Chesapeake Energy Corporation Reports 2017 Full Year And Fourth Quarter Financial And Operational Results And Announces 2018 ...

OKLAHOMA CITY, Feb. 22, 2018 /PRNewswire/ -- Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operational results for the 2017 full year and fourth quarter plus other recent developments. Highlights include:

Average 2017 production of approximately 547,800 barrels of oil equivalent (boe) per day, up 3 percent compared to 2016 levels, adjusted for asset sales; oil production up 11 percent in 2017 fourth quarter compared to 2016 fourth quarter, adjusted for asset sales
Reduced production, general and administrative and gathering, processing and transportation expenses by approximately $510 million, down 18 percent compared to 2016 levels
Projected 2018 capital expenditures program of approximately $1.975 - $2.375 billion, down 12 percent compared to 2017 levels, using midpoint
Total 2018 production, adjusted for asset sales, expected to grow approximately 3 percent year-over-year, using midpoint; oil volumes adjusted for asset sales, expected to grow by approximately 5 percent compared to 2017 levels, using midpoint

Doug Lawler, Chesapeake's Chief Executive Officer, commented, "I am very pleased with our fourth quarter and full year 2017 performance, as we made significant progress toward our goals of reducing our debt, increasing cash flow generation and margin enhancement. Fiscal year 2017 was a pivotal year for Chesapeake, as we restored our production and increased net cash provided by operations, increased our oil production, adjusted for asset sales, and significantly improved our cost structure by reducing our combined production, general and administrative and gathering, processing, and transportation expenses by approximately $510 million. We further demonstrated the depth of our portfolio by closing on approximately $1.3 billion in asset and property sales and signed additional asset sales for approximately $575 million that we expect to close by the end of the 2018 second quarter. We reduced our outstanding secured term debt by approximately $1.3 billion, or 32 percent, continued to remove legal obligations and recorded the best environmental and safety performance in our company's history.

"We are well-positioned to build on our 2017 accomplishments and progress our strategic goals, with our 2018 guidance highlighting improvements in our cost structure, increased oil production, adjusted for asset sales, and increased net cash and margins provided by operations. We expect to deliver production growth, adjusted for asset sales, of 1 percent to 5 percent on reduced capital expenditures. The expected improvements in our cost structure, as well as improved basis pricing differentials and higher NYMEX pricing, result in higher forecasted year-over-year cash flows.

"Over the last four years, we have fundamentally transformed our business, removing financial and operational complexity, significantly improving our balance sheet, and addressing numerous legacy issues that have affected past performance. Chesapeake Energy continues to get stronger, and we believe we are well positioned to create meaningful shareholder value in the years ahead."

2017 Full Year Results

For the 2017 full year, Chesapeake reported net income of $953 million and net income available to common stockholders of $813 million, or $0.90 per diluted share. The company's EBITDA for the 2017 full year was $2.376 billion. Adjusting items that are typically excluded by securities analysts, the 2017 full year adjusted net income attributable to Chesapeake was $742 million, or $0.82 per diluted share, while the company's adjusted EBITDA was $2.160 billion. Reconciliations of financial measures calculated in accordance with GAAP to non-GAAP measures are provided on pages 12 - 16 of this release.

Chesapeake's oil, natural gas and NGL unhedged revenue increased by 18 percent year over year due to an increase in average price despite a 14 percent reduction in production volumes sold. Average daily production for 2017 of approximately 547,800 boe increased by 3 percent compared to 2016 levels, adjusted for asset sales, and consisted of approximately 89,500 barrels (bbls) of oil, 2.406 billion cubic feet (bcf) of natural gas and 57,300 bbls of NGL.

During the full year production expenses were $2.81 per boe, while general and administrative expenses (including stock-based compensation) were $1.31 per boe. Combined production and general and administrative expenses during the 2017 full year were $4.12 per boe, an increase of 1 percent year over year. Gathering, processing, and transportation expenses during the 2017 full year were $7.36 per boe, a decrease of 8 percent year over year.

2017 Fourth Quarter Results

For the 2017 fourth quarter, Chesapeake reported net income of $334 million and net income available to common stockholders of $309 million, or $0.33 per diluted share. The company's EBITDA for the 2017 fourth quarter was $764 million. Adjusting for items that are typically excluded by securities analysts, the 2017 fourth quarter adjusted net income attributable to Chesapeake was $314 million, or $0.30 per diluted share, while the company's adjusted EBITDA was $706 million. Reconciliations of financial measures calculated in accordance with GAAP to non-GAAP measures are provided on pages 12 - 16 of this release.

Chesapeake's oil, natural gas and NGL unhedged revenue in the fourth quarter increased 16 percent year over year due to a 3 percent increase in volumes and an increase in commodity prices. Average daily production for the 2017 fourth quarter of approximately 593,200 boe increased by 15 percent over 2016 fourth quarter levels and 10 percent sequentially, adjusted for asset sales, and consisted of approximately 99,900 bbls of oil, 2.603 bcf of natural gas and 59,500 bbls of NGL.

Production expenses during the 2017 fourth quarter were $2.50 per boe, while general and administrative expenses (including stock-based compensation) during the 2017 fourth quarter were $1.34 per boe. Combined production and general and administrative expenses during the 2017 fourth quarter were $3.84 per boe, a decrease of 10 percent year over year and a decrease of 7 percent quarter over quarter. Gathering, processing, and transportation expenses during the 2017 fourth quarter were $7.15 per boe, a decrease of 10 percent year over year and a decrease of 3 percent quarter over quarter.

