gas per day, which is the company's highest daily rate since November 2012. Additionally, Chesapeake expects to place on production its first 10,000-foot Bossier well, the Nabors 13&12-10-13 1HC, located in Sabine Parish in late November 2017 and intends to spud its first 15,000-foot lateral Haynesville well in the 2017 fourth quarter. The company expects to place on production up to seven wells in the Haynesville in the 2017 fourth quarter.

In the Mid-Continent, Chesapeake recently drilled and completed a 10,000-foot lateral well with an enhanced completion design on the Bravo 1H well in Major County, yielding an average production rate of approximately 1,550 bbls of oil per day and an average total production rate of 1,960 boe per day over the first 10 days.

Key Financial and Operational Results

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



	Three Months Ended
	09/30/17		06/30/17		09/30/16
Oil equivalent production (in mmboe)	50		48		59
Oil production (in mmbbls)	8		8		8
Average realized oil price ($/bbl)^(a)	52.33		51.65		45.24
Natural gas production (in bcf)	219		209		268
Average realized natural gas price ($/mcf)^(a)	2.52		2.71		2.13
NGL production (in mmbbls)	5		5		6
Average realized NGL price ($/bbl)^(a)	21.26		18.51		13.70
Production expenses ($/boe)	3.03		2.92		2.80
Gathering, processing and transportation expenses ($/boe)	7.40		7.44		8.07
Oil - ($/bbl)	4.33		3.70		3.67
Natural Gas - ($/mcf)	1.34		1.37		1.47
NGL - ($/bbl)	7.40		7.87		8.13
Production taxes ($/boe)	0.43		0.42		0.29
General and administrative expenses ($/boe)^(b)	0.91		1.20		0.90
Stock-based compensation ($/boe)	0.17		0.25		0.18
DD&A of oil and natural gas properties ($/boe)	4.57		4.21		4.26
DD&A of other assets ($/boe)	0.41		0.43		0.42
Interest expense ($/boe)^(a)	2.26		1.92		1.20
Marketing, gathering and compression net margin ($ in millions)^(c)	(14	)	(25	)	(162	)
Net cash provided by (used in) operating activities ($ in millions)	331		(157	)	376
Net cash provided by (used in) operating activities ($/boe)	6.62		(3.27	)	6.37
Operating cash flow ($ in millions)^(d)	337		316		214
Operating cash flow ($/boe)	6.74		6.58		3.63
Adjusted ebitda ($ in millions)^(e)	468		461		421
Adjusted ebitda ($/boe)	9.36		9.60		7.17
Net income (loss) available to common stockholders ($ in millions)	(41	)	470		(1,257	)
Income (loss) per share – diluted ($)	(0.05	)	0.47		(1.62	)
Adjusted net income (loss) attributable to Chesapeake ($ in millions)^(f)	106		146		73
Adjusted income (loss) per share - diluted ($)^(g)	0.12		0.18		0.09


(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 September 30, 2016, unrealized losses on supply contract derivatives, but excludes depreciation and amortization of other assets. For the three months ended September 30, 2016, unrealized losses on supply contract derivatives were $280 million. No other period presented had such gains (losses).


(d)	Defined as cash flow provided by operating activities before changes in assets and liabilities.


(e)	Defined as net income (loss) before interest expense, income taxes and depreciation, depletion and amortization expense, as adjusted to remove the effects of certain items detailed on page 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 Third Quarter Financial and Operational Results Conference Call Information

A conference call to discuss this release has been scheduled on Thursday, November 2, 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.



CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS ($ in millions except per share data) (unaudited)
	Three Months Ended September 30,
	2017			2016
REVENUES:
Oil, natural gas and NGL	$	979		$	1,177
Marketing, gathering and compression	964			1,099
Total Revenues	1,943			2,276
OPERATING EXPENSES:
Oil, natural gas and NGL production	151			164
Oil, natural gas and NGL gathering, processing and transportation	369			473
Production taxes	21			17
Marketing, gathering and compression	978			1,261
General and administrative	54			63
Provision for legal contingencies	20			8
Oil, natural gas and NGL depreciation, depletion and amortization	228			251
Depreciation and amortization of other assets	20			25
Impairment of oil and natural gas properties	—			497
Impairments of fixed assets and other	9			751
Net gains on sales of fixed assets	(1		)	—
Total Operating Expenses	1,849			3,510
INCOME (LOSS) FROM OPERATIONS	94			(1,234		)
OTHER INCOME (EXPENSE):
Interest expense	(114		)	(73		)
Losses on investments	—			(1		)
Gains (losses) on purchases or exchanges of debt	(1		)	87
Other income	4			7
Total Other Income (Expense)	(111		)	20
LOSS BEFORE INCOME TAXES	(17		)	(1,214		)
Income Tax Expense	—			—
NET LOSS	(17		)	(1,214		)
Net income attributable to noncontrolling interests	(1		)	(1		)
NET LOSS ATTRIBUTABLE TO CHESAPEAKE	(18		)	(1,215		)
Preferred stock dividends	(23		)	(42		)
NET LOSS AVAILABLE TO COMMON STOCKHOLDERS	$	(41	)	$	(1,257	)
LOSS PER COMMON SHARE:
Basic	$	(0.05	)	$	(1.62	)
Diluted	$	(0.05	)	$	(1.62	)
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic	909			777
Diluted	909			777



CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS ($ in millions except per share data) (unaudited)
	Nine Months Ended September 30,
	2017			2016
REVENUES:
Oil, natural gas and NGL	$	3,727		$	2,610
Marketing, gathering and compression	3,250			3,241
Total Revenues	6,977			5,851
OPERATING EXPENSES:
Oil, natural gas and NGL production	426			552
Oil, natural gas and NGL gathering, processing and transportation	1,081			1,436
Production taxes	64			54
Marketing, gathering and compression	3,333			3,410
General and administrative	189			172
Restructuring and other termination costs	—			3
Provision for legal contingencies	35			112
Oil, natural gas and NGL depreciation, depletion and amortization	627			791
Depreciation and amortization of other assets	62			83
Impairment of oil and natural gas properties	—			2,564
Impairments of fixed assets and other	426			795
Net gains on sales of fixed assets	—			(5		)
Total Operating Expenses	6,243			9,967
INCOME (LOSS) FROM OPERATIONS	734			(4,116		)
OTHER INCOME (EXPENSE):
Interest expense	(302		)	(197		)
Losses on investments	—			(3		)
Loss on sale of investment	—			(10		)
Gains on purchases or exchanges of debt	183			255
Other income	6			13
Total Other Income (Expense)	(113		)	58
INCOME (LOSS) BEFORE INCOME TAXES	621			(4,058		)
Income Tax Expense	2			—
NET INCOME (LOSS)	619			(4,058		)
Net income attributable to noncontrolling interests	(3		)	(1		)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	616			(4,059		)
Preferred stock dividends	(62		)	(127		)
Loss on exchange of preferred stock	(41		)	—
Earnings allocated to participating securities	(7		)	—
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$	506		$	(4,186	)
EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	0.56		$	(5.80	)
Diluted	$	0.56		$	(5.80	)
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic	908			722
Diluted	908			722



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

Cash and cash equivalents	$	5		$	882
Other current assets	1,173			1,260
Total Current Assets	1,178			2,142

Property and equipment, net	10,580			10,609
Other assets	223			277
Total Assets	$	11,981		$	13,028

Current liabilities	$	2,218		$	3,648
Long-term debt, net	9,899			9,938
Other long-term liabilities	568			645
Total Liabilities	12,685			14,231

Preferred stock	1,671			1,771
Noncontrolling interests	253			257
Common stock and other stockholders’ equity (deficit)	(2,628		)	(3,231		)
Total Equity (Deficit)	(704		)	(1,203		)

Total Liabilities and Equity	$	11,981		$	13,028

Common shares outstanding (in millions)	909			896
Principal amount of debt outstanding	$	9,775		$	9,989



CHESAPEAKE ENERGY CORPORATION SUPPLEMENTAL DATA – OIL, NATURAL GAS AND NGL PRODUCTION, SALES AND INTEREST EXPENSE (unaudited)
	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Net Production:
Oil (mmbbl)	8			8			23			25
Natural gas (bcf)	219			268			639			814
NGL (mmbbl)	5			6			15			19
Oil equivalent (mmboe)	50			59			145			180
Oil, natural gas and NGL Sales ($ in millions):
Oil sales	$	379		$	342		$	1,140		$	952
Oil derivatives – realized gains (losses)^(a)	35			18			79			102
Oil derivatives – unrealized gains (losses)^(a)	(96		)	23			45			(217		)
Total oil sales	318			383			1,264			837

