Chesapeake Energy Corporation Reports 2019 Third Quarter Financial And Operational Results, Maintains 2019 Guidance And Announces Plans To Reduce 2020 Capital Budget

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OKLAHOMA CITY, Nov. 5, 2019 /PRNewswire/ — Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operational results for the 2019 third quarter. Highlights include:

(PRNewsfoto/Chesapeake Energy Corporation)

Maintaining 2019 Production and Capital Expenditure Guidance:

2019 fourth quarter oil production projected to increase approximately 10% over 2019 third quarter levels
Brazos Valley sets net average oil production record of approximately 40,000 barrels (bbls) of oil per day for the month of October 2019; continue to deliver capital and operating costs ahead of projected synergies
Powder River Basin (PRB) Turner well costs down approximately 10% year to date; first Niobrara well drilled and completed since 2014 produces more than 100,000 bbls of oil in first 87 days

Continuing Progress on Prudently Managing Balance Sheet and Cash Costs:

Recently re-affirmed borrowing base of Chesapeake credit facility
Exchanged $693 million of Senior Notes and $40 million of preferred shares for 319 million common shares at an average discount of approximately 25%, reducing annual interest and preferred dividend payments
Restructured gas gathering and crude oil transportation contracts in South Texas and Brazos Valley, improving future returns

Reducing 2020 Capital Expenditure Forecast by Approximately 30%, Targeting Free Cash Flow:

Anticipate flat oil production year over year, utilizing 10 to 13 rigs with projected total capital expenditures of approximately $1.3 to $1.6 billion, contingent upon commodity prices
Expect to reduce 2020 production and general and administrative (G&A) expenses by approximately 10%

Doug Lawler, Chesapeake’s President and Chief Executive Officer, commented, “We are pleased with our execution this quarter as we continue to successfully integrate and realize value from our Brazos Valley acquisition and maximize cash flow from our oil assets while reducing capital directed to our natural gas assets. We expect our oil production to grow approximately 10% in the fourth quarter, compared to the third quarter, and we remain on track to meet our 2019 total production and capital expenditure guidance. Our capital efficiency improvements, expected reduction in cash costs and anticipated capital plan position us to target free cash flow in 2020.”

2019 Third Quarter Results

For the 2019 third quarter, Chesapeake reported a net loss of $61 million and a net loss available to common stockholders of $101 million, or $0.06 per diluted share. Adjusting for items typically excluded by securities analysts, the 2019 third quarter adjusted net loss attributable to Chesapeake was $188 million, or $0.11 per share, while adjusted EBITDAX was $577 million. Reconciliations of financial measures calculated in accordance with GAAP to non-GAAP measures are provided on pages 16 – 20 of this release.

Average daily production for the 2019 third quarter was approximately 478,000 barrels of oil equivalent (boe), representing year-over-year growth of 3% adjusted for asset purchases and sales, and consisted of approximately 115,000 bbls of oil, 1.989 billion cubic feet (bcf) of natural gas and 32,000 bbls of natural gas liquids (NGL). Average daily production for the 2018 third quarter was approximately 537,000 boe and consisted of approximately 89,000 bbls of oil, 2.332 bcf of natural gas and 59,000 bbls of NGL. Oil production represented approximately 24% of the company’s 2019 third quarter aggregate production, compared to 17% in the 2018 third quarter.

Despite lower average prices for our oil, natural gas and NGL sold, Chesapeake’s operating margin remained flat in the 2019 third quarter, compared to the 2018 third quarter, due to an increase in oil production mix and a decrease in cash costs. Gathering, processing and transportation and G&A expenses decreased by $109 million, or approximately $1.39 per boe, while production expense increased $23 million, or $0.86 per boe, when compared to the same quarter in 2018.

Capital Spending Overview

Chesapeake invested total capital expenditures of approximately $640 million during the 2019 third quarter, including capitalized interest of $6 million, compared to approximately $551 million in the 2018 third quarter. The increase in capital expenditures in the 2019 third quarter was largely attributable to an increase in net wells spud, completed and connected. See tables below for a summary of activity and expenditures.

	Three Months Ended September 30,
	2019		2018
	Net	Gross	Net	Gross
Operated activity comparison
Average rig count	13	17	11	19
Wells spud	63	87	49	84
Wells completed	83	117	59	81
Wells connected	83	118	53	75

	Three Months Ended September 30,
	2019		2018*
Type of cost ($ in millions)
Drilling and completion capital expenditures	$	613	$	531
Leasehold and additions to other PP&E	21		16
Subtotal capital expenditures	$	634	$	547
Capitalized interest	6		4
Total capital expenditures	$	640	$	551

* Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting.

