Exhibit

EX-99.1 2 chk-ex_991x20160630x8kxpr.htm EXHIBIT 99.1 Exhibit



		EXHIBIT 99.1
News Release

FOR IMMEDIATE RELEASE

AUGUST 4, 2016

CHESAPEAKE ENERGY CORPORATION REPORTS 2016 SECOND QUARTER

FINANCIAL AND OPERATIONAL RESULTS

OKLAHOMA CITY, August 4, 2016 – Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operational results for the 2016 second quarter. Highlights include:


•	Total debt reduction of more than $1.0 billion year to date


•	2016 second quarter production averaged approximately 657,100 boe per day; company increases full-year 2016 production guidance by 3% while maintaining capital expenditure guidance


•	Cost structure improvements lead to lower full-year 2016 production expense guidance


•	Company increases target of 2016 total gross proceeds from asset divestitures by year-end to more than $2.0 billion from $1.2 to $1.7 billion; selected Haynesville Shale acreage expected to be sold

Doug Lawler, Chesapeake’s Chief Executive Officer, commented, “In 2016, we have made substantial progress on many fronts, including the reduction of more than $1 billion of debt, the reduction of complexity in our portfolio through the purchase of oil and natural gas interests previously conveyed in certain volumetric production payment transactions (VPPs), the continued improvement in our cash cost structure and the optimization of our current portfolio through non-core asset sales.

“Financial discipline remains our top priority, and we continue to work toward additional solutions to improve our liquidity, reduce our midstream commitments and enhance our margins. With continued improvements in our operating expenses and the disposition of non-core properties, we have refined our portfolio to provide a more competitive foundation for Chesapeake. In addition, the application of new technologies, including longer laterals and enhanced completion techniques, to our extensive undeveloped acreage position provides us with a robust portfolio of development opportunities.”

Lawler continued, “As a result of our portfolio’s strong performance to date in 2016, we have increased our total production guidance for the remainder of the year. As for an initial look into 2017, we believe our oil production will be relatively flat in 2017 as compared to 2016, while total production volumes are projected to be down approximately 5% compared to 2016 levels. With the breadth and depth of our large acreage position, the evolution of technologies being applied to our portfolio and the reduction in our leverage and complexity, we believe that the next few months will be a very exciting time for Chesapeake.”

2016 Second Quarter Results

For the 2016 second quarter, Chesapeake’s revenues declined by 54% year over year, primarily due to a decrease in the average realized commodity prices received for its production, unrealized losses from oil and natural gas derivatives and a decrease in the average realized commodity prices received for its marketing operations. Average daily production for the 2016 second quarter of approximately 657,100 barrels of oil equivalent (boe) consisted of approximately 90,500 barrels (bbls) of oil, 2.960 billion cubic feet (bcf) of natural gas and 73,200 bbls of natural gas liquids (NGL). As a result of the company's strong production through the first six months of 2016, Chesapeake has raised its full-year 2016 production




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

guidance by 3% (using midpoints) from 605,000 to 635,000 boe per day to a new range of 625,000 to 650,000 boe per day. A summary of the company’s guidance for 2016 is provided in the Outlook dated August 4, 2016, beginning on Page 17.

Chesapeake's cash expenses continue to decline due to its focus on cost discipline. Average production expenses during the 2016 second quarter were $3.05 per boe. G&A expenses (including stock-based compensation) during the 2016 second quarter were $1.02 per boe. Combined production and G&A expenses (including stock-based compensation) during the 2016 second quarter were $4.07 per boe, a decrease of 25% year over year and 2% from the 2016 first quarter.

Chesapeake reported a net loss available to common stockholders of $1.792 billion, or $2.48 per share, while the company's ebitda for the 2016 second quarter was $(1.394) billion. The primary drivers of the net loss were a noncash impairment of the carrying value of Chesapeake's oil and natural gas properties of approximately $1.045 billion, largely resulting from decreases in the trailing 12-month average first-day-of-the-month oil and natural gas prices as of June 30, 2016, as compared to March 31, 2016, and unrealized hedging losses of approximately $544 million. Adjusting for these and other items that are typically excluded by securities analysts, the 2016 second quarter adjusted net loss available to common stockholders was $145 million, or $0.14 per common share, while the company's adjusted ebitda was $252 million in the 2016 second quarter. Reconciliations of financial measures calculated in accordance with generally accepted accounting principles (GAAP) to non-GAAP measures are provided on pages 12 – 16 of this release.

Capital Spending Overview

Chesapeake’s total capital investments were approximately $456 million during the 2016 second quarter, compared to approximately $957 million in the 2015 second quarter, as summarized in the table below. While the company has reiterated its total capital investments program for 2016 of approximately $1.3 to $1.8 billion, it now expects to be at the higher end of its current guidance range due to additional drilling and completion activity as a result of efficiency gains and an acquisition of additional working interests in the Haynesville Shale. A summary of the company’s guidance for 2016 is provided in the Outlook dated August 4, 2016, beginning on Page 17.



