CHK
$3.58
Chesapeake Energy
($.15)
(4.02%)
Earnings Details
3rd Quarter September 2018
Tuesday, October 30, 2018 7:01:00 AM
Tweet Share Watch
Summary

Chesapeake Energy Beats

Chesapeake Energy (CHK) reported 3rd Quarter September 2018 earnings of $0.19 per share on revenue of $2.4 billion. The consensus earnings estimate was $0.16 per share on revenue of $1.2 billion. The Earnings Whisper number was $0.18 per share. Revenue grew 24.4% on a year-over-year basis.

Chesapeake Energy Corp is a natural gas and oil exploration and production company. It explores, develops and acquires properties for the production of natural gas and crude oil from underground reservoirs and also provides marketing & midstream services.

Results
Reported Earnings
$0.19
Earnings Whisper
$0.18
Consensus Estimate
$0.16
Reported Revenue
$2.42 Bil
Revenue Estimate
$1.16 Bil
Growth
Earnings Growth
Revenue Growth
Power Rating
Grade
Earnings Release

Chesapeake Energy Corporation Reports 2018 Third Quarter Financial And Operational Results And Time Change For Earnings Call

OKLAHOMA CITY, Oct. 30, 2018 /PRNewswire/ -- Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operational results for the 2018 third quarter. Highlights include:

  • 2018 third quarter net income available to common stockholders of $60 million, or $0.07 per diluted share; 2018 third quarter adjusted net income attributable to Chesapeake of $174 million, or $0.19 per diluted share
  • 2018 third quarter cash flow from operating activities of $504 million, up 52 percent from 2017 third quarter levels
  • Average 2018 third quarter production of approximately 537,000 barrels of oil equivalent (boe) per day, up 5 percent compared to 2017 third quarter, adjusted for asset sales
  • Average 2018 third quarter oil production of approximately 89,000 barrels (bbls) of oil per day, up 13 percent compared to 2017 third quarter, adjusted for asset sales, primarily driven by higher volume growth from the Powder River Basin (PRB)

(PRNewsfoto/Chesapeake Energy Corporation)

Doug Lawler, Chesapeake's President and Chief Executive Officer, commented, "Chesapeake continues to make significant progress on our strategic priorities, as demonstrated by our improved cash flow from operations, which was more than 50 percent higher than the 2017 third quarter due to higher average realized commodity prices and 13 percent growth in our adjusted oil production. We plan to focus the vast majority of our projected 2019 activity on our high-margin, higher-return oil opportunities in the PRB and Eagle Ford Shale, while decreasing capital and activity directed toward our natural gas portfolio, which will generate additional free cash flow. Our capital expenditures for 2018 remain on track, as we execute on our priorities of reducing leverage, increasing margins and reaching sustainable positive cash flow, and we expect continued progress in 2019."

2018 Third Quarter Results

For the 2018 third quarter, Chesapeake reported net income of $85 million and net income available to common stockholders of $60 million, or $0.07 per diluted share.  The company's EBITDA for the 2018 third quarter was $504 million. Adjusting for items that are typically excluded by securities analysts, the 2018 third quarter adjusted net income attributable to Chesapeake was $174 million, or $0.19 per diluted share, while the company's adjusted EBITDA was $594 million. Reconciliations of financial measures calculated in accordance with GAAP to non-GAAP measures are provided on pages 13 - 18 of this release.

Production expenses during the 2018 third quarter were $2.68 per boe, compared to $3.03 per boe in the 2017 third quarter. The decrease was primarily a result of certain 2018 and 2017 divestitures, in addition to lower workover activity in the Eagle Ford Shale. General and administrative expenses (including stock-based compensation) during the 2018 third quarter were $1.34 per boe, compared to $1.08 per boe in the 2017 third quarter. The increase was primarily due to less overhead allocated to production expenses, marketing expenses and capitalized general and administrative costs, as well as less overhead billed to working interest owners, due to certain divestitures in 2017 and 2018. The company's gathering, processing and transportation expenses decreased to $7.36 per boe from $7.40 per boe during the 2017 third quarter primarily as a result of certain 2018 and 2017 divestitures, reduced fees due to restructured midstream contracts and lower volume commitments.

Capital Spending Overview

Chesapeake incurred total capital expenditures, including capitalized interest of $42 million, of approximately $619 million during the 2018 third quarter, compared to approximately $692 million in the 2017 third quarter. A summary is provided in the table below.



Three Months Ended
September 30,


2018


2017

Operated activity comparison




Average rig count

19


17

Gross wells spud

84


86

Gross wells completed

81


120

Gross wells connected

75


122





Type of cost ($ in millions)




Drilling and completion capital expenditures

$

549


$

626

Exploration costs, leasehold and additions to other PP&E

28


17

Subtotal capital expenditures

$

577


$

643

Capitalized interest

42


49

Total capital expenditures

$

619


$

692

Balance Sheet and Liquidity

As of September 30, 2018, Chesapeake's principal amount of debt outstanding was approximately $9.862 billion, compared to $9.981 billion as of December 31, 2017. Also as of September 30, 2018, the company had $645 million of outstanding borrowings and $182 million for various letters of credit under its senior secured revolving credit facility resulting in approximately $2.2 billion of available liquidity under the facility.