Balance Sheet and Liquidity

As of September 30, 2019, Chesapeake’s principal amount of debt outstanding inclusive of Brazos Valley debt was approximately $9.732 billion, compared to $8.168 billion as of December 31, 2018. As of September 30, 2019, the company had borrowed $1.504 billion under the $3.0 billion Chesapeake credit facility, utilized approximately $53 million for various letters of credit, and had additional borrowing capacity of approximately $1.443 billion. Under the $1.3 billion Brazos Valley credit facility, the company had borrowed $900 million and had additional borrowing capacity of approximately $400 million. The borrowing base of the Chesapeake credit facility was re-affirmed in November 2019 and the redetermination process for the Brazos Valley credit facility is scheduled for the 2019 fourth quarter.

During the 2019 third quarter, Chesapeake exchanged approximately 319 million common shares for various series of Senior Notes and preferred shares totaling a principal amount of approximately $733 million. The company expects approximately $45 million in interest savings in 2020 as a result of these transactions. The company believes these transactions, together with its planned reduction in capital expenditures in 2020 and other efficiency measures, will reduce its debt levels and improve the ratios under the covenants in the company’s revolving credit facility.

As of October 31, 2019, including October and November derivative contracts that have settled, approximately 80% of the company’s remaining 2019 forecasted oil, natural gas and NGL production revenue was hedged, including approximately 74% and 75% of its remaining 2019 forecasted oil and natural gas production at average prices of $59.34 per bbl and $2.83 per thousand cubic feet (mcf), respectively. Additionally, Chesapeake has basis protection swaps on approximately 2 million barrels (mmbbls) of its remaining projected 2019 Eagle Ford oil production at a premium to WTI of approximately $5.67 per bbl.

In 2020, Chesapeake currently has downside protection on a portion of its 2020 projected oil production at an average price of $59.28 per bbl and on a portion of its 2020 projected gas production at an average price of $2.76 per mcf.

Operations Update and Highlights

Chesapeake’s average daily production for the 2019 third quarter was approximately 478,000 boe compared to approximately 537,000 boe in the 2018 third quarter. The following tables show average daily production and average sales prices received (excluding gains/losses on derivatives) by the company’s operating areas for the 2019 and 2018 third quarters.

	Three Months Ended September 30, 2019
	Oil		Natural Gas		NGL		Total
	mbbl per day	$/bbl	mmcf per day	$/mcf	mbbl per day	$/bbl	mboe per day	%		$/boe
Marcellus	—	—	928	1.85	—	—	154	32		11.11
Haynesville	—	—	694	2.03	—	—	116	24		12.17
Eagle Ford	51	60.13	161	2.13	16	14.24	94	20		38.62
Brazos Valley	36	58.23	62	1.70	6	8.84	53	11		43.07
Powder River Basin	20	54.17	86	1.96	5	11.49	39	8		33.09
Mid-Continent	8	55.24	57	1.63	5	12.06	22	5		26.26
Retained assets^(a)	115	58.18	1,988	1.93	32	12.44	478	100		22.79
Divested assets	—	—	—	—	—	—	—	—		—
Total	115	58.18	1,989	1.93	32	12.44	478	100	%	22.79

	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		14.77
Haynesville	—	—	769	2.74	—	—	128	24		16.44
Eagle Ford	58	74.38	121	3.26	21	28.94	100	19		53.48
Powder River Basin	12	69.24	73	2.50	5	27.89	29	5		39.76
Mid-Continent	9	69.76	60	2.50	4	29.73	23	4		38.64
Retained assets^(a)	79	73.07	1,835	2.63	30	28.86	415	77		27.66
Divested assets	10	67.02	497	2.91	29	29.34	122	23		24.38
Total	89	72.39	2,332	2.69	59	29.09	537	100	%	26.92


(a)	Includes assets retained as of September 30, 2019.

Brazos Valley: Sets new production record

In Chesapeake’s Brazos Valley area in central Texas, the company is currently utilizing four rigs and placed 25 wells on production during the 2019 third quarter, 14 of which were placed on production in the last five weeks of the quarter. As a result, the company set a new net oil production record for the month of October 2019 of approximately 40,000 bbls of oil per day, exceeding the monthly production record set by the previous operator in November 2018 while utilizing five rigs. The increase was also driven by improvements to the field’s base decline through its well optimization and workover program.

As the company’s subsurface understanding evolves, the commercial black oil area of the field continues to expand, further strengthening the inventory of the future drilling program. Since February 1, 2019, the company has placed 13 wells on production which have reached peak 24-hour rates of more than 1,000 bbls of oil per day. The company anticipates placing 20 wells on production in the 2019 fourth quarter.