	2016		2016		2015
Activity Comparison	Q2		Q1		Q2
Average operated rig count	9		8		26
Gross wells completed	131		57		121
Gross wells spud	49		41		109
Gross wells connected	141		80		173

Type of Cost ($ in millions)
Drilling and completion costs	$	337	$	281	$	787
Exploration costs and additions to other PP&E	56		16		56
Subtotal capital expenditures	$	393	$	297	$	843
Capitalized interest	63		68		114
Total capital expenditures	$	456	$	365	$	957

Balance Sheet and Liquidity

As of June 30, 2016, Chesapeake’s debt principal balance was approximately $8.7 billion, including approximately $100 million of borrowings outstanding on the company's $4.0 billion revolving credit facility, compared to $9.7 billion as of December 31, 2015, and $11.7 billion as of June 30, 2015. Since January

1, 2016, the company has retired at maturity, repurchased or exchanged for equity approximately $1.0 billion of debt, $518 million of which was due or putable to the company in 2017.

In April 2016, Chesapeake amended its $4.0 billion revolving credit facility maturing in 2019 to reaffirm its borrowing base, restructure financial covenants and increase its ability to issue secured debt. Using June 30, 2016 crude oil and natural gas strip pricing, Chesapeake estimates that the PV-10 of its proved oil and gas reserves was approximately $11.1 billion, compared to approximately $3.1 billion when using the average of commodity prices on the first day of the month over the trailing 12-month period (see Page 16 of this release for additional information). In addition to $100 million of borrowings under the company's revolving credit facility, letters of credit issued under the credit facility were approximately $813 million as of June 30, 2016, which included a $461 million supersedeas bond supporting the company's appeal of the judgment issued in 2015 with respect to the company's 2019 Notes litigation.

Asset Acquisition and Divestitures Update

Through the 2016 second quarter, the company’s asset divestiture activities have totaled $964 million in net proceeds received to date, after post-closing adjustments. In addition, consideration of more than $100 million was withheld subject to certain title, environmental and other standard contingencies, the majority of which Chesapeake expects to collect in the third quarter. In conjunction with certain of these sales, Chesapeake repurchased oil and natural gas interests previously sold to third parties in connection with four of its VPP transactions for approximately $259 million. A majority of the acquired interests were part of the asset divestitures discussed above and the company no longer has any further commitments related to these VPPs. With the closing of these VPP acquisitions in the 2016 second quarter, the company has only two VPPs remaining.

The company continues to focus on select asset divestitures and is currently planning to sell additional properties by year-end 2016, including a portion of its Haynesville Shale properties. As a result, Chesapeake has raised its 2016 guidance for total gross asset divestitures either closed or under signed sales agreements to now be more than $2.0 billion, compared to its previous range of $1.2 to $1.7 billion.

In July 2016, Chesapeake purchased certain operated working interests to enhance its Haynesville Shale acreage position for approximately $87 million, increasing its average operated working interest in the area to approximately 83% and adding to its net acreage position by approximately 70,000 net acres. The company closed this transaction in the 2016 third quarter.

Operations Update

Chesapeake is currently utilizing 10 drilling rigs across its operating areas, three of which are located in the Eagle Ford Shale, three in the Haynesville Shale, three in the Mid-Continent area and one rig in the Utica Shale. Due to greater capital efficiencies and lower oilfield service costs, Chesapeake is currently planning to operate these 10 rigs throughout the remainder of the year and, as a result, plans to drill more than 100 additional wells and place approximately 75 additional wells on production in 2016. While the company is maintaining its 2016 total capital expenditures guidance to be approximately $1.3 to $1.8 billion, it now expects to be at the higher end of its current guidance range.

In July 2016, Chesapeake placed the CA 12&13-15-15 1H horizontal well on production, targeting the Haynesville Shale in Caddo Parish, Louisiana. This well's results provide further confirmation that the company's current completion optimization techniques, along with extended laterals, are having a significant impact on higher sustained flow rates and the increased potential for higher rates of return in all areas of the Haynesville. With reducing cluster spacing and increased proppant loading, this 10,000-foot lateral well reached a maximum production rate of approximately 38.0 million cubic feet of gas (mmcf) per day with a flowing tubing pressure of 7,400 psi. The company's current estimate of the ultimate recovery from this well is approximately 22 to 24 bcf with an estimated completed well cost of approximately $9.8 million. The PCK 1H, a 7,500-foot lateral well located in DeSoto Parish, reached a maximum production rate of 31.0 mmcf per day with a flowing pressure of 7,600 psi using similar completion techniques for an estimated well cost of $8.4 million. Chesapeake believes that leading-edge completion techniques, along with access to Gulf Coast pricing, could increase field-wide productivity by opening up new areas in the field that were previously economically challenged.