Natural gas sales	553			622			1,807			1,545
Natural gas derivatives – realized gains (losses)^(a)	(1		)	(50		)	(53		)	192
Natural gas derivatives – unrealized gains (losses)^(a)	(3		)	131			384			(204		)
Total natural gas sales	549			703			2,138			1,533

NGL sales	117			84			328			247
NGL derivatives – realized gains (losses)^(a)	(3		)	(2		)	(1		)	(5		)
NGL derivatives – unrealized gains (losses)^(a)	(2		)	9			(2		)	(2		)
Total NGL sales	112			91			325			240

Total oil, natural gas and NGL sales	$	979		$	1,177		$	3,727		$	2,610
Average Sales Price (excluding gains (losses) on derivatives):
Oil ($ per bbl)	$	47.94		$	42.94		$	48.53		$	38.21
Natural gas ($ per mcf)	$	2.52		$	2.32		$	2.83		$	1.90
NGL ($ per bbl)	$	21.83		$	13.93		$	21.28		$	12.90
Oil equivalent ($ per boe)	$	21.06		$	17.86		$	22.53		$	15.27
Average Sales Price (including realized gains (losses) on derivatives):
Oil ($ per bbl)	$	52.33		$	45.24		$	51.90		$	42.31
Natural gas ($ per mcf)	$	2.52		$	2.13		$	2.75		$	2.13
NGL ($ per bbl)	$	21.26		$	13.70		$	21.21		$	12.66
Oil equivalent ($ per boe)	$	21.67		$	17.30		$	22.70		$	16.88
Interest Expense ($ in millions):
Interest expense^(b)	$	115		$	74		$	302		$	199
Interest rate derivatives – realized (gains) losses^(c)	(1		)	(3		)	(3		)	(9		)
Interest rate derivatives – unrealized (gains) losses^(c)	—			2			3			7
Total Interest Expense	$	114		$	73		$	302		$	197

(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:	September 30, 2017			September 30, 2016

Beginning cash	$	13		$	4

Net cash provided by operating activities	331			376

Cash flows from investing activities:
Drilling and completion costs^(a)	(566		)	(339		)
Acquisitions of proved and unproved properties^(b)	(64		)	(157		)
Proceeds from divestitures of proved and unproved properties	242			24
Additions to other property and equipment^(c)	(5		)	(7		)
Proceeds from sales of other property and equipment	14			—
Other	—			(1		)
Net cash used in investing activities	(379		)	(480		)

Net cash provided by financing activities	40			104
Change in cash and cash equivalents	(8		)	—
Ending cash	$	5		$	4


(a)	Includes capitalized interest of $2 million and $1 million for the three months ended September 30, 2017 and 2016, respectively.


(b)	Includes capitalized interest of $47 million and $56 million for the three months ended September 30, 2017 and 2016, respectively.


(c)	Includes capitalized interest of a nominal amount for the three months ended September 30, 2017 and 2016, respectively.



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

Beginning cash	$	882		$	825

Net cash provided by operating activities	273			50

Cash flows from investing activities:
Drilling and completion costs^(a)	(1,597		)	(948		)
Acquisitions of proved and unproved properties^(b)	(226		)	(583		)
Proceeds from divestitures of proved and unproved properties	1,193			988
Additions to other property and equipment^(c)	(12		)	(32		)
Proceeds from sales of other property and equipment	40			70
Cash paid for title defects	—			(69		)
Other	—			(5		)
Net cash used in investing activities	(602		)	(579		)

Net cash used in financing activities	(548		)	(292		)
Change in cash and cash equivalents	(877		)	(821		)
Ending cash	$	5		$	4


(a)	Includes capitalized interest of $7 million and $5 million for the nine months ended September 30, 2017 and 2016, respectively.


(b)	Includes capitalized interest of $139 million and $179 million for the nine months ended September 30, 2017 and 2016, respectively.