Chesapeake continues to improve operational efficiencies in its Brazos Valley development program, resulting in a 21% decrease in completed well costs to approximately $830 per foot, and extending its average completed lateral length per well drilled to more than 9,000 feet.

Eagle Ford Shale: Gas gathering and crude oil transportation restructuring provides improved long term field economics, production anticipated to ramp in the fourth quarter

In the company’s South Texas Eagle Ford asset, 2019 third quarter volumes were projected to represent the low for the year primarily due to timing of the company’s development plan and longer cleanup periods associated with that development. Of the 47 wells Chesapeake placed on production during the 2019 third quarter, 46 were put to sales in August and September. The company is currently running four rigs in South Texas and anticipates placing 41 wells on production in the 2019 fourth quarter.

Additionally, Chesapeake continues to optimize its midstream and downstream commitments and has recently successfully restructured its gas gathering and crude transportation commitments in the Eagle Ford. These agreements allow the company to move away from a cost-of-service mechanism to fixed-fee gathering rate structures, as well as maximize its pipeline commitments going forward.

Powder River Basin: Turner capital efficiency continues to advance and first Niobrara well drilled since 2014 delivers record results

Chesapeake continues to recognize operational efficiencies in the Turner sandstone formation which have driven costs out of its operations, including reductions in cycle times by 25% year over year and in average drilling and completion costs by approximately $800,000, or 10%, per well through the first nine months of 2019 compared to 2018 results. These efficiency enhancements have resulted in a recent four-well Turner pad being drilled and completed for approximately $6.0 million per well, with the last 25 wells turned to sales averaging approximately $7.2 million per well.

While the Turner sandstone formation has been Chesapeake’s primary focus in its PRB development program, the company remains enthusiastic about the stacked pay potential in the basin. The company recently placed on production its first Niobrara well since 2014, and in the first 87 days it has produced approximately 106,500 bbls of oil, reaching a 24-hour peak rate of greater than 1,600 bbls of oil per day. The company currently plans to drill and complete four additional Niobrara wells in 2019 and expects that more than 25% of its projected 2020 capital program will be targeting the Niobrara formation. The company is currently utilizing four rigs in the PRB, placed 26 wells on production in the 2019 third quarter and anticipates placing 17 wells on production in the 2019 fourth quarter.

Production volumes in the 2019 third quarter were less than expected, primarily driven by the impact from a group of nine wells placed on production earlier in the year in the northern edge of Chesapeake’s Turner acreage. These isolated wells encountered poorer reservoir quality, resulting in lower than expected performance compared to other company-operated wells in the rest of the field. Production volumes were also negatively impacted by unplanned outages due to electrical power issues that interrupted portions of the field’s midstream system. The company is working with local utility companies and its midstream partners to ensure reliable power to support all production, gathering and transportation systems.

Marcellus Shale: Recent well performance highlights capital efficiency gains

In the Marcellus Shale, the company continues its strategy of maintaining its operated production to capture the value from seasonal basin congestion and pricing, while achieving lower costs and capital requirements due to the strong performance of recent wells. Wider spacing averaging approximately 1,350 feet between well bores, fit-for-purpose modern completions and improved cycle times continue to yield impressive results for Chesapeake in the Marcellus Shale, with six wells recently turned to sales reaching peak 24-hour flow rates between 60 million cubic feet (mmcf) of gas per day to a record 85 mmcf per day. The company is currently utilizing two rigs in the Marcellus, placed 17 wells on production in the 2019 third quarter and anticipates placing four wells on production in the 2019 fourth quarter.

Haynesville Shale, Mid-Continent: Allocating capital to higher-return areas in 2020

In the Haynesville Shale in Louisiana, Chesapeake placed five wells on production during the 2019 third quarter. The company has released its operated rigs and completion crews in both the Haynesville Shale and Mid-Continent areas for the rest of the year.

Key Financial and Operational Results

The table below summarizes Chesapeake’s key financial and operational results during the 2019 third quarter as compared to results in the same quarter in 2018. The three months ended September 30, 2019 include Brazos Valley operations. The three months ended September 30, 2018 do not include Brazos Valley operations.