Key Financial and Operational Results

The table below summarizes Chesapeake’s key financial and operational results during the 2016 second quarter as compared to results in prior periods.



	Three Months Ended
	06/30/16		03/31/16		06/30/15
Oil equivalent production (in mmboe)	60		61		64
Oil production (in mmbbls)	8		9		11
Average realized oil price ($/bbl)^(a)	44.31		37.74		71.39
Natural gas production (in bcf)	269		276		275
Average realized natural gas price ($/mcf)^(a)	1.97		2.29		2.35
NGL production (in mmbbls)	7		6		7
Average realized NGL price ($/bbl)^(a)	12.88		11.44		13.02
Production expenses ($/boe)	(3.05	)	(3.36	)	(4.32	)
Gathering, processing and transportation expenses ($/boe)	(8.04	)	(7.88	)	(7.64	)
Production taxes ($/boe)	(0.32	)	(0.30	)	(0.52	)
General and administrative expenses ($/boe)^(b)	(0.86	)	(0.66	)	(0.89	)
Stock-based compensation ($/boe)	(0.16	)	(0.13	)	(0.19	)
DD&A of oil and natural gas properties ($/boe)	(4.43	)	(4.43	)	(9.39	)
DD&A of other assets ($/boe)	(0.48	)	(0.48	)	(0.52	)
Interest expenses ($/boe)^(a)	(1.00	)	(0.98	)	(1.12	)
Marketing, gathering and compression net margin ($ in millions)^(c)	(25	)	18		209
Operating cash flow ($ in millions)^(d)	176		263		572
Operating cash flow ($/boe)	2.94		4.29		8.94
Adjusted ebitda ($ in millions)^(e)	252		282		600
Adjusted ebitda ($/boe)	4.21		4.61		9.37
Net loss available to common stockholders ($ in millions)	(1,792	)	(964	)	(4,151	)
Loss per share – diluted ($)	(2.48	)	(1.44	)	(6.27	)
Adjusted net loss available to common stockholders ($ in millions)^(f)	(145	)	(120	)	(126	)
Adjusted loss per share ($) ^(g)	(0.14	)	(0.12	)	(0.13	)


(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 ($37 million), $20 million and $220 million of unrealized gains (losses) on supply contract derivatives for the three months ended June 30, 2016, March 31, 2016 and June 30, 2015, respectively. Excludes depreciation and amortization of other assets.


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


(e)	Defined as net income before interest expense, income taxes and depreciation, depletion and amortization expense, as adjusted to remove the effects of certain items detailed on page 16.


(f)	Defined as net income available to common stockholders, as adjusted to remove the effects of certain items detailed on page 12.


(g)	We have revised our presentation of adjusted loss per share to exclude shares considered antidilutive when calculating earnings per share in accordance with GAAP.

2016 Second Quarter Financial and Operational Results Conference Call Information

A conference call to discuss this release has been scheduled on Thursday, August 4, 2016, at 9:00 am EDT. The telephone number to access the conference call is 866-454-4209 or international toll 913-312-9308. The passcode for the call is 4546210. 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 4546210. The conference call will also be webcast live 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 gathering and compression businesses. Further information is available at www.chk.com where Chesapeake routinely posts announcements, updates, events, investor information, presentations and news releases.

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 or forecasts of future events, production and well connection forecasts, estimates of operating costs, anticipated capital and operational efficiencies, planned development drilling and expected drilling cost reductions, general and administrative expenses, capital expenditures, the timing of anticipated noncore asset sales and proceeds to be received therefrom, projected cash flow and liquidity, our ability to enhance our cash flow and financial flexibility, plans and objectives for future operations (including our ability to optimize base production and execute gas gathering agreements), 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 or at all; the availability of cash flows from operations and other funds to finance reserve replacement costs or satisfy our debt obligations; a further 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 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 of our spin-off of Seventy Seven Energy Inc. (SSE) 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 and preferred stock; certain anti-takeover provisions that affect shareholder rights; and our inability to increase or maintain our liquidity through debt repurchases, capital exchanges, asset sales, joint ventures, farmouts or other means.

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



CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ in millions, except per share data)
(unaudited)