Capital Spending Overview

Chesapeake's total capital investments were approximately $2.458 billion during the 2017 full year, compared to approximately $1.697 billion in the 2016 full year. A summary of the company's 2017 and 2016 capital expenditures, as well as the current 2018 capital expenditure guidance, is provided in the table below.

	2016				2017				2018
Operated activity comparison	Q4		FY		Q4		FY		Outlook
Average rig count	12		10		14		17		14 - 16
Gross wells spud	60		213		66		341		275 - 300
Gross wells completed	82		365		101		417		320 - 350
Gross wells connected	110		428		118		411		320 - 350

Type of cost ($ in millions)
Drilling and completion costs	$	365	$	1,316	$	462	$	2,190	$1,700 - $2,050
Exploration costs, leasehold and additions to other PP&E	38		130		15		74		$100 - $150
Subtotal capital expenditures	$	403	$	1,446	$	477	$	2,264	$1,800 - $2,200
Capitalized interest	60		251		46		194		175
Total capital expenditures	$	463	$	1,697	$	523	$	2,458	$1,975 - $2,375

Balance Sheet and Liquidity

As of December 31, 2017, Chesapeake's principal debt balance was approximately $9.981 billion, compared to $9.989 billion as of December 31, 2016. The company's liquidity as of December 31, 2017 was approximately $2.893 billion, which included cash on hand and undrawn borrowing capacity of approximately $2.888 billion under the company's senior secured revolving credit facility. As of December 31, 2017, the company had $781 million of outstanding borrowings under the revolving credit facility and had used $116 million of the revolving credit facility for various letters of credit.

The company recently signed additional asset sales agreements for properties in the Mid-Continent, including our Mississippian Lime assets, for approximately $500 million in proceeds that we expect to close by the end of the 2018 second quarter. In addition, the company sold approximately 4.3 million shares of FTS International, Inc. (NYSE: FTSI) for approximately $74 million in net proceeds and continues to hold approximately 22.0 million shares in the publicly traded company. FTSI is a provider of hydraulic fracturing services in North America and a company in which Chesapeake has owned a significant stake since 2006. FTSI completed its initial public offering of common shares on February 6, 2018. The proceeds from these divestitures will go toward reducing Chesapeake's outstanding borrowings under its revolving credit facility, to repurchase high coupon debt to reduce annual interest expense, based on market conditions.

Operations Update

Chesapeake's average daily production for the 2017 full year was approximately 547,800 boe compared to approximately 635,400 boe in the 2016 full year. A summary of the company's 2017 average daily production and average daily sales prices received by the company's operating divisions can be found in the company's Form 10-K.

Chesapeake's average daily production for the 2017 fourth quarter was approximately 593,200 boe compared to approximately 574,500 boe in the 2016 fourth quarter. The following tables show average daily production and average daily sales prices received by the company's operating divisions for the 2017 fourth quarter.

	Three Months Ended December 31, 2017
	Oil		Natural Gas		NGL		Total
	mbbl per day	$/bbl	mmcf per day	$/mcf	mbbl per day	$/bbl	mboe per day	%		$/boe
Marcellus	—	—	834	2.23	—	—	139	23		13.36
Haynesville	—	—	930	2.72	—	—	155	26		16.41
Eagle Ford	66	59.62	150	3.12	21	27.09	112	19		44.38
Utica	11	51.20	477	2.70	25	29.96	115	20		22.48
Mid-Continent	16	53.99	167	2.49	10	26.42	54	9		28.50
Powder River Basin	7	54.36	45	2.90	3	33.30	18	3		34.83
Total	100	57.42	2,603	2.57	59	28.54	593	100	%	23.81

In the Powder River Basin (PRB), strong results from Chesapeake's latest well placed on production in the Turner formation provides additional confirmation of the PRB's potential resource. In December 2017, the LEBAR 15-34-69 A TR 22H well was placed on production in the gas condensate window of the Turner with a lateral length of approximately 10,100 feet. This well reached a peak rate of 2,600 boe per day (50% oil) and has cumulatively produced 115,000 boe (50% oil) in its first 60 days of production. The LEBAR well is currently producing approximately 2,000 boe per day (45% oil) with a flowing tubing pressure of 2,600 psi after approximately 80 days on production. Chesapeake's seventh producing well targeting the Turner formation, the BB 35-35-72 USA A TR 21H, was completed with a 9,677-foot lateral and is scheduled to be placed on production next week. In January 2018, Chesapeake placed three wells on production from the Sussex formation, averaging approximately 6,895 feet in lateral length, and achieving an average peak rate of 880 boe per day (90% oil), while still cleaning up. Chesapeake added a third rig in October 2017 and expects to add a fourth rig in April 2018. Chesapeake expects to place on production up to 33 wells in 2018, compared to 25 wells in 2017.

In the Eagle Ford Shale in south Texas, Chesapeake is currently utilizing five drilling rigs and expects to place on production up to 140 wells in 2018, compared to 166 wells in 2017.

In the Marcellus Shale in northeast Pennsylvania, Chesapeake is currently utilizing one drilling rig and expects to place on production up to 55 wells in 2018, compared to 43 wells in 2017. Chesapeake expects to keep its total gross operated production from the region effectively flat compared to 2017 at approximately 2.1 bcf per day.