Chesapeake continues to focus on reducing future interest expense charges, eliminating complexity and simplifying its balance sheet. On September 12, 2018, the company amended and restated its senior secured revolving credit facility with an initial borrowing base of $3.0 billion maturing in September 2023. The collateral securing the initial borrowing base does not include any properties sold in the company's $2.0 billion Utica Shale transaction, which closed in October 2018, therefore the borrowing base was not affected.

On September 27, 2018, the company issued $1.25 billion of senior notes, consisting of $850 million of 7.00% senior notes due 2024 and $400 million of 7.50% senior notes due 2026. Chesapeake used the net proceeds from the offering, together with borrowings under its revolving credit facility, to repay its secured term loan due 2021 which carried a floating interest rate equating to approximately 9.60%, in its entirety. The impact of this refinancing is projected to result in cash interest expense savings of approximately $30 million in 2019.

On October 29, 2018, the company delivered a notice of redemption to the trustee for its 8.00% Senior Secured Second Lien Notes due 2022 to call for redemption approximately $1.416 billion aggregate principal amount of the outstanding notes, representing 100% of the aggregate principal amount of the outstanding notes. The settlement of the redemption is expected to occur approximately 30 days from the notice delivery date and be funded with proceeds from the sale of the company's Utica Shale assets in Ohio.

Operations Update

Chesapeake's average daily production for the 2018 third quarter was approximately 537,000 boe compared to approximately 542,000 boe in the 2017 third quarter. The following tables show average daily production and average daily sales prices received by the company's operating divisions for the 2018 and 2017 third quarters, respectively.



Three Months Ended September 30, 2018



Oil


Natural Gas


NGL


Total



mbbl

per day


$/bbl


mmcf

per day


$/mcf


mbbl

per day


$/bbl


mboe

per day


%


$/boe

Marcellus






812



2.46







135



25



14.74


Haynesville






769



2.74







128



24



16.44


Eagle Ford


58



74.40



122



3.26



22



28.95



100



19



53.43


Utica


10



67.09



488



2.92



28



29.39



119



22



24.33


Mid-Continent


9



69.41



66



2.50



4



29.40



25



5



37.68


Powder River Basin


12



69.23



73



2.50



5



27.89



29



5



39.79


Retained assets(a)


89



72.39



2,330



2.69



59



29.10



536



100



26.92


Divested assets






2



2.02







1





19.17


Total


89



72.39



2,332



2.69



59



29.09



537



100

%


26.92







Three Months Ended September 30, 2017



Oil


Natural Gas


NGL


Total



mbbl

per day


$/bbl


mmcf

per day


$/mcf


mbbl

per day


$/bbl


mboe

per day


%


$/boe

Marcellus






748



1.96







125



23



11.76


Haynesville






804



2.77







134



25



16.63


Eagle Ford


52



49.08



136



3.25



18



23.07



92



17



36.91


Utica


12



44.18



475



2.76



28



20.30



120



22



20.21


Mid-Continent


10



46.98



69



2.54



6



22.18



27



5



28.03


Powder River Basin


5



47.12



35



2.91



3



26.77



14



2



31.01


Retained assets(a)


79



47.96



2,267



2.52



55



21.70



512



94



20.94


Divested assets


7



47.71



115



2.47



4



23.63



30



6



23.25


Total


86



47.94



2,382



2.52



59



21.83



542



100

%


21.06



(a)   Includes assets retained as of September 30, 2018.

Momentum is building in the PRB, where additional spacing and step-out tests further validate the exceptional rock quality, productivity and repeatable performance of the Turner formation. Daily net production from the basin continues to climb as demonstrated by the 107 percent increase compared to the average 2017 third quarter daily rate and 32 percent sequential growth compared to the 2018 second quarter. Chesapeake expects net production from the area will reach approximately 38,000 boe per day as an exit rate in 2018, and currently projects total net annual production from the PRB to more than double in 2019 compared to 2018.

In July 2018, Chesapeake moved to five rigs in the PRB, all of which are currently drilling the Turner formation. The company placed 13 wells on production during the 2018 third quarter, eight of which were Turner wells, bringing the total number of Turner wells on production to 24. Included was the company's best well drilled to date in the Turner with the Wyoming 36-34-69 B TR 1H well reaching a peak 24-hour average rate of 3,133 boe per day (47 percent oil) from a 10,246-foot lateral. In the 2018 third quarter, Chesapeake also drilled and completed three successful step-out Turner wells located along the western periphery of its acreage position. The wells yielded peak 24-hour production rates ranging from 1,480 to 2,725 boe per day with an average oil cut of 82 percent. With these well results, Chesapeake has delineated an area covering more than 50 square miles, or approximately 60 percent of its prospective Turner acreage, strengthening its confidence in future development plans.