	Three Months Ended June 30,
	2016			2015
REVENUES:
Oil, natural gas and NGL	$	440		$	1,216
Marketing, gathering and compression	1,182			2,305
Total Revenues	1,622			3,521
OPERATING EXPENSES:
Oil, natural gas and NGL production	182			276
Oil, natural gas and NGL gathering, processing and transportation	481			488
Production taxes	19			34
Marketing, gathering and compression	1,207			2,096
General and administrative	61			69
Restructuring and other termination costs	3			(4		)
Provision for legal contingencies	82			334
Oil, natural gas and NGL depreciation, depletion and amortization	265			601
Depreciation and amortization of other assets	29			34
Impairment of oil and natural gas properties	1,045			5,015
Impairments of fixed assets and other	6			84
Net (gains) losses on sales of fixed assets	(1		)	1
Total Operating Expenses	3,379			9,028
LOSS FROM OPERATIONS	(1,757		)	(5,507		)
OTHER INCOME (EXPENSE):
Interest expense	(62		)	(71		)
Losses on investments	(2		)	(17		)
Gains on purchases or exchanges of debt	68			—
Other income (expense)	3			(1		)
Total Other Income (Expense)	7			(89		)
LOSS BEFORE INCOME TAXES	(1,750		)	(5,596		)
INCOME TAX BENEFIT:
Current income taxes	—			(6		)
Deferred income taxes	—			(1,500		)
Total Income Tax Benefit	—			(1,506		)
NET LOSS	(1,750		)	(4,090		)
Net income attributable to noncontrolling interests	—			(18		)
NET LOSS ATTRIBUTABLE TO CHESAPEAKE	(1,750		)	(4,108		)
Preferred stock dividends	(42		)	(43		)
NET LOSS AVAILABLE TO COMMON STOCKHOLDERS	$	(1,792	)	$	(4,151	)
LOSS PER COMMON SHARE:
Basic	$	(2.48	)	$	(6.27	)
Diluted	$	(2.48	)	$	(6.27	)
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic	724			662
Diluted	724			662



CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ in millions, except per share data)
(unaudited)

	Six Months Ended June 30,
	2016			2015
REVENUES:
Oil, natural gas and NGL	$	1,433		$	2,759
Marketing, gathering and compression	2,142			3,980
Total Revenues	3,575			6,739
OPERATING EXPENSES:
Oil, natural gas and NGL production	388			575
Oil, natural gas and NGL gathering, processing and transportation	963			946
Production taxes	37			62
Marketing, gathering and compression	2,149			3,796
General and administrative	109			125
Restructuring and other termination costs	3			(14		)
Provision for legal contingencies	104			359
Oil, natural gas and NGL depreciation, depletion and amortization	536			1,285
Depreciation and amortization of other assets	58			69
Impairment of oil and natural gas properties	1,898			9,991
Impairments of fixed assets and other	44			88
Net (gains) losses on sales of fixed assets	(5		)	4
Total Operating Expenses	6,284			17,286
LOSS FROM OPERATIONS	(2,709		)	(10,547		)
OTHER INCOME (EXPENSE):
Interest expense	(124		)	(122		)
Losses on investments	(2		)	(24		)
Loss on sale of investment	(10		)	—
Gains on purchases or exchanges of debt	168			—
Other income	6			5
Total Other Income (Expense)	38			(141		)
LOSS BEFORE INCOME TAXES	(2,671		)	(10,688		)
INCOME TAX BENEFIT:
Current income taxes	—			(6		)
Deferred income taxes	—			(2,872		)
Total Income Tax Benefit	—			(2,878		)
NET LOSS	(2,671		)	(7,810		)
Net income attributable to noncontrolling interests	—			(37		)
NET LOSS ATTRIBUTABLE TO CHESAPEAKE	(2,671		)	(7,847		)
Preferred stock dividends	(85		)	(86		)
NET LOSS AVAILABLE TO COMMON STOCKHOLDERS	$	(2,756	)	$	(7,933	)
LOSS PER COMMON SHARE:
Basic	$	(3.97	)	$	(11.99	)
Diluted	$	(3.97	)	$	(11.99	)
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic	695			662
Diluted	695			662



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

	June 30, 2016			December 31, 2015

Cash and cash equivalents	$	4		$	825
Other current assets	1,200			1,655
Total Current Assets	1,204			2,480

Property and equipment, (net)	11,685			14,298
Other assets	598			536
Total Assets	$	13,487		$	17,314

Current liabilities	$	3,777		$	3,685
Long-term debt, net	8,621			10,311
Other long-term liabilities	860			921
Total Liabilities	13,258			14,917

Preferred stock	3,036			3,062
Noncontrolling interests	261			259
Common stock and other stockholders’ equity	(3,068		)	(924		)
Total Equity	229			2,397

Total Liabilities and Equity	$	13,487		$	17,314

Common shares outstanding (in millions)	775			663
Principal amount of debt outstanding	$	8,679		$	9,706



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

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Net Production:
Oil (mmbbl)	8			11			17			22
Natural gas (bcf)	269			275			546			539
NGL (mmbbl)	7			7			13			14
Oil equivalent (mmboe)	60			64			121			126

Oil, natural gas and NGL Sales ($ in millions):
Oil sales	$	355		$	594		$	610		$	1,080
Oil derivatives – realized gains (losses)^(a)	11			182			84			417
Oil derivatives – unrealized gains (losses)^(a)	(168		)	(234		)	(240		)	(344		)
Total Oil Sales	198			542			454			1,153

Natural gas sales	440			577			923			1,347
Natural gas derivatives – realized gains (losses)^(a)	92			71			242			271
Natural gas derivatives – unrealized gains (losses)^(a)	(365		)	(67		)	(335		)	(231		)
Total Natural Gas Sales	167			581			830			1,387