(c)	Includes capitalized interest of $1 million and $1 million for the nine months ended September 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:	September 30, 2017
	$			$/Diluted Share^(b)(c)
Net loss available to common stockholders (GAAP)	$	(41	)	$	(0.05	)

Adjustments:
Unrealized losses on commodity derivatives	101			0.12
Provision for legal contingencies	20			0.02
Impairments of fixed assets and other	9			0.01
Net gains on sales of fixed assets	(1		)	—
Losses on purchases or exchanges of debt	1			—
Income tax expense (benefit)^(a)	—			—
Other	(6		)	(0.01		)
Adjusted net income available to common stockholders^(b) (Non-GAAP)	83			0.09

Preferred stock dividends	23			0.03
Total adjusted net income attributable to Chesapeake^{(b) (c)} (Non-GAAP)	$	106		$	0.12


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


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


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


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


(c)	Our presentation of diluted adjusted net income (loss) per share excludes 206 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:	September 30, 2016
	$			$/Diluted Share^(b)(c)
Net loss available to common stockholders (GAAP)	$	(1,257	)	$	(1.62	)

Adjustments:
Unrealized gains on commodity derivatives	(163		)	(0.21		)
Unrealized losses on supply contract derivatives	280			0.36
Provision for legal contingencies	8			0.01
Impairment of natural gas properties	497			0.64
Impairments of fixed assets and other	751			0.97
Gains on purchases or exchanges of debt	(87		)	(0.11		)
Income tax expense (benefit)^(a)	—			—
Other	2			—
Adjusted net income available to common stockholders^(b) (Non-GAAP)	31			0.04

Preferred stock dividends	42			0.05
Total adjusted net income attributable to Chesapeake^{(b) (c)} (Non-GAAP)	$	73		$	0.09


(a)	Due to our valuation allowance position, no income tax effect from the adjustments has been included in determining adjusted net income.

(b)


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


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


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


(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 ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS ($ in millions except per share data) (unaudited)
NINE MONTHS ENDED:	September 30, 2017
	$			$/Diluted Share^(b)(c)
Net income available to common stockholders (GAAP)	$	506		$	0.56

Adjustments:
Unrealized gains on commodity derivatives	(427		)	(0.47		)
Provision for legal contingencies	35			0.04
Impairments of fixed assets and other	426			0.47
Gains on purchases or exchanges of debt	(183		)	(0.21		)
Loss on exchange of preferred stock	41			0.05
Income tax expense (benefit)^(a)	—			—
Other	(3		)	—
Adjusted net income available to common stockholders^(b) (Non-GAAP)	395			0.44

Preferred stock dividends	62			0.07
Earnings allocated to participating securities	7			—
Total adjusted net income attributable to Chesapeake^{(b) (c)} (Non-GAAP)	$	464		$	0.51


(a)	Due to our valuation allowance position, no income tax effect from the adjustments has been included in determining adjusted net income.

(b)


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


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


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


(c)	Our presentation of diluted adjusted net income (loss) per share excludes 207 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)
NINE MONTHS ENDED:	September 30, 2016
	$			$/Diluted Share^(b)(c)
Net loss available to common stockholders (GAAP)	$	(4,186	)	(5.80		)

Adjustments:
Unrealized losses on commodity derivatives	423			0.58
Unrealized losses on supply contract derivatives	297			0.41
Restructuring and other termination costs	3			—
Provision for legal contingencies	112			0.16
Impairment of natural gas properties	2,564			3.56
Impairments of fixed assets and other	795			1.10
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	(255		)	(0.35		)
Income tax expense (benefit)^(a)	—			—
Other	8			0.01
Adjusted net loss available to common stockholders^(b) (Non-GAAP)	(234		)	(0.33		)

Preferred stock dividends	127			0.18
Total adjusted net loss attributable to Chesapeake^{(b) (c)} (Non-GAAP)	$	(107	)	$	(0.15	)


(a)	Due to our valuation allowance position, no income tax effect from the adjustments has been included in determining adjusted net income.

(b)


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


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


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


(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:	September 30, 2017		September 30, 2016

CASH PROVIDED BY OPERATING ACTIVITIES	$	331	$	376
Changes in assets and liabilities	6		(162		)
OPERATING CASH FLOW^(a)	$	337	$	214



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

NET LOSS	$	(17	)	$	(1,214	)
Interest expense	114			73
Depreciation and amortization of other assets	20			25
Oil, natural gas and NGL depreciation, depletion and amortization	228			251
EBITDA^(b)	$	345		$	(865	)