In the Haynesville Shale in Louisiana, Chesapeake is currently utilizing three drilling rigs and expects to place on production up to 25 wells in 2018, compared to 36 wells in 2017. In December 2017, Chesapeake placed the Nabors 13&12-10-13 1HC well on production from the Bossier formation, its first ever Bossier horizontal well with a lateral length of more than 10,000 feet, which achieved a peak rate of 35.8 million cubic feet of gas per day.

In the Utica Shale in northeast Ohio, Chesapeake is currently utilizing two drilling rigs and expects to place on production up to 40 wells in 2018, compared to 67 wells in 2017.

In the company's Mid-Continent operating area in Oklahoma, Chesapeake is currently utilizing one drilling rig and expects to place on production up to 40 wells in 2018, compared to 71 wells in 2017. Chesapeake expects to spud its first horizontal well targeting the Chester formation in Woods County in May 2018 and its first horizontal well targeting the Hunton formation in June 2018. If successful, Chesapeake could drill up to 10 additional Chester and Hunton tests in 2018.

Key Financial and Operational Results

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

	Three Months Ended		Full Year Ended
	12/31/17	12/31/16	12/31/17	12/31/16
Barrels of oil equivalent production (in mmboe)	55	53	200	233
Oil production (in mmbbls)	9	8	33	33
Average realized oil price ($/bbl)^(a)	56.47	47.37	53.19	43.58
Natural gas production (in bcf)	239	236	878	1,049
Average realized natural gas price ($/mcf)^(a)	2.76	2.41	2.75	2.20
NGL production (in mmbbls)	5	5	21	24
Average realized NGL price ($/bbl)^(a)	27.98	20.90	22.98	14.43
Production expenses ($/boe)	2.50	2.98	2.81	3.05
Gathering, processing and transportation expenses ($/boe)	7.15	7.92	7.36	7.98
Oil - ($/bbl)	3.90	3.87	3.94	3.61
Natural Gas - ($/mcf)	1.30	1.46	1.34	1.47
NGL - ($/bbl)	7.83	8.05	7.88	7.83
Production taxes ($/boe)	0.45	0.38	0.44	0.32
General and administrative expenses ($/boe)^(b)	1.19	1.11	1.13	0.87
General and administrative expenses (stock-based compensation) (non-cash) ($/boe)	0.15	0.17	0.18	0.16
DD&A of oil and natural gas properties ($/boe)	5.23	4.03	4.56	4.31
DD&A of other assets ($/boe)	0.37	0.40	0.41	0.45
Interest expense ($/boe)^(a)	2.25	1.61	2.11	1.18
Marketing, gathering and compression net margin($ in millions)	(4)	(25)	(87)	(194)
Net cash provided by (used in) operating activities ($ in millions)	472	(254)	745	(204)
Net cash provided by (used in) operating activities ($/boe)	8.65	(4.79)	3.73	(0.88)
Operating cash flow ($ in millions)^(c)	577	(107)	1,216	557
Operating cash flow ($/boe)	10.57	(2.02)	6.09	2.39
Net income (loss) ($ in millions)	334	(341)	953	(4,399)
Net income (loss) available to common stockholders ($ in millions)	309	(740)	813	(4,915)
Net income (loss) per share available to common stockholders – diluted ($)	0.33	(0.83)	0.90	(6.43)
Adjusted EBITDA ($ in millions)^(d)	706	385	2,160	1,350
Adjusted EBITDA ($/boe)	12.94	7.26	10.80	5.79
Adjusted net income (loss) attributable to Chesapeake ($ in millions)^(e)	314	64	742	(31)
Adjusted net income (loss) attributable to Chesapeake per share - diluted ($ in millions)^(f)	0.30	0.07	0.82	(0.03)


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

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

(c)	Defined as cash flow provided by operating activities before changes in components of working capital and other assets and liabilities. This is a non-GAAP measure. See reconciliation to cash provided by (used in) operating activities on page 14.

(d)	Defined as net income (loss) before interest expense, income taxes and depreciation, depletion and amortization expense, as adjusted to remove the effects of certain items detailed on page 16. This is a non-GAAP measure. See reconciliation of net income (loss) to EBITDA on page 14 and reconciliation of EBITDA to adjusted EBITDA on page 16.

(e)	Defined as net income (loss) attributable to Chesapeake, as adjusted to remove the effects of certain items detailed on pages 12 - 13. This is a non-GAAP measure. See reconciliation of net income to adjusted net income (loss) available to Chesapeake on pages 12-13.

(f)	Our presentation of diluted adjusted net income (loss) attributable to Chesapeake per share excludes 60 million and 211 million shares for the three months ended December 31, 2017 and 2016, respectively, and 207 million and 247 million shares for the years ended December 31,2017 and 2016, respectively, considered antidilutive when calculating diluted earnings per share.

2017 Fourth Quarter and Year-End Financial and Operational Results Conference Call Information

A conference call to discuss this release has been scheduled on Thursday, February 22, 2018 at 9:00 am EDT. The telephone number to access the conference call is 719-325-4837 or toll-free 877-419-6600. The passcode for the call is 4866677. 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 4866677. The conference call will be webcast and can be found at www.chk.com in the "Investors" section of the company's website. The webcast of the conference will be available on the website for one year.

Headquartered in Oklahoma City, Chesapeake Energy Corporation's (NYSE: CHK) operations are focused on discovering and developing its large and geographically diverse resource base of unconventional oil and natural gas assets onshore in the United States.