The company continues to experiment with tighter spacing tests and is currently drilling its second set of wells spaced at approximately 1,980 feet. In April 2018, Chesapeake drilled six Turner wells spaced at approximately 1,980 to 2,300 feet apart and, with more than 190 days on production for each well, the company has seen no degradation from the tighter-spaced Turner wells compared to wells spaced at approximately 2,680 feet. The company expects to drill additional spacing tests in 2019, as well as move to development pad drilling in the more oil-prone (lower gas-to-oil ratio) portion of the field.

Chesapeake expects to place an additional 15 wells on production in the 2018 fourth quarter and is currently projecting an additional 65 to 70 Turner wells to be placed on production in 2019. The company is exploring the potential of adding a sixth rig in 2019, which would likely begin to focus on the Parkman and Niobrara formations.

To support the company's anticipated oil production growth, Chesapeake has recently finalized an agreement, subject to a right of first refusal, to lower its gathering and transporting costs by switching from trucking to pipeline transportation. The agreement will provide for the gathering and transportation of a portion of the company's crude oil volumes via pipeline from its development area to Guernsey, Wyoming beginning in the 2019 second quarter. The company's fixed-fee rate under this agreement is approximately one-third the cost the market is presently paying to gather and transport oil volumes to Guernsey by trucking. Chesapeake is evaluating long-haul transportation options to take volumes to Cushing, Oklahoma, to increase market access as production grows.

The Eagle Ford Shale in Texas continues to deliver steady, high-margin oil volumes that receive premium Gulf Coast pricing. While the region is typically unaffected by major weather events, production from the area was affected by abnormal flooding resulting in a decline in average net oil volumes sold of approximately 1,300 bbls of oil per day for the months of September and October 2018. The company is currently utilizing four rigs in the Eagle Ford, placed 29 wells on production during the 2018 third quarter and expects to place 53 wells on production during the 2018 fourth quarter. Chesapeake plans to add a fifth rig in 2019, as it continues to delineate additional opportunities in the Upper Eagle Ford and the Austin Chalk formations.

Chesapeake's position in the Marcellus Shale in Pennsylvania continues to create significant free cash flow driven by higher realized in-basin gas prices in the 2018 third quarter compared to a year ago, enhanced completions and longer laterals. Chesapeake is currently utilizing two rigs in the Marcellus, placed seven wells on production during the 2018 third quarter, and expects to place 25 wells on production during the 2018 fourth quarter.

In the 2018 third quarter, Chesapeake entered into a long-term supply agreement with a liquefied natural gas (LNG) provider for a portion of the company's in-basin net Marcellus gas production. Chesapeake has agreed to supply approximately 260 to 365 million British thermal units per day of net Marcellus gas production to the LNG provider for a 15-year term.

In the Haynesville Shale in Louisiana, Chesapeake moved an additional rig into the area in July and is currently utilizing four rigs, one of which is drilling the company's second well with a proposed lateral length of approximately 15,000 feet. Chesapeake drilled its first 15,000-foot well, the GEPH 30&19&18-16-15 1HC, in December 2017, which was placed on production in May, 2018. After approximately 170 days, the well is producing approximately 24.9 million cubic feet of natural gas (mmcf) per day and has produced a cumulative of 5.8 billion cubic feet of natural gas (bcf). Given higher-margin oil drilling opportunities in Chesapeake's portfolio, the company expects to decrease its activity in the area and move to operating one to two rigs in 2019. The company placed four wells on production in the Haynesville Shale during the 2018 third quarter, and expects to place seven wells on production during the 2018 fourth quarter.

In July 2018, Chesapeake announced that it entered into an agreement to sell its interests in the Utica Shale operating area located in Ohio for approximately $2.0 billion, subject to certain customary closing conditions including the receipt of third-party consents. This transaction closed in October 2018. Chesapeake is currently operating two rigs in the area and placed 11 Utica wells on production during the 2018 third quarter.


Key Financial and Operational Results


The table below summarizes Chesapeake's key financial and operational results during the 2018 third quarter as compared to results in prior periods.



Three Months Ended
September 30,


2018


2017

Barrels of oil equivalent production (in mboe)

49,413



49,831


Barrels of oil equivalent production (mboe/d)

537



542


Oil production (in mbbl/d)

89



86


Average realized oil price ($/bbl)(a)

58.77



52.33


Natural gas production (in mmcf/d)

2,332



2,382


Average realized natural gas price ($/mcf)(a)

2.69



2.52


NGL production (in mbbl/d)

59



59


Average realized NGL price ($/bbl)(a)

27.37



21.26


Production expenses ($/boe)

2.68



3.03


Gathering, processing and transportation expenses ($/boe)

7.36



7.40


Oil - ($/bbl)

3.83



4.33


Natural Gas - ($/mcf)

1.33



1.34


NGL - ($/bbl)

8.59



7.40


Production taxes ($/boe)

0.69



0.43


General and administrative expenses ($/boe)(b)

1.22



0.91


General and administrative expenses (stock-based compensation) (non-cash) ($/boe)

0.12



0.17


DD&A of oil and natural gas properties ($/boe)

5.54



4.57


DD&A of other assets ($/boe)