	Three Months Ended September 30,
	2019	2018*
Barrels of oil equivalent production (in mboe)	43,991	49,413
Barrels of oil equivalent production (mboe/d)	478	537
Oil production (in mbbl/d)	115	89
Average realized oil price ($/bbl)^(a)	60.66	58.77
Natural gas production (in mmcf/d)	1,989	2,332
Average realized natural gas price ($/mcf)^(a)	2.38	2.69
NGL production (in mbbl/d)	32	59
Average realized NGL price ($/bbl)^(a)	12.44	27.37
Production expenses ($/boe)	3.54	2.68
Gathering, processing and transportation expenses ($/boe)	6.12	7.36
Oil – ($/bbl)	3.53	3.83
Natural Gas – ($/mcf)	1.19	1.33
NGL – ($/bbl)	5.19	8.59
Production taxes ($/boe)	0.79	0.69
Exploration expenses ($ in millions)	17	22
General and administrative expenses ($/boe)^(b)	1.35	1.51
General and administrative expenses (stock-based compensation) (non-cash) ($/boe)	0.13	0.12
Depreciation, depletion, and amortization ($/boe)	13.04	8.20
Interest expense ($/boe)^(c)	3.99	3.32
Marketing net margin ($ in millions)^(d)	(13)	(14)
Net cash provided by operating activities ($ in millions)	329	444
Net cash provided by operating activities ($/boe)	7.48	8.99
Net loss ($ in millions)	(61)	(146)
Net loss available to common stockholders ($ in millions)	(101)	(169)
Net loss per share available to common stockholders – diluted ($)	(0.06)	(0.19)
Adjusted EBITDAX ($ in millions)^(e)	577	584
Adjusted EBITDAX ($/boe)	13.12	11.82
Adjusted net loss attributable to Chesapeake ($ in millions)^(f)	(188)	(8)
Adjusted net loss attributable to Chesapeake per share – diluted ($)^(g)	(0.11)	(0.01)


* Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting.


(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)	Includes the effects of realized (gains) losses from interest rate derivatives, excludes the effects of unrealized (gains) losses from interest rate derivatives and is shown net of amounts capitalized.

(d)	Marketing net margin is marketing gross margin of ($12) million and ($19) million for the three months ended September 30, 2019 and 2018, excluding non-cash amortization of ($1) million and $5 million, respectively, related to the buy down of a transportation agreement.

(e)	Defined as net income (loss) before interest expense, income taxes, depreciation, depletion and amortization expense, and exploration expense, as adjusted to remove the effects of certain items detailed in the Reconciliation of Net Income (Loss) to Adjusted EBITDAX. This is a non-GAAP measure.

(f)	Defined as net income (loss) attributable to Chesapeake, as adjusted to remove the effects of certain items detailed in the Reconciliation of Adjusted Net Income (Loss) Attributable to Chesapeake. This is a non-GAAP measure.

(g)	Our presentation of diluted adjusted net loss attributable to Chesapeake per share excludes 183 million and 208 million shares for the three months ended September 30, 2019 and 2018, respectively, which are considered antidilutive when calculating diluted earnings per share.

2019 Third Quarter Financial and Operational Results Conference Call Update

The conference call to discuss the company’s financial and operational results has been scheduled on Tuesday, November 5 at 9:00 am EDT. The telephone number to access the conference call is 1-888-317-6003 or 1-412-317-6061 for international callers. The passcode for the call is 2440889. 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, cost-cutting measures, reductions in expenditures, proposed refinancing transactions, capital exchange transactions, asset divestitures, reductions in capital expenditures, operational efficiencies, production and well connection forecasts, estimates of operating costs, anticipated capital and operational efficiencies, planned development drilling and expected drilling cost reductions, expected lateral lengths of wells, anticipated timing and number of wells to be placed into production, expected oil growth trajectory, anticipated timing of execution of new gathering agreement, expected savings in connection with new oil gathering and pipeline agreements, projected capital expenditures, 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 our ability to comply with the covenants under our revolving credit facilities and other indebtedness and the related impact on our ability to continue as a going concern, 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.

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,
	2019		2018*		2019		2018*
REVENUES AND OTHER:
Oil, natural gas and NGL^(a)	$	1,170	$	1,199	$	3,553	$	3,424
Marketing	889		1,219		3,038		3,738
Total Revenues	2,059		2,418		6,591		7,162
Other	15		16		45		48
Gains (losses) on sales of assets	13		(10)		33		27
Total Revenues and Other	2,087		2,424		6,669		7,237
OPERATING EXPENSES:
Oil, natural gas and NGL production	155		132		453		417
Oil, natural gas and NGL gathering, processing and transportation	270		364		815		1,060
Production taxes	35		34		109		91
Exploration	17		22		56		123
Marketing	901		1,238		3,071		3,798
General and administrative	66		81		258		273
Restructuring and other termination costs	—		—		—		38
Provision for legal contingencies, net	—		8		3		17
Depreciation, depletion and amortization	573		405		1,672		1,335
Impairments	9		58		11		122
Other operating (income) expense	15		—		79		(1)
Total Operating Expenses	2,041		2,342		6,527		7,273
INCOME (LOSS) FROM OPERATIONS	46		82		142		(36)
OTHER INCOME (EXPENSE):
Interest expense	(177)		(165)		(513)		(482)
Gains (losses) on investments	(4)		—		(28)		139
Gains (losses) on purchases or exchanges of debt	70		(68)		70		(68)
Other income	3		6		30		62
Total Other Expense	(108)		(227)		(441)		(349)
LOSS BEFORE INCOME TAXES	(62)		(145)		(299)		(385)
Income tax expense (benefit)	(1)		1		(315)		(8)
NET INCOME (LOSS)	(61)		(146)		16		(377)
Net income attributable to noncontrolling interests	—		—		—		(1)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(61)		(146)		16		(378)
Preferred stock dividends	(23)		(23)		(69)		(69)
Loss on exchange of preferred stock	(17)		—		(17)		—
NET LOSS AVAILABLE TO COMMON STOCKHOLDERS	$	(101)	$	(169)	$	(70)	$	(447)
LOSS PER COMMON SHARE:
Basic	$	(0.06)	$	(0.19)	$	(0.04)	$	(0.49)
Diluted	$	(0.06)	$	(0.19)	$	(0.04)	$	(0.49)
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic	1,698		910		1,570		909
Diluted	1,698		910		1,570		909


* Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting.


(a)	See Supplemental Data – Oil, Natural Gas and NGL Production and Sales Prices 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, 2019		December 31, 2018

Cash and cash equivalents	$	14	$	4
Other current assets	1,389		1,594
Total Current Assets	1,403		1,598

Property and equipment, net	14,876		10,818
Other long-term assets	300		319
Total Assets	$	16,579	$	12,735

Current liabilities	$	2,348	$	2,887
Long-term debt, net	9,133		7,341
Other long-term liabilities	363		374
Total Liabilities	11,844		10,602

Preferred stock	1,631		1,671
Noncontrolling interests	39		41
Common stock and other stockholders’ equity	3,065		421
Total Equity	4,735		2,133

Total Liabilities and Equity	$	16,579	$	12,735

CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED CASH FLOW DATA ($ in millions) (unaudited)
	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018*		2019		2018*

Beginning cash and cash equivalents	$	4	$	3	$	4	$	5

Net cash provided by operating activities	329		444		1,182		1,395

Cash flows from investing activities:
Drilling and completion costs^(a)	(570)		(479)		(1,640)		(1,407)
Business combination, net	—		—		(353)		—
Acquisitions of proved and unproved properties	(14)		(16)		(31)		(118)
Proceeds from divestitures of proved and unproved properties	28		11		110		395
Additions to other property and equipment	(9)		(6)		(27)		(11)
Proceeds from sales of other property and equipment	2		1		6		75
Proceeds from sales of investments	—		—		—		74
Net cash used in investing activities	(563)		(489)		(1,935)		(992)

Net cash provided by (used in) financing activities	244		46		763		(404)
Change in cash and cash equivalents	10		1		10		(1)
Ending cash and cash equivalents	$	14	$	4	$	14	$	4


* Financial information for 2018 has been recast to reflect the retrospective application of the successful efforts method of accounting.


(a)	Includes capitalized interest of $6 million and $4 million for the three months ended September 30, 2019 and 2018, respectively, and includes capitalized interest of $19 million and $13 million for the nine months ended September 30, 2019 and 2018, respectively.

CHESAPEAKE ENERGY CORPORATION SUPPLEMENTAL DATA – OIL, NATURAL GAS AND NGL PRODUCTION AND SALES PRICES (unaudited)
	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Net Production:
Oil (mmbbl)	10		9		31		25
Natural gas (bcf)	183		215		550		647
NGL (mmbbl)	3		5		10		15
Oil equivalent (mmboe)	44		49		133		148
Average daily production (mboe)	478		537		486		540
Oil, Natural Gas and NGL Sales ($ in millions):
Oil sales	$	613	$	594	$	1,879	$	1,698
Natural gas sales	353		578		1,384		1,822
NGL sales	37		159		149		404
Total oil, natural gas and NGL sales	$	1,003	$	1,331	$	3,412	$	3,924

Financial Derivatives:
Oil derivatives – realized gains (losses)^(a)	$	26	$	(112)	$	18	$	(273)
Natural gas derivatives – realized gains (losses)^(a)	83		(1)		71		83
NGL derivatives – realized losses^(a)	—		(10)		—		(14)
Total realized gains (losses) on financial derivatives	$	109	$	(123)	$	89	$	(204)

Oil derivatives – unrealized gains (losses)^(b)	$	98	$	12	$	(67)	$	(115)
Natural gas derivatives – unrealized gains (losses)^(b)	(40)		(17)		119		(168)
NGL derivatives – unrealized losses^(b)	—		(4)		—		(13)
Total unrealized gains (losses) on financial derivatives	$	58	$	(9)	$	52	$	(296)