This news release and the accompanying Outlook include "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are statements other than statements of historical fact. They include statements that give our current expectations, management's outlook guidance or forecasts of future events, production and well connection forecasts, estimates of operating costs, anticipated capital and operational efficiencies, planned development drilling and expected drilling cost reductions, anticipated timing of wells to be placed into production, general and administrative expenses, capital expenditures, the timing of anticipated asset sales and proceeds to be received therefrom, the expected use of proceeds of anticipated asset sales, projected cash flow and liquidity, our ability to enhance our cash flow and financial flexibility, plans and objectives for future operations, the ability of our employees, portfolio strength and operational leadership to create long-term value, and the assumptions on which such statements are based. Although we believe the expectations and forecasts reflected in the forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate or changed assumptions or by known or unknown risks and uncertainties.

Factors that could cause actual results to differ materially from expected results include those described under "Risk Factors" in Item 1A of our annual report on Form 10-K and any updates to those factors set forth in Chesapeake's subsequent quarterly reports on Form 10-Q or current reports on Form 8-K (available at http://www.chk.com/investors/sec-filings). These risk factors include the volatility of oil, natural gas and NGL prices; the limitations our level of indebtedness may have on our financial flexibility; our inability to access the capital markets on favorable terms; the availability of cash flows from operations and other funds to finance reserve replacement costs or satisfy our debt obligations; downgrade in our credit rating requiring us to post more collateral under certain commercial arrangements; write-downs of our oil and natural gas asset carrying values due to low commodity prices; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and projecting future rates of production and the amount and timing of development expenditures; our ability to generate profits or achieve targeted results in drilling and well operations; leasehold terms expiring before production can be established; commodity derivative activities resulting in lower prices realized on oil, natural gas and NGL sales; the need to secure derivative liabilities and the inability of counterparties to satisfy their obligations; adverse developments or losses from pending or future litigation and regulatory proceedings, including royalty claims; charges incurred in response to market conditions and in connection with our ongoing actions to reduce financial leverage and complexity; drilling and operating risks and resulting liabilities; effects of environmental protection laws and regulation on our business; legislative and regulatory initiatives further regulating hydraulic fracturing; our need to secure adequate supplies of water for our drilling operations and to dispose of or recycle the water used; impacts of potential legislative and regulatory actions addressing climate change; federal and state tax proposals affecting our industry; potential OTC derivatives regulation limiting our ability to hedge against commodity price fluctuations; competition in the oil and gas exploration and production industry; a deterioration in general economic, business or industry conditions; negative public perceptions of our industry; limited control over properties we do not operate; pipeline and gathering system capacity constraints and transportation interruptions; terrorist activities and cyber-attacks adversely impacting our operations; an interruption in operations at our headquarters due to a catastrophic event; certain anti-takeover provisions that affect shareholder rights; and our inability to increase or maintain our liquidity through debt repurchases, capital exchanges, asset sales, joint ventures, farmouts or other means.

In addition, disclosures concerning the estimated contribution of derivative contracts to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility. Our production forecasts are also dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Expected asset sales may not be completed in the time frame anticipated or at all. We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this news release, and we undertake no obligation to update any of the information provided in this release or the accompanying Outlook, except as required by applicable law. In addition, this news release contains time-sensitive information that reflects management's best judgment only as of the date of this news release.

INVESTOR CONTACT:	MEDIA CONTACT:
Brad Sylvester, CFA	Gordon Pennoyer
(405) 935-8870	(405) 935-8878
ir@chk.com	media@chk.com

CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS ($ in millions except per share data) (unaudited)
	Three Months Ended December 31,				Years Ended December 31,
	2017		2016		2017		2016
REVENUES:
Oil, natural gas and NGL	$	1,258	$	678	$	4,985	$	3,288
Marketing, gathering and compression	1,261		1,343		4,511		4,584
Total Revenues	2,519		2,021		9,496		7,872
OPERATING EXPENSES:
Oil, natural gas and NGL production	136		158		562		710
Oil, natural gas and NGL gathering, processing and transportation	390		419		1,471		1,855
Production taxes	25		20		89		74
Marketing, gathering and compression	1,265		1,368		4,598		4,778
General and administrative	73		68		262		240
Restructuring and other termination costs	—		3		—		6
Provision for legal contingencies, net	(73)		11		(38)		123
Oil, natural gas and NGL depreciation, depletion and amortization	286		212		913		1,003
Depreciation and amortization of other assets	20		21		82		104
Impairment of oil and natural gas properties	—		—		—		2,564
Impairments of fixed assets and other	(5)		43		421		838
Net gains on sales of fixed assets	(3)		(7)		(3)		(12)
Total Operating Expenses	2,114		2,316		8,357		12,283
INCOME (LOSS) FROM OPERATIONS	405		(295)		1,139		(4,411)
OTHER INCOME (EXPENSE):
Interest expense	(124)		(99)		(426)		(296)
Losses on investments	—		(5)		—		(8)
Loss on sale of investment	—		—		—		(10)
Impairments of investments	—		(119)		—		(119)
Gains (losses) on purchases or exchanges of debt	50		(19)		233		236
Other income	3		6		9		19
Total Other Expense	(71)		(236)		(184)		(178)
INCOME (LOSS) BEFORE INCOME TAXES	334		(531)		955		(4,589)
INCOME TAX EXPENSE (BENEFIT):
Current income taxes	(11)		(19)		(9)		(19)
Deferred income taxes	11		(171)		11		(171)
Total Income Tax Expense (Benefit)	—		(190)		2		(190)
NET INCOME (LOSS)	334		(341)		953		(4,399)
Net (income) loss attributable to noncontrolling interests	(1)		(1)		(4)		9
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	333		(342)		949		(4,390)
Preferred stock dividends	(23)		30		(85)		(97)
Loss on exchange of preferred stock	—		(428)		(41)		(428)
Earnings allocated to participating securities	(1)		—		(10)		—
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$	309	$	(740)	$	813	$	(4,915)
EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	0.34	$	(0.83)	$	0.90	$	(6.43)
Diluted	$	0.33	$	(0.83)	$	0.90	$	(6.43)
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic	907		887		906		764
Diluted	1,053		887		906		764