0.35



0.41


Interest expense ($/boe)

2.56



2.26


Marketing gross margin ($ in millions)

(19)



(14)


Net cash provided by operating activities ($ in millions)

504



331


Net cash provided by operating activities ($/boe)

10.20



6.62


Operating cash flow ($ in millions)(c)

482



337


Operating cash flow ($/boe)

9.75



6.74


Net income (loss) ($ in millions)

85



(17)


Net income (loss) available to common stockholders ($ in millions)

60



(41)


Net income (loss) per share available to common stockholders – diluted ($)

0.07



(0.05)


Adjusted EBITDA ($ in millions)(d)

594



468


Adjusted EBITDA ($/boe)

12.01



9.36


Adjusted net income attributable to Chesapeake ($ in millions)(e)

174



106


Adjusted net income attributable to Chesapeake per share - diluted ($ in millions)(f)

0.19



0.12




(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 Condensed 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 of cash provided by operating activities to operating cash flow on page 16.



(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 18. This is a non-GAAP measure. See reconciliation of net income (loss) to EBITDA on page 16 and reconciliation of EBITDA to adjusted EBITDA on page 18.



(e)

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



(f)

Our presentation of diluted adjusted net income attributable to Chesapeake per share excludes 208 million and 206 million shares for the three months ended September 30, 2018 and 2017, respectively, considered antidilutive when calculating diluted earnings per share.



2018 Third Quarter Financial and Operational Results Conference Call Update

The conference call to discuss this release has been re-scheduled on Tuesday, October 30, 2018 at 9:00 am EDT. The telephone number to access the conference call is 877-871-3172 or 412-902-6603. The passcode for the call is 0118883. The conference call will be webcast and can be found at www.chk.com in the "Investors" section of the company's website.

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
(405) 935-8870
ir@chk.com

Gordon Pennoyer
(405) 935-8878
media@chk.com



CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

($ in millions except per share data)

(unaudited)



Three Months Ended
September 30,


Nine Months Ended
September 30,



2018


2017


2018


2017

REVENUES:









Oil, natural gas and NGL(a)


$

1,199



$

979



$

3,424



$

3,727


Marketing


1,219



964



3,738



3,250


Total Revenues


2,418



1,943



7,162



6,977


OPERATING EXPENSES:









Oil, natural gas and NGL production


132



151



417



426


Oil, natural gas and NGL gathering, processing and transportation


364



369



1,060



1,081


Production taxes


34



21



91



64


Marketing


1,238



978



3,798



3,333


General and administrative


66



54



229



189


Restructuring and other termination costs






38




Provision for legal contingencies, net


8



20



17



35


Oil, natural gas and NGL depreciation, depletion and amortization


274



228



813



627


Depreciation and amortization of other assets


17



20



54



62


Impairments


5



3



51



3


Other operating (income) expense




6



(1)



423


Net (gains) losses on sales of fixed assets




(1)



7




Total Operating Expenses


2,138



1,849



6,574



6,243


INCOME FROM OPERATIONS


280



94



588



734


OTHER INCOME (EXPENSE):









Interest expense


(127)



(114)



(367)



(302)


Gains on investments






139




Gains (losses) on purchases or exchanges of debt


(68)



(1)



(68)



183


Other income


1



4



63



6


Total Other Expense


(194)



(111)



(233)



(113)


INCOME (LOSS) BEFORE INCOME TAXES


86



(17)



355



621


Income tax expense (benefit)


1





(8)



2


NET INCOME (LOSS)


85



(17)



363



619


Net income attributable to noncontrolling interests


(1)



(1)



(3)



(3)


NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE


84



(18)



360



616


Preferred stock dividends


(23)



(23)



(69)



(62)


Loss on exchange of preferred stock








(41)


Earnings allocated to participating securities


(1)





(3)



(7)


NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS


$

60



$

(41)



$

288



$

506


EARNINGS (LOSS) PER COMMON SHARE:









Basic


$

0.07



$

(0.05)



$

0.32



$

0.56


Diluted


$

0.07



$

(0.05)



$

0.32



$

0.56


WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):









Basic


910



909



909



908


Diluted


911



909



909



908




(a)

See page 10 for a reconciliation of oil, natural gas and NGL revenue before and after the effect of financial derivatives.







CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

($ in millions)

(unaudited)



September 30,
2018


December 31,
2017






Cash and cash equivalents


$

4



$

5


Other current assets


1,231



1,520


Total Current Assets


1,235



1,525







Property and equipment, net


11,177



10,680


Other long-term assets


247



220


Total Assets


$

12,659



$

12,425







Current liabilities


$

2,976



$

2,356


Long-term debt, net


9,380



9,921


Other long-term liabilities


342



520


Total Liabilities


12,698



12,797







Preferred stock


1,671



1,671


Noncontrolling interests


123



124


Common stock and other stockholders' equity (deficit)


(1,833)



(2,167)


Total Equity (Deficit)


(39)



(372)







Total Liabilities and Equity


$

12,659



$

12,425







Common shares outstanding (in millions)