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

CASH PROVIDED BY OPERATING ACTIVITIES	$	331		$	376
Changes in assets and liabilities	6			(162		)
Interest expense, net of unrealized gains (losses) on derivatives	114			71
Gains (losses) on commodity derivatives, net	(70		)	129
Losses on supply contract derivatives, net	—			(134		)
Cash receipts on commodity and supply contract derivative settlements, net	(20		)	(101		)
Renegotiation of gas gathering contract	—			66
Stock-based compensation	(11		)	(15		)
Restructuring and other termination costs	—			1
Provision for legal contingencies	(20		)	27
Impairment of oil and natural gas properties	—			(497		)
Impairments of fixed assets and other	(8		)	(751		)
Net gains on sales of fixed assets	1			—
Investment activity	—			(1		)
Gains on purchases or exchanges of debt	—			87
Other items	22			39
EBITDA^(b)	$	345		$	(865	)

(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.

(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)
NINE MONTHS ENDED:	September 30, 2017		September 30, 2016

CASH PROVIDED BY OPERATING ACTIVITIES	$	273	$	50
Changes in assets and liabilities	366		614
OPERATING CASH FLOW^(a)	$	639	$	664



NINE MONTHS ENDED:	September 30, 2017		September 30, 2016

NET INCOME (LOSS)	$	619	$	(4,058	)
Interest expense	302		197
Income tax expense	2		—
Depreciation and amortization of other assets	62		83
Oil, natural gas and NGL depreciation, depletion and amortization	627		791
EBITDA^(b)	$	1,612	$	(2,987	)



NINE MONTHS ENDED:	September 30, 2017			September 30, 2016

CASH USED IN OPERATING ACTIVITIES	$	273		$	50
Changes in assets and liabilities	366			614
Interest expense, net of unrealized gains (losses) on derivatives	299			190
Gains (losses) on commodity derivatives, net	452			(134		)
Losses on supply contract derivatives, net	—			(151		)
Cash (receipts) payments on commodity and supply contract derivative settlements, net	46			(487		)
Renegotiation of gas gathering contract	—			66
Stock-based compensation	(38		)	(40		)
Restructuring and other termination costs	—			(1		)
Provision for legal contingencies	(35		)	(77		)
Impairment of oil and natural gas properties	—			(2,564		)
Impairments of fixed assets and other	(9		)	(785		)
Net gains on sales of fixed assets	—			5
Investment activity	—			(13		)
Gains on purchases or exchanges of debt	185			255
Other items	73			85
EBITDA^(b)	$	1,612		$	(2,987	)

(a)

(b)



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

EBITDA	$	345		$	(865	)

Adjustments:
Unrealized (gains) losses on commodity derivatives	101			(163		)
Unrealized losses on supply contract derivatives	—			280
Provision for legal contingencies	20			8
Impairment of oil and natural gas properties	—			497
Impairments of fixed assets and other	9			751
Net gains on sales of fixed assets	(1		)	—
(Gains) losses on purchases or exchanges of debt	1			(87		)
Net income attributable to noncontrolling interests	(1		)	(1		)
Other	(6		)	1

Adjusted EBITDA^(a)	$	468		$	421



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

EBITDA	$	1,612		$	(2,987	)

Adjustments:
Unrealized (gains) losses on commodity derivatives	(427		)	423
Unrealized losses on supply contract derivatives	—			297
Restructuring and other termination costs	—			3
Provision for legal contingencies	35			112
Impairment of oil and natural gas properties	—			2,564
Impairments of fixed assets and other	426			795
Net gains on sales of fixed assets	—			(5		)
Loss on sale of investment	—			10
Gains on purchases or exchanges of debt	(183		)	(255		)
Net income attributable to noncontrolling interests	(3		)	(1		)
Other	(6		)	(1		)

Adjusted EBITDA^(a)	$	1,454		$	955


(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 September 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 – September 30, 2017 @ NYMEX Strip	$	8,456
Less: Change in discount factor from 9 to 10	(440		)
PV-10 – September 30, 2017 @ NYMEX Strip	8,016
Less: Change in pricing assumption from NYMEX Strip to SEC	(85		)
PV-10 – September 30, 2017 @ SEC	7,931
Less: Change in PV-10 from 12/31/16 to 9/30/2017	(3,526		)
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 NOVEMBER 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 September 26, 2017 Outlook are italicized bold below.