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

Cash and cash equivalents	$	5	$	882
Other current assets	1,520		1,260
Total Current Assets	1,525		2,142

Property and equipment, net	10,680		10,609
Other long-term assets	220		277
Total Assets	$	12,425	$	13,028

Current liabilities	$	2,356	$	3,648
Long-term debt, net	9,921		9,938
Other long-term liabilities	520		645
Total Liabilities	12,797		14,231

Preferred stock	1,671		1,771
Noncontrolling interests	124		128
Common stock and other stockholders' equity (deficit)	(2,167)		(3,102)
Total Equity (Deficit)	(372)		(1,203)

Total Liabilities and Equity	$	12,425	$	13,028

Common shares outstanding (in millions)	909		896
Principal amount of debt outstanding	$	9,981	$	9,989

CHESAPEAKE ENERGY CORPORATION SUPPLEMENTAL DATA – OIL, NATURAL GAS AND NGL PRODUCTION, SALES AND INTEREST EXPENSE (unaudited)
	Three Months Ended December 31,				Years Ended December 31,
	2017		2016		2017		2016
Net Production:
Oil (mmbbl)	9		8		33		33
Natural gas (bcf)	239		236		878		1,049
NGL (mmbbl)	5		5		21		24
Oil equivalent (mmboe)	55		53		200		233
Average daily production (mboe)	593		575		548		635
Oil, natural gas and NGL Sales ($ in millions):
Oil sales	$	528	$	399	$	1,668	$	1,351
Oil derivatives – realized gains (losses)^(a)	(9)		(5)		70		97
Oil derivatives – unrealized gains (losses)^(a)	(179)		(101)		(134)		(318)
Total oil sales	340		293		1,604		1,130

Natural gas sales	615		610		2,422		2,155
Natural gas derivatives – realized gains (losses)^(a)	44		(41)		(9)		151
Natural gas derivatives – unrealized gains (losses)^(a)	105		(296)		489		(500)
Total natural gas sales	764		273		2,902		1,806

NGL sales	156		113		484		360
NGL derivatives – realized gains (losses)^(a)	(3)		(3)		(4)		(8)
NGL derivatives – unrealized gains (losses)^(a)	1		2		(1)		—
Total NGL sales	154		112		479		352

Total oil, natural gas and NGL sales	$	1,258	$	678	$	4,985	$	3,288
Average Sales Price of Production:
Oil ($ per bbl)	$	57.42	$	47.95	$	51.03	$	40.65
Natural gas ($ per mcf)	$	2.57	$	2.59	$	2.76	$	2.05
NGL ($ per bbl)	$	28.54	$	21.54	$	23.18	$	14.76
Oil equivalent ($ per boe)	$	23.81	$	21.24	$	22.88	$	16.63
Average Sales Price (including realized gains (losses) on derivatives):
Oil ($ per bbl)	$	56.47	$	47.37	$	53.19	$	43.58
Natural gas ($ per mcf)	$	2.76	$	2.41	$	2.75	$	2.20
NGL ($ per bbl)	$	27.98	$	20.90	$	22.98	$	14.43
Oil equivalent ($ per boe)	$	24.41	$	20.30	$	23.17	$	17.66
Interest Expense ($ in millions):
Interest expense^(b)	$	123	$	87	$	425	$	286
Interest rate derivatives – realized (gains) losses^(c)	—		(2)		(3)		(11)
Interest rate derivatives – unrealized (gains) losses^(c)	1		14		4		21
Total Interest Expense	$	124	$	99	$	426	$	296


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

(b)	Net of amounts capitalized.

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

CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED CASH FLOW DATA ($ in millions) (unaudited)
	Three Months Ended December 31,				Years Ended December 31,
	2017		2016		2017		2016

Beginning cash and cash equivalents	$	5	$	4	$	882	$	825

Net cash provided by (used in) operating activities	472		(254)		745		(204)

Cash flows from investing activities:
Drilling and completion costs^(a)	(589)		(347)		(2,186)		(1,295)
Acquisitions of proved and unproved properties^(b)	(59)		(205)		(285)		(788)
Proceeds from divestitures of proved and unproved properties	56		418		1,249		1,406
Additions to other property and equipment^(c)	(9)		(5)		(21)		(37)
Proceeds from sales of other property and equipment	15		61		55		131
Cash paid for title defects	—		—		—		(69)
Other	—		(3)		—		(8)
Net cash used in investing activities	(586)		(81)		(1,188)		(660)

Net cash provided by (used in) financing activities	114		1,213		(434)		921
Change in cash and cash equivalents	—		878		(877)		57
Ending cash and cash equivalents	$	5	$	882	$	5	$	882


(a)	Includes capitalized interest of $2 million and $2 million for the three months ended December 31, 2017 and 2016, respectively. Includes capitalized interest of $9 million and $6 million for the years ended December 31, 2017 and 2016, respectively

(b)	Includes capitalized interest of $44 million and $56 million for the three months ended December 31, 2017 and 2016, respectively. Includes capitalized interest of $184 million and $236 million for the years ended December 31, 2017 and 2016, respectively.