NGL sales	89			93			163			219
NGL derivatives – realized gains (losses)^(a)	(3		)	—			(3		)	—
NGL derivatives – unrealized gains (losses)^(a)	(11		)	—			(11		)	—
Total NGL Sales	75			93			149			219
Total Oil, Natural Gas and NGL Sales	$	440		$	1,216		$	1,433		$	2,759

Average Sales Price – excluding gains (losses) on derivatives:
Oil ($ per bbl)	$	43.00		$	54.69		$	35.98		$	49.48
Natural gas ($ per mcf)	$	1.63		$	2.09		$	1.69		$	2.50
NGL ($ per bbl)	$	13.37		$	13.02		$	12.43		$	15.64
Oil equivalent ($ per boe)	$	14.76		$	19.77		$	14.01		$	21.04

Average Sales Price – including realized gains (losses) on derivatives:
Oil ($ per bbl)	$	44.31		$	71.39		$	40.93		$	68.55
Natural gas ($ per mcf)	$	1.97		$	2.35		$	2.14		$	3.00
NGL ($ per bbl)	$	12.88		$	13.02		$	12.17		$	15.64
Oil equivalent ($ per boe)	$	16.43		$	23.72		$	16.68		$	26.51

Interest Expense ($ in millions):
Interest^(b)	$	63		$	72		$	125		$	134
Interest rate derivatives – realized (gains) losses^(c)	(3		)	(1		)	(6		)	(2		)
Interest rate derivatives – unrealized (gains) losses^(c)	2			—			5			(10		)
Total Interest Expense	$	62		$	71		$	124		$	122

(a)

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


(b)	Net of amounts capitalized.


(c)	Realized (gains) losses include settlements related to the current period interest accrual and the effect of (gains) losses on early termination trades. Unrealized (gains) losses include changes in the fair value of open interest rate derivatives offset by amounts reclassified to realized (gains) losses during the period.



CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
($ in millions)
(unaudited)

THREE MONTHS ENDED:	June 30, 2016			June 30, 2015

Beginning cash	$	16		$	2,907

Net cash provided by operating activities	95			314

Cash flows from investing activities:
Drilling and completion costs^(a)	(344		)	(862		)
Acquisitions of proved and unproved properties^(b)	(359		)	(138		)
Divestitures of proved and unproved properties	833			(7		)
Additions to other property and equipment^(c)	(15		)	(35		)
Proceeds from sales of other property and equipment	61			5
Other	(2		)	(3		)
Net cash provided by (used in) investing activities	174			(1,040		)

Net cash used in financing activities	(281		)	(130		)
Change in cash and cash equivalents	(12		)	(856		)
Ending cash	$	4		$	2,051


(a)	Includes capitalized interest of $1 million and $7 million for the three months ended June 30, 2016 and 2015, respectively.


(b)	Includes capitalized interest of $60 million and $104 million for the three months ended June 30, 2016 and 2015, respectively.


(c)	Includes capitalized interest of a nominal amount and $1 million for the three months ended June 30, 2016 and 2015, respectively.



CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
($ in millions)
(unaudited)

SIX MONTHS ENDED:	June 30, 2016			June 30, 2015

Beginning cash	$	825		$	4,108

Net cash provided by (used in) operating activities	(326		)	737

Cash flows from investing activities:
Drilling and completion costs^(a)	(609		)	(2,168		)
Acquisitions of proved and unproved properties^(b)	(426		)	(266		)
Proceeds from divestitures of proved and unproved properties	964			14
Additions to other property and equipment^(c)	(25		)	(93		)
Proceeds from sales of other property and equipment	70			7
Cash paid for title defects	(69		)	—
Additions to investments	—			(1		)
Other	(4		)	(5		)
Net cash used in investing activities	(99		)	(2,512		)

Net cash used in financing activities	(396		)	(282		)
Change in cash and cash equivalents	(821		)	(2,057		)
Ending cash	$	4		$	2,051


(a)	Includes capitalized interest of $3 million and $18 million for the six months ended June 30, 2016 and 2015, respectively.


(b)	Includes capitalized interest of $124 million and $212 million for the six months ended June 30, 2016 and 2015, respectively.


(c)	Includes capitalized interest of $1 million and $2 million for the six months ended June 30, 2016 and 2015, respectively.