	Year Ending 12/31/2017

Adjusted Production Growth^(a)	(1%) to 1%
Absolute Production
Liquids - mmbbls	51.5 - 53.5
Oil - mmbbls	32.0 - 33.0
NGL- mmbbls	19.5 - 20.5
Natural gas - bcf	855 - 875
Total absolute production - mmboe	194.0 - 199.0
Absolute daily rate - mboe	532 - 545
Estimated Realized Hedging Effects^(b) (based on 10/30/17 strip prices):
Oil - $/bbl	$2.61
Natural gas - $/mcf	$0.00
NGL - $/bbl	($0.20)
Estimated Basis to NYMEX Prices:
Oil - $/bbl	$0.45 - $0.55
Natural gas - $/mcf	$0.30 - $0.35
NGL - $/bbl	$3.75 - $4.15
Operating Costs per Boe of Projected Production:
Production expense	$2.80 - $2.95
Gathering, processing and transportation expenses	$7.15 - $7.40
Oil - $/bbl	$3.90 - $4.00
Natural Gas - $/mcf	$1.30 - $1.35
NGL - $/bbl	$7.70 - $7.90
Production taxes	$0.40 - $0.50
General and administrative^(c)	$1.10 - $1.20
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)	$2.05 - $2.15
Marketing, gathering and compression net margin^(e)	($80) - ($60)
Book Tax Rate	0%
Capital Expenditures ($ in millions)^(f)	$2,100 - $2,300
Capitalized Interest ($ in millions)	$200
Total Capital Expenditures ($ in millions)	$2,300 - $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 October 31, 2017, the company had downside protection, through open swaps, on a portion of its remaining 2017 oil production at an average price of $50.36 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 $3.17 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 $0.76 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 $3.10 per mcf. Chesapeake also had downside price protection through open swaps on a portion of its 2018 oil production at an average price of $51.74 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 October 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)

Q4 2017	5,612	$	50.36	23
Total 2017	5,612	$	50.36	$	23

Q1 2018	5,099	$	51.84	$	(1	)
Q2 2018	5,187	$	51.85	(1		)
Q3 2018	4,324	$	51.63	(1		)
Q4 2018	4,324	$	51.63	(1		)
Total 2018	18,934	$	51.74	$	(4	)

Total 2019 - 2022	—	$	—	$	(8	)



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

Q4 2017	1,334	$	83.50
Total 2017	1,334	$	83.50

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



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



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

Q4 2017	1	$	3.15
Total 2017	1	$	3.15

Q1 2018	2	$	3.12
Q1 2018	2	$	3.12
Q3 2018	2	$	3.28
Q4 2018	2	$	3.28
Total 2018	8	$	3.19

The company’s natural gas hedging positions as of October 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)

Q4 2017	164	$	3.16	(3		)
Total 2017	164	$	3.16	$	(3	)

Q1 2018	174	$	3.44	$	(6	)
Q1 2018	118	$	2.92	(4		)
Q3 2018	120	$	2.94	(4		)
Q4 2018	120	$	3.00	(6		)
Total 2018	532	$	3.11	$	(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

Q4 2017	12	$	9.43
Total 2017	12	$	9.43

Q1 2018	16	$	6.27
Q4 2018	16	$	6.27
Q3 2018	17	$	6.27
Q4 2018	17	$	6.27
Total 2018	66	$	6.27

Total 2019 – 2020	44	$	12.00



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

Q4 2017	17	$	(0.66	)
Total 2017	17	$	(0.66	)

Q1 2018	18	$	(0.78	)
Q4 2018	18	$	(0.77	)
Q3 2018	17	$	(0.77	)
Q4 2018	6	$	(0.77	)
Total 2018	59	$	(0.78	)

The company’s natural gas liquids hedging positions as of October 31, 2017 were as follows:



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

Q4 2017	15	$	0.76
Total 2017	15	$	0.76

Q1 2018	3	$	0.73
Q4 2018	4	$	0.73
Q3 2018	4	$	0.73
Q4 2018	4	$	0.73
Total 2018	15	$	0.73



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

Q1 2018	1	$	0.88
Q4 2018	1	$	0.88
Q3 2018	1	$	0.88
Q4 2018	1	$	0.88
Total 2018	5	$	0.88



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

Q1 2018	1	70.5	%
Q4 2018	1	70.5	%
Q3 2018	1	70.5	%
Q4 2018	1	70.5	%
Total 2018	5	70.5	%