Total financial derivatives	$	167	$	(132)	$	141	$	(500)

Total oil, natural gas and NGL sales	$	1,170	$	1,199	$	3,553	$	3,424
Average Sales Price (excluding gains (losses) on derivatives):
Oil ($ per bbl)	$	58.18	$	72.39	$	59.78	$	68.63
Natural gas ($ per mcf)	$	1.93	$	2.69	$	2.51	$	2.82
NGL ($ per bbl)	$	12.44	$	29.09	$	15.50	$	26.87
Oil equivalent ($ per boe)	$	22.79	$	26.92	$	25.70	$	26.59
Average Sales Price (excluding unrealized gains (losses) on derivatives):
Oil ($ per bbl)	$	60.66	$	58.77	$	60.37	$	57.61
Natural gas ($ per mcf)	$	2.38	$	2.69	$	2.64	$	2.94
NGL ($ per bbl)	$	12.44	$	27.37	$	15.50	$	25.96
Oil equivalent ($ per boe)	$	25.26	$	24.44	$	26.37	$	25.21


(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. 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)	Unrealized gains (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 (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.

CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE ($ in millions) (unaudited)
	Three Months Ended September 30,
	2019				2018
	$		$/Share		$		$/Share
Net loss available to common stockholders (GAAP)	$	(101)	$	(0.06)	$	(169)	$	(0.19)
Effect of dilutive securities	—		—		—		—
Diluted loss available to common stockholders (GAAP)^(a)	$	(101)	$	(0.06)	$	(169)	$	(0.19)

Adjustments:
Unrealized (gains) losses on oil, natural gas and NGL derivatives	(58)		(0.03)		9		0.01
Provision for legal contingencies, net	—		—		8		0.01
(Gains) losses on sales of assets	(13)		(0.01)		10		0.01
Other operating expense	15		0.01		—		—
Impairments	9		0.01		58		0.06
Losses on investments	4		—		—		—
(Gains) losses on purchases or exchanges of debt	(70)		(0.04)		68		0.08
Loss on exchange of preferred stock	17		0.01		—		—
Other revenue	(15)		(0.01)		(16)		(0.02)
Other	1		—		1		—
Income tax benefit^(b)	—		—		—		—
Adjusted net loss available to common stockholders^(c) (Non-GAAP)	(211)		(0.12)		(31)		(0.04)

Preferred stock dividends	23		0.01		23		0.03
Total adjusted net loss attributable to Chesapeake^(a)(c)(Non-GAAP)	$	(188)	$	(0.11)	$	(8)	$	(0.01)

CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE ($ in millions) (unaudited)
	Nine Months Ended September 30,
	2019				2018
	$		$/Share		$		$/Share
Net loss available to common stockholders (GAAP)	$	(70)	$	(0.04)	$	(447)	$	(0.49)
Effect of dilutive securities	—		—		—		—
Diluted loss available to common stockholders (GAAP)^(d)	$	(70)	$	(0.04)	$	(447)	$	(0.49)

Adjustments:
Unrealized (gains) losses on oil, natural gas and NGL derivatives	(45)		(0.03)		296		0.33
Restructuring and other termination costs	—		—		38		0.04
Provision for legal contingencies, net	3		—		17		0.02
Gains on sales of assets	(33)		(0.02)		(27)		(0.03)
Other operating (income) expense^(e)	79		0.05		(1)		—
Impairments	11		0.01		122		0.13
(Gains) losses on investments	28		0.02		(139)		(0.15)
(Gains) losses on purchases or exchanges of debt	(70)		(0.04)		68		0.07
Loss on exchange of preferred stock	17		0.01		—		—
Other revenue	(45)		(0.03)		(48)		(0.05)
Other	(3)		—		(60)		(0.07)
Income tax benefit^(f)	(314)		(0.20)		—		—
Adjusted net loss available to common stockholders^(c) (Non-GAAP)	(442)		(0.27)		(181)		(0.20)

Preferred stock dividends	69		0.04		69		0.08
Total adjusted net loss attributable to Chesapeake^(d)(c)(Non-GAAP)	$	(373)	$	(0.23)	$	(112)	$	(0.12)


(a)	Our presentation of diluted net losses available to common stockholders per share and diluted adjusted net loss per share excludes 183 million and 208 million shares considered antidilutive for the three months ended September 30, 2019 and 2018. The number of shares used for the non-GAAP calculation was determined in a manner consistent with GAAP.

(b)	No income tax effect from the adjustments has been included in determining adjusted net income for the three months ended September 30, 2019 and 2018. Our effective tax rate was 0% due to our valuation allowance position.