914



909


Principal amount of debt outstanding


$

9,862



$

9,981





CHESAPEAKE ENERGY CORPORATION

SUPPLEMENTAL DATA – OIL, NATURAL GAS AND NGL PRODUCTION, SALES AND INTEREST EXPENSE

(unaudited)


Three Months Ended
September 30,


Nine Months Ended
September 30,


2018


2017


2018


2017

Net Production:








Oil (mmbbl)

8



8



25



23


Natural gas (bcf)

215



219



647



639


NGL (mmbbl)

5



5



15



15


Oil equivalent (mmboe)

50



50



148



145


Average daily production (mboe)

537



542



540



532


Oil, Natural Gas and NGL Sales ($ in millions):








Oil sales

$

594



$

379



$

1,698



$

1,140


Natural gas sales

578



553



1,822



1,807


NGL sales

159



117



404



328


Total oil, natural gas and NGL sales

$

1,331



$

1,049



$

3,924



$

3,275










Financial Derivatives:








Oil derivatives – realized gains (losses)(a)

(112)



35



$

(273)



79


Natural gas derivatives – realized gains (losses)(a)

(1)



(1)



83



(53)


NGL derivatives – realized gains (losses)(a)

(10)



(3)



(14)



(1)


Total realized gains (losses) on financial derivatives

$

(123)



$

31



$

(204)



$

25










Oil derivatives – unrealized gains (losses)(a)

12



(96)



(115)



45


Natural gas derivatives – unrealized gains (losses)(a)

(17)



(3)



(168)



384


NGL derivatives – unrealized gains (losses)(a)

(4)



(2)



(13)



(2)


Total unrealized gains (losses) on financial derivatives

$

(9)



$

(101)



$

(296)



$

427










Total financial derivatives

$

(132)



$

(70)



$

(500)



$

452










Total oil, natural gas and NGL sales

$

1,199



$

979



$

3,424



$

3,727


Average Sales Price (excluding gains (losses) on derivatives):








Oil ($ per bbl)

$

72.39



$

47.94



$

68.63



$

48.53


Natural gas ($ per mcf)

$

2.69



$

2.52



$

2.82



$

2.83


NGL ($ per bbl)

$

29.09



$

21.83



$

26.87



$

21.28


Oil equivalent ($ per boe)

$

26.92



$

21.06



$

26.59



$

22.53


Average Sales Price (excluding unrealized gains (losses) on derivatives):








Oil ($ per bbl)

$

58.77



$

52.33



$

57.61



$

51.90


Natural gas ($ per mcf)

$

2.69



$

2.52



$

2.94



$

2.75


NGL ($ per bbl)

$

27.37



$

21.26



$

25.96



$

21.21


Oil equivalent ($ per boe)

$

24.44



$

21.67



$

25.21



$

22.70


Interest Expense ($ in millions):








Interest expense(b)

$

127



$

115



$

367



$

302


Interest rate derivatives – realized gains(c)

(1)



(1)



(2)



(3)


Interest rate derivatives – unrealized losses(c)

1





2



3


Total Interest Expense

$

127



$

114



$

367



$

302




(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 amounts reclassified to realized (gains) losses during the period.







CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED CASH FLOW DATA

($ in millions)

(unaudited)


Three Months Ended
September 30,


Nine Months Ended
September 30,


2018


2017


2018


2017









Beginning cash and cash equivalents

$

3



$

13



$

5



$

882










Net cash provided by operating activities

504



331



1,595



273










Cash flows from investing activities:








Drilling and completion costs(a)

(502)



(566)



(1,481)



(1,597)


Acquisitions of proved and unproved properties(b)

(53)



(64)



(244)



(226)


Proceeds from divestitures of proved and unproved properties

11



242



395



1,193


Additions to other property and equipment

(6)



(5)



(11)



(12)


Proceeds from sales of other property and equipment

1



14



75



40


Proceeds from sales of investments





74




Net cash used in investing activities

(549)



(379)



(1,192)



(602)










Net cash provided by (used in) financing activities

46



40



(404)



(548)


Change in cash and cash equivalents

1



(8)



(1)



(877)


Ending cash and cash equivalents

$

4



$

5



$

4



$

5




(a)

Includes capitalized interest of $2 million and $2 million for the three months ended September 30, 2018 and 2017, respectively, and includes capitalized interest of $7 million and $7 million for the nine months ended September 30, 2018 and 2017, respectively.



(b)

Includes capitalized interest of $40 million and $47 million for the three months ended September 30, 2018 and 2017, respectively, and includes capitalized interest of $121 million and $139 million for the nine months ended September 30, 2018 and 2017, respectively.







CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS

($ in millions except per share data)

(unaudited)



Three Months Ended September 30,



2018


2017



$


$/Share(a)(b)


$


$/Share(a)(b)

Net income (loss) available to common stockholders (GAAP)


$

60



$

0.07



$

(41)



$

(0.05)


Effect of dilutive securities









Diluted earnings (losses) per common stockholder (GAAP)


$

60



$

0.07



$

(41)



$

(0.05)











Adjustments:









Unrealized losses on oil, natural gas and NGL derivatives


9



0.01



101



0.12


Provision for legal contingencies, net


8



0.01



20



0.02


Other operating expense






6



0.01


Impairments


5





3




Net gains on sales of fixed assets






(1)




Losses on purchases or exchanges of debt


68



0.07



1




Income tax expense (benefit)(c)









Other






(6)



(0.01)


Adjusted net income available to common stockholders(a) (Non-GAAP)


150



0.16



83



0.09











Preferred stock dividends


23



0.03



23



0.03


Earnings allocated to participating securities


1








Total adjusted net income attributable to Chesapeake(a) (b) (Non-GAAP)


$

174



$

0.19



$

106



$

0.12





(a)

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.




(b)

Our presentation of diluted net income (loss) available to common stockholders and diluted adjusted net income (loss) per share excludes 208 million and 206 million shares considered antidilutive for the three months ended September 30, 2018 and 2017, respectively. The number of shares used for the non-GAAP calculation was determined in a manner consistent with GAAP.




(c)

Our effective tax rate in the three months ended September 30, 2018 was 0%. 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 September 30, 2017.










CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS

($ in millions except per share data)

(unaudited)



Nine Months Ended September 30,



2018


2017



$


$/Share(a)(b)


$


$/Share(a)(b)

Net income available to common stockholders (GAAP)


$

288



$

0.32



$

506



$

0.56


Effect of dilutive securities









Diluted earnings per common stockholder (GAAP)


$

288



$

0.32



$

506



$

0.56











Adjustments:









Unrealized (gains) losses on oil, natural gas and NGL derivatives


296



0.32



(427)



(0.47)


Restructuring and other termination costs


38



0.04






Provision for legal contingencies, net


17



0.02



35



0.04


Other operating expense (income)


(1)





423



0.47


Impairments


51



0.06



3




Net losses on sales of fixed assets


7



0.01






Gains on investments


(139)



(0.15)






(Gains) losses on purchases or exchanges of debt


68



0.07



(183)



(0.21)


Loss on exchange of preferred stock






41



0.05


Income tax expense (benefit)(c)









Other (d)


(59)



(0.06)



(3)




Adjusted net income available to common stockholders(a) (Non-GAAP)


566



0.63



395



0.44











Preferred stock dividends


69



0.07



62



0.07


Earnings allocated to participating securities


3





7




Total adjusted net income attributable to Chesapeake(a) (b) (Non-GAAP)


$

638



$

0.70



$

464



$

0.51





(a)

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.




(b)

Our presentation of diluted net income (loss) available to common stockholders and diluted adjusted net income (loss) per share excludes 207 million and 207 million shares considered antidilutive for the nine months ended September 30, 2018 and 2017, respectively. The number of shares used for the non-GAAP calculation was determined in a manner consistent with GAAP.




(c)

Our effective tax rate in the nine months ended September 30, 2018 was 0%. Due to our valuation allowance position, no income tax effect from the adjustments has been included in determining adjusted net income for the nine months ended September 30, 2017.




(d)

Other for the nine months ended September 30, 2018 includes a $61 million gain related to an extinguishment of the CHK Utica overriding royalty interest conveyance obligation.










CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF OPERATING CASH FLOW AND EBITDA

($ in millions)

(unaudited)


Three Months Ended

September 30,


Nine Months Ended
September 30,


2018


2017


2018


2017









CASH PROVIDED BY OPERATING ACTIVITIES (GAAP)

$

504



$

331



$

1,595



$

273


Changes in components of working capital and other assets and liabilities

(22)



6



(116)



366


OPERATING CASH FLOW (Non-GAAP)(a)

$

482



$

337



$

1,479



$

639




Three Months Ended
September 30,


Nine Months Ended
September 30,


2018


2017


2018


2017









NET INCOME (LOSS) (GAAP)

$

85



$

(17)



$

363



$

619


Interest expense

127



114



367



302


Income tax expense (benefit)

1





(8)



2


Depreciation and amortization of other assets

17



20



54



62


Oil, natural gas and NGL depreciation, depletion and amortization

274



228



813



627


EBITDA (Non-GAAP)(b)

$

504



$

345



$

1,589



$

1,612




Three Months Ended
September 30,


Nine Months Ended
September 30,


2018


2017


2018


2017









CASH PROVIDED BY OPERATING ACTIVITIES (GAAP)

$

504



$

331



$

1,595



$

273


Changes in assets and liabilities

(22)



6



(116)



366


Interest expense

127



114



367



302


Gains (losses) on oil, natural gas and NGL derivatives, net

(132)



(70)



(500)



452


Cash (receipts) payments on derivative settlements, net

107



(20)



162



46


Stock-based compensation

(7)



(11)



(25)



(38)


Impairments

(5)



(3)



(51)



(3)


Gains (losses) on sales of fixed assets



1



(7)




Gains on investments





139




Gains (losses) on purchases or exchanges of debt

(68)





(68)



185


Other items (c)



(3)



93



29


EBITDA (Non-GAAP)(b)

$

504



$

345



$

1,589



$

1,612




(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 nine months ended September 30, 2018 is mainly due to an increase in realized prices and volumes.