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

THREE MONTHS ENDED:	June 30, 2016			June 30, 2015

Net loss available to common stockholders	$	(1,792	)	$	(4,151	)

Weighted average common and common equivalent shares outstanding ^(a)	724			662

Loss per common share (diluted)	$	(2.48	)	$	(6.27	)

Adjustments:
Unrealized losses on commodity and interest rate derivatives	$	546		$	301
Unrealized (gains) losses on supply contract derivatives	37			(220		)
Restructuring and other termination costs	3			(4		)
Provision for legal contingencies	82			334
Impairment of oil and natural gas properties	1,045			5,015
Impairments of fixed assets and other	6			84
Net (gains) losses on sales of fixed assets	(1		)	1
Gains on purchases or exchanges of debt	(68		)	—
Other	(3		)	(3		)
Tax effect of above items^(b)	—			(1,483		)
Adjusted net loss available to common stockholders^(c)	$	(145	)	$	(126	)

Preferred stock dividends	42			43
Total adjusted net loss attributable to Chesapeake	$	(103	)	$	(83	)

Adjusted loss per share^{(c) (d)}	$	(0.14	)	$	(0.13	)

(a) Weighted average common and common equivalent shares outstanding do not include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP.

(b) Our effective tax rate in the three months ended June 30, 2016 was 0%; thus, there is no tax effect on the reconciling adjustments.

(c)

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


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


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


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

(d) We have revised our presentation of adjusted loss per share to exclude shares considered antidilutive when calculating earnings per share in accordance with GAAP.



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

SIX MONTHS ENDED:	June 30, 2016			June 30, 2015

Net loss available to common stockholders	$	(2,756	)	$	(7,933	)

Weighted average common and common equivalent shares outstanding ^(a)	695			662

Loss per common share (diluted)	$	(3.97	)	$	(11.99	)

Adjustments:
Unrealized losses on commodity and interest rate derivatives	$	591		$	565
Unrealized (gains) losses on supply contract derivatives	17			(220		)
Restructuring and other termination costs	3			(14		)
Provision for legal contingencies	104			359
Impairment of oil and natural gas properties	1,898			9,991
Impairments of fixed assets and other	44			88
Net (gains) losses on sales of fixed assets	(5		)	4
Loss on sale of investment	10			—
Gains on purchases or exchanges of debt	(168		)	—
Tax rate adjustment	—			(17		)
Other	(2		)	(7		)
Tax effect of above items^(b)	—			(2,900		)
Adjusted net loss available to common stockholders^(c)	$	(264	)	$	(84	)

Preferred stock dividends	85			86
Total adjusted net income (loss) attributable to Chesapeake	$	(179	)	$	2

Adjusted earnings (loss) per common share^{(c) (d)}	$	(0.26	)	$	0.00

(a) Weighted average common and common equivalent shares outstanding do not include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP.

(b) Our effective tax rate in the six months ended June 30, 2016 was 0%; thus, there is no tax effect on the reconciling adjustments.

(c)

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


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


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


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

(d) We have revised our presentation of adjusted loss per share to exclude shares considered antidilutive when calculating earnings per share in accordance with GAAP.



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

THREE MONTHS ENDED:	June 30, 2016		June 30, 2015

CASH PROVIDED BY OPERATING ACTIVITIES	$	95	$	314
Changes in assets and liabilities	81		258
OPERATING CASH FLOW^(a)	$	176	$	572




THREE MONTHS ENDED:	June 30, 2016			June 30, 2015

NET LOSS	$	(1,750	)	$	(4,090	)
Interest expense	62			71
Income tax benefit	—			(1,506		)
Depreciation and amortization of other assets	29			34
Oil, natural gas and NGL depreciation, depletion and amortization	265			601
EBITDA^(b)	$	(1,394	)	$	(4,890	)




THREE MONTHS ENDED:	June 30, 2016			June 30, 2015

CASH PROVIDED BY OPERATING ACTIVITIES	$	95		$	314
Changes in assets and liabilities	81			258
Interest expense, net of unrealized gains (losses) on derivatives	59			71
Losses on commodity derivatives, net	(444		)	(48		)
Gains (losses) on supply contract derivatives, net	(37		)	220
Cash receipts on commodity derivative settlements, net	(119		)	(223		)
Stock-based compensation	(13		)	(20		)
Restructuring and other termination costs	(3		)	4
Provision for legal contingencies	(82		)	(334		)
Impairment of oil and natural gas properties	(1,045		)	(5,015		)
Impairments of fixed assets and other	(1		)	(79		)
Net gains (losses) on sales of fixed assets	1			(1		)
Investment activity	(2		)	(17		)
Gains on purchases or exchanges of debt	68			—
Other items	48			(20		)
EBITDA^(b)	$	(1,394	)	$	(4,890	)

(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, investing or financing 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 flow provided by operating activities prepared in accordance with GAAP.