(c)	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 our calculations 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 measures of other companies.

(d)	Our presentation of diluted net losses available to common stockholders per share and diluted adjusted net loss per share excludes 184 million and 207 million shares considered antidilutive for the nine months ended September 30, 2019 and 2018. The number of shares used for the non-GAAP calculation was determined in a manner consistent with GAAP.

(e)	The nine months ended September 30, 2019 includes $34 million in integration and acquisition costs as a result of Chesapeake’s merger with WildHorse Resource Development Corporation (WRD). Additionally, most WRD executives and employees were terminated and entitled to severance benefits of approximately $38 million in accordance with certain provisions of existing employment agreements that were triggered by the change in control.

(f)	For the nine months ended September 30, 2019, we recorded a net deferred tax liability of $314 million associated with the acquisition of WildHorse Resource Development Corporation. As a result of recording this net deferred tax liability through business combination accounting, we released a corresponding amount of the valuation allowance that we maintain against our net deferred tax asset position. This release resulted in an income tax benefit of $314 million. Further, no income tax expense or benefit is shown for the adjustments being made to arrive at adjusted net loss available to common stockholders as a result of not recording an income tax expense or benefit on current period results due to maintaining a full valuation allowance against our net deferred tax asset position.

CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF CASH PROVIDED BY OPERATING ACTIVITIES TO ADJUSTED EBITDAX ($ in millions) (unaudited)
	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
CASH PROVIDED BY OPERATING ACTIVITIES (GAAP)	$	329	$	444	$	1,182	$	1,395

Adjustments:
Changes in assets and liabilities	77		(7)		214		(69)
Other revenue	(15)		(16)		(45)		(48)
Interest expense	177		165		513		482
Exploration	7		14		21		42
Income tax expense	(1)		2		(1)		2
Stock-based compensation	(7)		(7)		(24)		(25)
Restructuring and other termination costs	—		—		—		38
Losses on investments	—		—		6		—
Net income attributable to noncontrolling interests	—		—		—		(1)
Other items	10		(11)		(1)		3
Adjusted EBITDAX (Non-GAAP)^(a)	$	577	$	584	$	1,865	$	1,819


(a)	Adjusted EBITDAX is not a measure of financial performance under GAAP, and should not be considered as an alternative to, or more meaningful than, cash flow provided by operating activities prepared in accordance with GAAP. Adjusted EBITDAX excludes certain items that management believes affect the comparability of operating results. The company believes this non-GAAP financial measure is a useful adjunct to cash flow provided by operating activities because:

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

	(ii)	Adjusted EBITDAX 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 EBITDAX excludes some, but not all, items that affect net income (loss), our calculations of adjusted EBITDAX may not be comparable to similarly titled measures of other companies.

CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF NET INCOME (LOSS) TO ADJUSTED EBITDAX ($ in millions) (unaudited)
	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
NET INCOME (LOSS) (GAAP)	$	(61)	$	(146)	$	16	$	(377)

Adjustments:
Interest expense	177		165		513		482
Income tax expense (benefit)	(1)		1		(315)		(8)
Depreciation, depletion and amortization	573		405		1,672		1,335
Exploration	17		22		56		123
Unrealized (gains) losses on oil, natural gas and NGL derivatives	(58)		9		(45)		296
Restructuring and other termination costs	—		—		—		38
Provision for legal contingencies, net	—		8		3		17
(Gains) losses on sales of assets	(13)		10		(33)		(27)
Other operating (income) expense	15		—		79		(1)
Impairments	9		58		11		122
(Gains) losses on investments	4		—		28		(139)
(Gains) losses on purchases or exchanges of debt	(70)		68		(70)		68
Net (income) loss attributable to noncontrolling interests	—		—		—		(1)
Other revenue	(15)		(16)		(45)		(48)
Other	—		—		(5)		(61)
Adjusted EBITDAX (Non-GAAP)^(a)	$	577	$	584	$	1,865	$	1,819


(a)	Adjusted EBITDAX is not a measure of financial performance under GAAP, and should not be considered as an alternative to, or more meaningful than, net income (loss) prepared in accordance with GAAP. Adjusted EBITDAX excludes certain items that management believes affect the comparability of operating results. The company believes this non-GAAP financial measure is a useful adjunct to net income (loss) because:

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

	(ii)	Adjusted EBITDAX 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 EBITDAX excludes some, but not all, items that affect net income (loss), our calculations of adjusted EBITDAX may not be comparable to similarly titled measures of other companies.