(b)

EBITDA represents net income before interest expense, income tax expense, 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.



(c)

Other items for the nine months ended September 30, 2018 includes a $61 million gain related to an extinguishment of the CHK Utica overriding royalty interest conveyance obligation.







CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED EBITDA

($ in millions)

(unaudited)


Three Months Ended
September 30,


Nine Months Ended
September 30,


2018


2017


2018


2017









EBITDA (Non-GAAP) (a)

$

504



$

345



$

1,589



$

1,612










Adjustments:








Unrealized (gains) losses on oil, natural gas and NGL derivatives

9



101



296



(427)


Restructuring and other termination costs





38




Provision for legal contingencies, net

8



20



17



35


Other operating expense (income)



6



(1)



423


Impairments

5



3



51



3


(Gains) losses on sales of fixed assets



(1)



7




Gains on investments





(139)




(Gains) losses on purchases or exchanges of debt

68



1



68



(183)


Net income attributable to noncontrolling interests

(1)



(1)



(3)



(3)


Other (b)

1



(6)



(60)



(6)










Adjusted EBITDA (Non-GAAP)(a)

$

594



$

468



$

1,863



$

1,454




(a)

EBITDA and Adjusted EBITDA are not measures of financial performance under GAAP, and should not be considered as an alternative to, or more meaningful than, net income (loss) or cash flow provided by (used in) operations prepared in accordance with GAAP. 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.





Because adjusted EBITDA excludes some, but not all, items that affect net income, our calculations of adjusted EBITDA may not be comparable to similarly titled measures of other companies.



(b)

Other for the nine months ended September 30, 2018 includes a $61 million gain related to an extinguishment of the CHK Utica overriding royalty interest conveyance obligation.







CHESAPEAKE ENERGY CORPORATION

MANAGEMENT'S OUTLOOK AS OF OCTOBER 30, 2018


Chesapeake periodically provides guidance on certain factors that affect the company's future financial performance. New information or changes from the company's August 1, 2018 outlook are italicized bold below.



Year Ending

12/31/2018



Production Growth adjusted for asset sales(a)

1% to 5%

Absolute Production


Liquids - mmbbls

48.5 - 52.5

Oil - mmbbls

31.5 - 33.5

NGL - mmbbls

17.0 - 19.0

Natural gas - bcf

790 - 830

Total absolute production - mmboe

180 - 191

Absolute daily rate - mboe

494 - 524

Estimated Realized Hedging Effects(b) (based on 10/25/18 strip prices):


Oil - $/bbl

($11.85)

Natural gas - $/mcf

$0.07

NGL - $/bbl

$(0.95)

Estimated Basis to NYMEX Prices:


Oil - $/bbl

$2.05 - $2.25

Natural gas - $/mcf

($0.10) - ($0.15)

NGL - $/bbl

($6.20) - ($6.60)

Operating Costs per Boe of Projected Production:


Production expense

$2.85 - $2.95

Gathering, processing and transportation expenses

$6.85 - $7.35

Oil - $/bbl

$3.60 - $3.80

Natural Gas - $/mcf

$1.25 - $1.35

NGL - $/bbl

$8.25 - $8.65

Production taxes

$0.60 - $0.70

General and administrative(c)

$1.25 - $1.35

Stock-based compensation (noncash)

$0.10 - $0.20

DD&A of natural gas and liquids assets

$5.25 - $6.25

Depreciation of other assets

$0.35 - $0.45

Interest expense

$2.40 - $2.60

Marketing net margin(d)

($55) - ($35)

Book Tax Rate

0%

Adjusted EBITDA, based on 10/25/18 strip prices ($ in millions)(e)

$2,300 - $2,500

Capital Expenditures ($ in millions)(f)

$2,000 - $2,300

Capitalized Interest ($ in millions)

$175

Total Capital Expenditures ($ in millions)

$2,175 - $2,475



(a)

Based on 2017 production of 407 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 non-cash amortization of approximately $19 million.



(e)

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.



(f)

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 October 26, 2018, including October 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. The company had downside oil price protection through swaps at an average price of $54.09 per bbl, and under three-way collar arrangements based on an average bought put NYMEX price of $47.00 per bbl and exposure below an average sold put NYMEX price of $39.15 per bbl. The company had downside natural gas price protection through swaps and two-way collars at an average price of $3.00 per mcf. Chesapeake also had downside ethane, propane, butane, isobutane and natural gasoline price protection through swaps at an average price of $0.29, $0.79, $0.88, $0.92 and $1.42 per gallon (as well as a portion of butane at 70.5 percent 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 $59.44 per bbl. The company also initiated downside protection on a portion of its 2019 natural gas production through open swaps and two-way collars at an average price of $2.82 per mcf and under three-way collar arrangements based on an average bought put NYMEX price of $2.80 per mcf and exposure below an average sold put NYMEX price of $2.50 per mcf.