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

SIX MONTHS ENDED:	June 30, 2016			June 30, 2015

CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	(326	)	$	737
Changes in assets and liabilities	765			719
OPERATING CASH FLOW^(a)	$	439		$	1,456




SIX MONTHS ENDED:	June 30, 2016			June 30, 2015

NET LOSS	$	(2,671	)	$	(7,810	)
Interest expense	124			122
Income tax benefit	—			(2,878		)
Depreciation and amortization of other assets	58			69
Oil, natural gas and NGL depreciation, depletion and amortization	536			1,285
EBITDA^(b)	$	(1,953	)	$	(9,212	)




SIX MONTHS ENDED:	June 30, 2016			June 30, 2015

CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	(326	)	$	737
Changes in assets and liabilities	765			719
Interest expense, net of unrealized gains (losses) on derivatives	119			132
Gains (losses) on commodity derivatives, net	(263		)	113
Gains (losses) on supply contract derivatives, net	(17		)	220
Cash receipts on commodity derivative settlements, net	(386		)	(636		)
Stock-based compensation	(25		)	(43		)
Restructuring and other termination costs	(3		)	14
Provision for legal contingencies	(104		)	(359		)
Impairment of oil and natural gas properties	(1,898		)	(9,991		)
Impairments of fixed assets and other	(34		)	(81		)
Net gains (losses) on sales of fixed assets	5			(4		)
Investment activity	(12		)	(24		)
Gains on purchases or exchanges of debt	168			—
Other items	58			(9		)
EBITDA^(b)	$	(1,953	)	$	(9,212	)

(a)

(b)



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

THREE MONTHS ENDED:	June 30, 2016			June 30, 2015

EBITDA	$	(1,394	)	$	(4,890	)

Adjustments:
Unrealized losses on commodity derivatives	544			301
Unrealized (gains) losses on supply contract derivatives	37			(220		)
Restructuring and other termination costs	3			(4		)
Provision for legal contingencies	82			334
Impairment of oil and natural gas properties	1,045			5,015
Impairments of fixed assets and other	6			84
Net (gains) losses on sales of fixed assets	(1		)	1
Gains on purchases or exchanges of debt	(68		)	—
Net income attributable to noncontrolling interests	—			(18		)
Other	(2		)	(3		)

Adjusted EBITDA^(a)	$	252		$	600



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

SIX MONTHS ENDED:	June 30, 2016			June 30, 2015

EBITDA	$	(1,953	)	$	(9,212	)

Adjustments:
Unrealized losses on commodity derivatives	586			575
Unrealized (gains) losses on supply contract derivatives	17			(220		)
Restructuring and other termination costs	3			(14		)
Provision for legal contingencies	104			359
Impairment of oil and natural gas properties	1,898			9,991
Impairments of fixed assets and other	44			88
Net (gains) losses on sales of fixed assets	(5		)	4
Loss on sale of investment	10			—
Gains on purchases or exchanges of debt	(168		)	—
Net income attributable to noncontrolling interests	—			(37		)
Other	(2		)	(6		)

Adjusted EBITDA^(a)	$	534		$	1,528


(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 and asset retirement obligations. 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, 2015 and for the interim period ended June 30, 2016. Management believes that PV-9 provides useful information to investors regarding the company's collateral position and that PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, management believes the use of a pre-tax measure is valuable for evaluating the company. Neither PV-9 nor PV-10 should be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP. With respect to PV-9 and PV-10 calculated as of an interim date, it is not practical to calculate taxes for the related interim period because GAAP does not provide for disclosure of standardized measure on an interim basis.



PV-9 – June 30, 2016 @ NYMEX Strip	$	11,857
Less: Change in discount factor from 9 to 10	(807		)
PV-10 – June 30, 2016 @ NYMEX Strip	11,050
Less: Change in pricing assumption from NYMEX Strip to SEC	(7,995		)
PV-10 – June 30, 2016 @ SEC	3,055
Change in PV-10 from 12/31/15 to 6/30/16	1,672
PV-10 – December 31, 2015 @ SEC	4,727
Less: Present value of future income tax discounted at 10%	(34		)
Standardized measure of discounted future cash flows – December 31, 2015	$	4,693

CHESAPEAKE ENERGY CORPORATION

MANAGEMENT’S OUTLOOK AS OF AUGUST 4, 2016

Chesapeake periodically provides guidance on certain factors that affect the company’s future financial performance. Changes from the company's May 5, 2016 Outlook are italicized bold below.



	Year Ending 12/31/2016
Adjusted Production Growth^(a)	(3%) to 2%
Absolute Production
Liquids - mmbbls	56 - 60
Oil - mmbbls	33 - 35
NGL- mmbbls	23 - 25
Natural gas - bcf	1,030 - 1,070
Total absolute production - mmboe	228 - 238
Absolute daily rate - mboe	625 - 650
Estimated Realized Hedging Effects^(b) (based on 8/1/16 strip prices):
Oil - $/bbl	$4.63
Natural gas - $/mcf	$0.13
NGL - $/bbl	($0.18)
Estimated Basis to NYMEX Prices:
Oil - $/bbl	$2.55 - $2.65
Natural gas - $/mcf	$0.35 - $0.45
NGL - $/bbl	$5.20 - $5.45
Operating Costs per Boe of Projected Production:
Production expense	$3.20 - $3.40
Gathering, processing and transportation expenses	$7.60 - $8.10
Oil - $/bbl	$3.75 - $3.95
Natural Gas^(c) - $/mcf	$1.40 - $1.50
NGL - $/bbl	$7.60 - $7.85
Production taxes	$0.35 - $0.45
General and administrative^(d)	$0.60 - $0.70
Stock-based compensation (noncash)	$0.10 - $0.20
DD&A of natural gas and liquids assets	$3.50 - $4.50
Depreciation of other assets	$0.40 - $0.50
Interest expense^(e)	$1.05 - $1.15
Marketing, gathering and compression net margin^(f)	($10) - $10
Book Tax Rate	0%
Capital Expenditures ($ in millions)^(g)	$1,000 - $1,500
Capitalized Interest ($ in millions)	$260
Total Capital Expenditures ($ in millions)	$1,260 - $1,760