(c)	Includes capitalized interest of $0 and $1 million for the three months ended December 31, 2017 and 2016, respectively. Includes capitalized interest of $1 million and $1 million for the years ended December 31, 2017 and 2016, respectively.

CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS ($ in millions except per share data) (unaudited)
	Three Months Ended December 31,
	2017				2016
	$		$/Share^(b)(c)		$		$/Share^(b)(c)
Net income (loss) available to common stockholders (GAAP)	$	309	$	0.34	$	(740)	$	0.83
Effect of dilutive securities	35				—
Diluted earnings (loss) per common stockholder (GAAP)	$	344	$	0.33	$	(740)	$	(0.83)

Adjustments:
Unrealized losses on oil, natural gas and NGL derivatives	73		0.07		395		0.45
Restructuring and other termination costs	—		—		3		—
Provision for legal contingencies, net	(73)		(0.07)		11		0.01
Impairments of fixed assets and other	(5)		—		43		0.05
Net gains on sales of fixed assets	(3)		—		(7)		(0.01)
Impairments of investments	—		—		119		0.13
(Gains) losses on purchases or exchanges of debt	(50)		(0.05)		19		0.02
Loss on exchange of preferred stock	—		—		428		0.48
Income tax expense (benefit)^(a)	—		—		(190)		(0.21)
Other	4		—		13		0.01
Adjusted net income available to common stockholders^(b) (Non-GAAP)	290		0.28		94		0.10

Preferred stock dividends	23		0.02		(30)		(0.03)
Earnings allocated to participating securities	1		—		—		—
Total adjusted net income attributable to Chesapeake^{(b) (c)} (Non-GAAP)	$	314	$	0.30	$	64	$	0.07


(a)	Due to our valuation allowance position, no income tax effect from the adjustments has been included in determining adjusted net income for the three months ended December 31, 2017. Our effective tax rate in the three months ended December 31, 2016 was 35.7%.

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

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

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

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

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

(c)	Our presentation of diluted net income (loss) available to common stockholders and diluted adjusted net income (loss) per share excludes 60 million and 211 million shares considered antidilutive for the three months ended December 31, 2017 and 2016, respectively and thus excluded from the calculation. The number of shares used for the non-GAAP calculation were determined in a manner consistent with GAAP.

CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS ($ in millions except per share data) (unaudited)
	Years Ended December 31,
	2017				2016
	$		$/Share^(b)(c)		$		$/Share^(b)(c)
Net income (loss) available to common stockholders (GAAP)	$	813	$	0.90	$	(4,915)	(6.43)

Adjustments:
Unrealized losses (gains) on oil, natural gas and NGL derivatives	(354)		(0.39)		818		1.07
Unrealized losses on supply contract derivative	—		—		297		0.39
Restructuring and other termination costs	—		—		6		0.01
Provision for legal contingencies, net	(38)		(0.04)		123		0.16
Impairment of oil, natural gas and NGL properties	—		—		2,564		3.36
Impairments of fixed assets and other	421		0.46		838		1.10
Net gains on sales of fixed assets	(3)		—		(12)		(0.02)
Impairments of investments	—		—		119		0.16
Loss on sale of investment	—		—		10		0.01
Gains on purchases or exchanges of debt	(233)		(0.26)		(236)		(0.31)
Loss on exchange of preferred stock	41		0.04		428		0.56
Income tax expense (benefit)^(a)	—		—		(190)		(0.25)
Other	—		—		22		0.03
Adjusted net income (loss) available to common stockholders^(b) (Non-GAAP)	647		0.71		(128)		(0.16)

Preferred stock dividends	85		0.10		—		—
Earnings allocated to participating securities	10		0.01		97		0.13
Total adjusted net income (loss) attributable to Chesapeake^{(b) (c)} (Non-GAAP)	$	742	$	0.82	$	(31)	$	(0.03)


(a)	Due to our valuation allowance position, no income tax effect from the adjustments has been included in determining adjusted net income for the year ended December 31, 2017. Our effective tax rate in the year ended December 31, 2016 was 4.1%.

(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, or more meaningful than, net income (loss) available to common stockholders or earnings (loss) per share. Adjusted net income (loss) available to common stockholders and adjusted earnings (loss) per share exclude certain items that management believes affect the comparability of operating results. The company believes these adjusted financial measures are a useful adjunct to earnings calculated in accordance with GAAP because:

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

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

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

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

(c)	Our presentation of diluted net income (loss) available to common stockholders and diluted adjusted net income (loss) attributable to Chesapeake per share excludes 207 million and 247 million shares considered antidilutive for the years ended December 31, 2017 and 2016, respectively and thus excluded from the calculation. The number of shares used for the non-GAAP calculation were determined in a manner consistent with GAAP.

CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF OPERATING CASH FLOW AND EBITDA ($ in millions) (unaudited)
	Three Months Ended December 31,				Years Ended December 31,
	2017		2016		2017		2016

CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES (GAAP)	$	472	$	(254)	$	745	$	(204)
Changes in components of working capital and other assets and liabilities	105		147		471		761
OPERATING CASH FLOW (Non-GAAP)^(a)	$	577	$	(107)	$	1,216	$	557

	Three Months Ended December 31,				Years Ended December 31,
	2017		2016		2017		2016

NET INCOME (LOSS) (GAAP)	$	334	$	(341)	$	953	$	(4,399)
Interest expense	124		99		426		296
Income tax expense (benefit)	—		(190)		2		(190)
Depreciation and amortization of other assets	20		21		82		104
Oil, natural gas and NGL depreciation, depletion and amortization	286		212		913		1,003
EBITDA (Non-GAAP)^(b)	$	764	$	(199)	$	2,376	$	(3,186)

	Three Months Ended December 31,				Years Ended December 31,
	2017		2016		2017		2016

CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES (GAAP)	$	472	$	(254)	$	745	$	(204)
Changes in assets and liabilities	105		147		471		761
Interest expense, net of unrealized gains (losses) on derivatives	123		85		422		275
Gains (losses) on oil, natural gas and NGL derivatives, net	(41)		(444)		411		(578)
Losses on supply contract derivative, net	—		—		—		(151)
Cash (receipts) payments on derivative settlements, net	(28)		39		18		(448)
Renegotiation of natural gas gathering contract	—		49		—		115
Stock-based compensation	(11)		(12)		(49)		(52)
Restructuring and other termination costs	—		(2)		—		(3)
Provision for legal contingencies, net	77		(10)		42		(87)
Impairment of oil and natural gas properties	—		—		—		(2,564)
Impairments of fixed assets and other	5		318		(4)		(467)
Net gains on sales of fixed assets	3		7		3		12
Investment activity	—		(5)		—		(18)
Impairments of investments	—		(119)		—		(119)
Gains (losses) on purchases or exchanges of debt	50		(19)		235		236
Other items	9		21		82		106
EBITDA (Non-GAAP)^(b)	$	764	$	(199)	$	2,376	$	(3,186)


(a)	Operating cash flow represents net cash provided by operating activities before changes in components of working capital and other. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under GAAP and provides useful information to investors for analysis of the Company's ability to generate cash to fund exploration and development, and to service debt. Operating cash flow is widely accepted as a financial indicator of an oil and natural gas company's ability to generate cash that is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies within the oil and natural gas exploration and production industry. Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities as an indicator of cash flows, or as a measure of liquidity. Because operating cash flow excludes some, but not all, items that affect net cash provided by operating activities and may vary among companies, our calculation of operating cash flow may not be comparable to similarly titled measures of other companies. The increase in operating cash flow for the three months ended December 31, 2017 is mainly due to an increase in prices and volumes. Operating cash flow for the year ended December 31, 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 (or liquidity) under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations or cash flows from operating activities prepared in accordance with GAAP.

CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED EBITDA ($ in millions) (unaudited)
	Three Months Ended December 31,				Years Ended December 31,
	2017		2016		2017		2016

EBITDA (Non-GAAP)	$	764	$	(199)	$	2,376	$	(3,186)

Adjustments:
Unrealized losses (gains) on oil, natural gas and NGL derivatives	73		395		(354)		818
Unrealized losses on supply contract derivative	—		—		—		297
Restructuring and other termination costs	—		3		—		6
Provision for legal contingencies, net	(73)		11		(38)		123
Impairment of oil and natural gas properties	—		—		—		2,564
Impairments of fixed assets and other	(5)		43		421		838
Net gains on sales of fixed assets	(3)		(7)		(3)		(12)
Impairments of investments	—		119		—		119
Loss on sale of investment	—		—		—		10
(Gains) losses on purchases or exchanges of debt	(50)		19		(233)		(236)
Net loss (income) attributable to noncontrolling interests	(1)		(1)		(4)		9
Other	1		2		(5)		—

Adjusted EBITDA (Non-GAAP)^(a)	$	706	$	385	$	2,160	$	1,350


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

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

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

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

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

CHESAPEAKE ENERGY CORPORATION ROLL-FORWARD OF PROVED RESERVES YEAR ENDED DECEMBER 31, 2017 (unaudited)
	Mmboe^(a)

Beginning balance, December 31, 2016	1,708
Production	(200)
Extensions, discoveries and other additions	723
Revisions of previous estimates	(252)
Sale of reserves in-place	(71)
Purchase of reserves in-place	4
Ending balance, December 31, 2017	1,912

Proved reserves growth rate before acquisitions and divestitures	16		%
Proved reserves growth rate after acquisitions and divestitures	12		%

Proved developed reserves	1,116
Proved developed reserves percentage	58		%

Standardized measure of discounted future net cash flows ($ in millions) (GAAP)	$	7,490
Add: Present value of future income taxes discounted at 10% per annum^(a)	—
PV-10 ($ in millions)^(a) (Non-GAAP)	$	7,490

(a)

Reserve volumes and PV-10 value estimated using SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices as of December 31, 2017 of $51.34 per bbl of oil and $2.98 per mcf of natural gas, before basis differential adjustments. 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 table above shows the reconciliation of 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, 2017. Future income taxes in the calculation of the standardized measure of discounted future net cash flows were zero as of December 31, 2017, as the historical tax basis of proved oil and gas properties, net of operating loss carryforwards, and future tax deductions exceeded the undiscounted future net cash flows before income taxes of the Company's proved oil and gas reserves as of December 31, 2017.