The company's crude oil hedging positions were as follows:

Crude Oil Swaps

Losses from Closed Crude Oil Trades


Swaps

(mmbbls)


Avg. NYMEX

Price of

Swaps


Losses from
Closed Trades

($ in millions)







Q4 2018

7


$

54.09



(1)


Total 2018

7


$

54.09



$

(1)








Q1 2019

4


$

59.06



(1)


Q2 2019

4


$

59.06



(1)


Q3 2019

3


$

59.96



(1)


Q4 2019

3


$

59.96



(1)


Total 2019

14


$

59.44



$

(4)








Total 2020-2022

3


$

69.47



$

(4)




Crude Oil Three-Way Collars



Collars
(mmbbls)


Avg. NYMEX
Sold Put Price


Avg. NYMEX
Bought Put Price


Avg. NYMEX
Sold Call Price










Q4 2018


1


$

39.15



$

47.00



$

55.00


Total 2018


1


$

39.15



$

47.00



$

55.00




Oil Basis Protection Swaps


Volume

(mmbbls)


Avg. NYMEX

plus/(minus)





Q4 2018

4


$

3.52


Total 2018

4


$

3.52






Q1 2019

2


$

5.93


Q2 2019

3


$

5.93


Q3 2019

1


$

6.20


Q4 2019

1


$

6.20


Total 2019

7


$

6.01


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

Natural Gas Swaps

Losses from Closed Natural Gas Trades


Swaps

(bcf)


Avg. NYMEX

Price of

Swaps


Losses

from Closed
Trades

($ in millions)







Q4 2018

120


$

3.00



(5)


Total 2018

120


$

3.00



$

(5)








Q1 2019

81


$

2.83



(6)


Q2 2019

81


$

2.83



(4)


Q3 2019

82


$

2.83



(4)


Q4 2019

81


$

2.83



(5)


Total 2019

325


$

2.83



$

(19)








Total 2020 - 2022


$



$

(29)




Natural Gas Two-Way Collars


Collars
(bcf)


Avg. NYMEX
Bought Put Price


Avg. NYMEX
Sold Call Price







Q4 2018

12


$

3.00



$

3.25


Total 2018

12


$

3.00



$

3.25








Q1 2019

27


$

2.75



$

3.13


Q2 2019

9


$

2.75



$

2.91


Q3 2019

9


$

2.75



$

2.91


Q4 2019

9


$

2.75



$

2.91


Total 2019

54


$

2.75



$

3.02




Natural Gas Three-Way Collars



Collars
(bcf)


Avg. NYMEX
Sold Put Price


Avg. NYMEX
Bought Put Price


Avg. NYMEX
Sold Call Price










Q1 2019


22


$

2.50



$

2.80



$

3.10


Q2 2019


22


$

2.50



$

2.80



$

3.10


Q3 2019


22


$

2.50



$

2.80



$

3.10


Q4 2019


22


$

2.50



$

2.80



$

3.10


Total 2019


88


$

2.50



$

2.80



$

3.10




Natural Gas Net Written Call Options


Call Options

(bcf)


Avg. NYMEX

Strike Price





Q4 2018

17


$

6.27


Total 2018

17


$

6.27






Q1 2019

5


$

12.00


Q2 2019

5


$

12.00


Q3 2019

6


$

12.00


Q4 2019

6


$

12.00


Total 2019

22


$

12.00






Total 2020

22


$

12.00




Natural Gas Basis Protection Swaps


Volume

(bcf)


Avg. NYMEX
plus/(minus)





Q4 2018

6


$

(0.77)


Total 2018

6


$

(0.77)






Q1 2019

7


$

1.07


Q2 2019

12


$

(0.17)


Q3 2019

12


$

(0.17)


Q4 2019

6


$

(0.39)


Total 2019

37


$

0.03


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

Ethane Swaps


Volume

(mmgal)


Avg. NYMEX
Price of Swaps





Q4 2018

23


$

0.29


Total 2018

23


$

0.29




Propane Swaps


Volume

(mmgal)


Avg. NYMEX
Price of Swaps





Q4 2018

15


$

0.79


Total 2018

15


$

0.79




Butane Swaps


Volume

(mmgal)


Avg. NYMEX
Price of Swaps





Q4 2018

1


$

0.88


Total 2018

1


$

0.88




Butane Swaps Priced as a Percentage of WTI


Volume

(mmgal)


Avg. NYMEX
as a % of WTI Swaps





Q4 2018

1


70.5%

Total 2018

1


70.5%



Iso-Butane Swaps


Volume

(mmgal)


Avg. NYMEX
Price of Swaps





Q4 2018

4


$

0.92


Total 2018

4


$

0.92




Natural Gasoline Swaps


Volume

(mmgal)


Avg. NYMEX
Price of Swaps





Q4 2018

12


$

1.42


Total 2018

12


$

1.42


 

Cision View original content to download multimedia:http://www.prnewswire.com/news-releases/chesapeake-energy-corporation-reports-2018-third-quarter-financial-and-operational-results-and-time-change-for-earnings-call-300740117.html

SOURCE Chesapeake Energy Corporation