(a)	Based on 2015 production of 621 mboe per day, adjusted for 2015 and 2016 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 a 2016 fourth quarter minimum volume commitment (MVC) shortfall estimate of approximately $165 to $175 million.


(d)	Excludes expenses associated with stock-based compensation.


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


(f)	Includes revenue and operating expenses. Excludes depreciation and amortization of other assets and unrealized gains (losses) on supply contract derivatives.


(g)	Includes capital expenditures for drilling and completion, leasehold, geological and geophysical costs, rig termination payments and other property and plant and equipment. Excludes approximately $259 million for the repurchase of overriding royalty interests associated with the sale of certain of the company's properties and 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 August 1, 2016, the company had downside protection, through open swaps, on a portion of its remaining 2016 oil production at an average price of $46.60 per bbl. The company had downside price protection, through open swaps and two-way collars, on a portion of its remaining 2016 natural gas production at an average price of $2.77 per mcf. Chesapeake also had downside price protection, through open swaps, on a portion of its remaining 2016 ethane and propane production at an average price of $0.17 per gallon and $0.46 per gallon, respectively.

The company’s crude oil hedging positions as of August 1, 2016 were as follows:



Open Crude Oil Swaps; Gains from Closed
Crude Oil Trades and Call Option Premiums

	Open Swaps (mbbls)	Avg. NYMEX Price of Open Swaps		Total Gains from Closed Trades and Premiums for Call Options ($ in millions)
Q3 2016	6,072	$	46.35	$	10
Q4 2016	6,072	$	46.84	10
Total 2016 ^(a)	12,144	$	46.60	$	20
Total 2017 – 2022	7,665	$	47.79	$	78

(a) Certain hedging arrangements include a sold option to extend at an average price of $53.67 per bbl covering 1.5 mmbbls in 2016. Sold options are included with net written call options.



Crude Oil Net Written Call Options

	Call Options (mbbls)	Avg. NYMEX Strike Price
Q3 2016	3,489	$	87.25
Q4 2016	3,488	$	87.25
Total 2016	6,977	$	87.25
Total 2017	5,293	$	83.50

The company’s natural gas hedging positions as of August 1, 2016 were as follows:



Open Natural Gas Swaps; Losses from Closed
Natural Gas Trades and Call Option Premiums

	Open Swaps (bcf)	Avg. NYMEX Price of Open Swaps		Total Losses from Closed Trades and Premiums for Call Options ($ in millions)
Q3 2016	203	$	2.69	$	(26	)
Q4 2016	155	$	2.85	(28		)
Total 2016 ^(a)	358	$	2.76	$	(54	)
Total 2017 – 2022	267	$	3.02	$	(78	)

(a) Certain hedging arrangements include a sold option to extend at an average price of $2.80 per mmbtu covering 52 bcf in 2016. Sold options are included with net written call options.



Natural Gas Two-Way Collars

	Open Collars (bcf)	Avg. NYMEX Bought Put Price		Avg. NYMEX Sold Call Price
Q4 2016	15	$	3.00	$	3.48
Total 2016	15	$	3.00	$	3.48
Total 2017	23	$	3.00	$	3.48



Natural Gas Net Written Call Options

	Call Options (bcf)	Avg. NYMEX Strike Price
Q3 2016	45	$	5.27
Q4 2016	46	$	5.27
Total 2016	91	$	5.27
Total 2017 – 2022	114	$	10.92



Natural Gas Basis Protection Swaps

	Volume (bcf)	Avg. NYMEX plus/(minus)
Q3 2016	12	$	(0.66	)
Q4 2016	10	$	(0.26	)
Total 2016	22	$	(0.49	)
Total 2017 - 2022	27	$	(0.34	)

The company’s natural gas liquids hedging positions as of August 1, 2016 were as follows:



Open Ethane Swaps

	Volume (mmgal)	Avg. NYMEX Price of Open Swaps
Q3 2016	58	$	0.17
Q4 2016	20	$	0.17
Total 2016	78	$	0.17



Open Propane Swaps

	Volume (mmgal)	Avg. NYMEX Price of Open Swaps
Q3 2016	50	$	0.46
Q4 2016	17	$	0.46
Total 2016	67	$	0.46