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

PV-9 – December 31, 2017 @ NYMEX Strip	$	8,026
Less: Change in discount factor from 9 to 10	(386)
PV-10 – December 31, 2017 @ NYMEX Strip	7,640
Less: Change in pricing assumption from NYMEX Strip to SEC	(150)
PV-10 – December 31, 2017 @ SEC	7,490
Less: Present value of future income tax discounted at 10%	—
Standardized measure of discounted future cash flows – December 31, 2017^(a)	$	7,490

(a)

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 table above 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, 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.

CHESAPEAKE ENERGY CORPORATION
MANAGEMENT'S OUTLOOK AS OF FEBRUARY 22, 2018
Chesapeake periodically provides guidance on certain factors that affect the company's future financial performance.

	Year Ending 12/31/2018
Production Growth adjusted for asset sales^(a)	1% to 5%
Absolute Production
Liquids - mmbbls	51.0 - 55.0
Oil - mmbbls	31.0 - 33.0
NGL - mmbbls	20.0 - 22.0
Natural gas - bcf	825 - 875
Total absolute production - mmboe	190 - 200
Absolute daily rate - mboe	515 - 550
Estimated Realized Hedging Effects^(b) (based on 2/16/18 strip prices):
Oil - $/bbl	($5.38)
Natural gas - $/mcf	$0.19
NGL - $/bbl	$0.02
Estimated Basis to NYMEX Prices:
Oil - $/bbl	$1.00 - $1.20
Natural gas - $/mcf	($0.10) - ($0.20)
NGL - $/bbl	($5.20) - ($5.60)
Operating Costs per Boe of Projected Production:
Production expense	$2.60 - $2.80
Gathering, processing and transportation expenses	$6.95 - $7.65
Oil - $/bbl	$3.90 - $4.10
Natural Gas - $/mcf	$1.25 - $1.40
NGL - $/bbl	$7.85 - $8.25
Production taxes	$0.50 - $0.60
General and administrative^(c)	$1.25 - $1.35
Stock-based compensation (noncash)	$0.10 - $0.20
DD&A of natural gas and liquids assets	$5.00 - $6.00
Depreciation of other assets	$0.35 - $0.45
Interest expense^(d)	$2.40 - $2.60
Marketing, gathering and compression net margin^(e)	($60) - ($40)
Book Tax Rate	0%
Adjusted EBITDA, based on 2/16/18 strip prices ($ in millions)^(f)	$2,200 - $2,400
Capital Expenditures ($ in millions)^(g)	$1,800 - $2,200
Capitalized Interest ($ in millions)	$175
Total Capital Expenditures ($ in millions)	$1,975 - $2,375


(a)	Based on 2017 production of 515 mboe per day, adjusted for 2017 asset sales and 2018 asset sales signed to date.

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

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

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

(e)	Excludes non-cash amortization of approximately $22 million related to the buydown of a transportation agreement.

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

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

Oil, Natural Gas and Natural Gas Liquids Hedging Activities

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

As of February 22, 2018, including January and February derivative contracts that have settled, the company had downside price protection on a portion of its 2018 oil, natural gas and natural gas liquids production. Through swaps, the company had downside oil price protection at an average price of $52.87 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. Through swaps and two way collars, the company had downside gas price protection at an average price of $3.10 per mcf. Chesapeake also had downside ethane, propane and butane price protection through swaps at an average price of $0.28, $0.73 and $0.88 per gallon (as well as a portion of butane at 70.5% of WTI), respectively. Further details summarized below.

In addition, the company had downside protection, through open swaps on a portion of its 2019 oil production at an average price of $56.04 per bbl.

The company's crude oil hedging positions 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)

Q1 2018	5,580	$	52.26	$	(1)
Q2 2018	5,642	$	52.26	(1)
Q3 2018	5,244	$	53.52	(1)
Q4 2018	5,244	$	53.52	(1)
Total 2018	21,710	$	52.87	$	(4)

Total 2019 - 2022	3,273	$	56.04	$	(8)

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

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

Crude Oil Three-Way Collars
	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)

Q1 2018	2,610	$	3.21
Q2 2018	2,639	$	3.21
Q3 2018	2,760	$	3.42
Q4 2018	2,760	$	3.42
Total 2018	10,769	$	3.32

The company's natural gas hedging positions 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)

Q1 2018	174	$	3.44	$	(6)
Q2 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

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

Q1 2018	16	$	6.27
Q2 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)

Q1 2018	24	$	(0.08)
Q2 2018	18	$	(0.77)
Q3 2018	17	$	(0.77)
Q4 2018	6	$	(0.77)
Total 2018	65	$	(0.52)

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

Open Ethane Swaps
	Volume (mgal)	Avg. NYMEX Price of Open Swaps

Q1 2018	3,780	$	0.28
Q2 2018	3,822	$	0.28
Total 2018	7,602	$	0.28

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

Q1 2018	3,780	$	0.73
Q2 2018	3,822	$	0.73
Q3 2018	3,864	$	0.73
Q4 2018	3,864	$	0.73
Total 2018	15,330	$	0.73

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

Q1 2018	1,323	$	0.88
Q2 2018	1,338	$	0.88
Q3 2018	1,352	$	0.88
Q4 2018	1,352	$	0.88
Total 2018	5,365	$	0.88

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

Q1 2018	1,323	70.5	%
Q2 2018	1,337	70.5	%
Q3 2018	1,352	70.5	%
Q4 2018	1,352	70.5	%
Total 2018	5,364	70.5	%

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