CHESAPEAKE ENERGY CORPORATION MANAGEMENT’S OUTLOOK AS OF NOVEMBER 5, 2019

Chesapeake periodically provides guidance on certain factors that affect the company’s future financial performance. New information or changes from the company’s August 6, 2019 outlook are *italicized bold* below.

	Year Ending 12/31/2019
Absolute Production:
Oil – mmbbls	43.0 – 44.5
NGL – mmbbls	13.0 – 15.0
Natural gas – bcf	725 – 750
Total absolute production – mmboe	177 – 184
Absolute daily rate – mboe	484 – 505
*Estimated Realized Hedging Effects^(a) (based on 10/31/19 strip prices)*
*Oil – $/bbl*	$1.52
*Natural gas – $/mcf*	$0.15
Estimated Basis to NYMEX Prices:
*Oil – $/bbl*	*$1.85 – $2.05*
*Natural gas – $/mcf*	*($0.15) – ($0.25)*
NGL – realizations as a % of WTI	25% – 28%
Operating Costs per boe of Projected Production:
Production expense	$3.20 – $3.40
Gathering, processing and transportation expenses	$5.90 – $6.40
Oil – $/bbl	$2.95 – $3.15
Natural Gas – $/mcf	$1.20 – $1.30
Production taxes	$0.80 – $0.90
General and administrative^(b)	$1.75 – $1.85
Stock-based compensation (non-cash)	$0.10 – $0.20
Marketing Net Margin and Other ($ in millions)^(c)	($15) – ($35)
*Adjusted EBITDAX, based on 10/31/19 strip prices ($ in millions)^(d)*	*$2,400 – $2,600*
Depreciation, depletion and amortization expense	$12.50 – $13.50
*Interest expense*	*$3.70 – $3.90*
Exploration expense ($ in millions, cash only)	$35 – $45
Book Tax Rate	0%
Capital Expenditures ($ in millions)^(e)	$2,085 – $2,285
Capitalized Interest ($ in millions)	$20
Total Capital Expenditures ($ in millions)	$2,105 – $2,305


(a)	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.
(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)	Excludes non-cash amortization of approximately $8.7 million related to the buydown of a transportation agreement.
(d)	Adjusted EBITDAX 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 EBITDAX excludes certain items that management believes affect the comparability of operating results. The most directly comparable GAAP measure is net income (loss) 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 (loss) 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 EBITDAX to forecasted GAAP net income (loss) would imply a degree of precision that may be confusing or misleading to investors. Items excluded from net income to arrive at adjusted EBITDAX include interest expense, income taxes, and depreciation, depletion and amortization expense, exploration expense as well as one-time items or items whose timing or amount cannot be reasonably estimated.
(e)	Includes capital expenditures for drilling and completion, leasehold, developmental geological and geophysical costs, rig termination payments and other property, plant and equipment. Excludes any additional proved property acquisitions and expenditures classified as exploration expense.

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 31, 2019, including October and November derivative contracts that have settled, approximately 80% of the company’s 2019 forecasted oil, natural gas and NGL production revenue was hedged, including approximately 74% and 75% of its remaining 2019 forecasted oil and natural gas production at average prices of $59.34 per bbl and $2.83 per mcf, respectively.

In addition, the company had downside protection on a portion of its 2020 oil production at an average price of $59.28 per bbl and on a portion of its 2020 gas production at an average price of $2.76 per mcf.

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

Open Crude Oil Swaps
	Volume (mmbbls)	Avg. NYMEX Price of Swaps

Q4 2019	7	$	60.24
Total 2019	7	$	60.24

Q1 2020	4	$	58.50
Q2 2020	4	$	58.57
Q3 2020	4	$	58.64
Q4 2020	3	$	58.71
Total 2020	15	$	58.60

Oil Two-Way Collars
	Volume (mmbbls)	Avg. NYMEX Bought Put Price		Avg. NYMEX Sold Call Price

Q4 2019	1	$	58.00	$	67.75
Total 2019	1	$	58.00	$	67.75

Q1 2020	0.5	$	65.00	$	83.25
Q2 2020	0.5	$	65.00	$	83.25
Q3 2020	0.5	$	65.00	$	83.25
Q4 2020	0.5	$	65.00	$	83.25
Total 2020	2	$	65.00	$	83.25

Oil Puts
	Volume (mmbbls)	Avg. NYMEX Bought Put Price

Q4 2019	1	$	54.43
Total 2019	1	$	54.43

Oil Swaptions
	Volume (mmbbls)	Avg. NYMEX Strike Price

Q1 2020	1	$	63.15
Q2 2020	1	$	63.15
Total 2020	2	$	63.15

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

Q4 2019	2	$	5.67
Total 2019	2	$	5.67

Q1 2020	1	$	2.45
Q2 2020	1	$	2.45
Q3 2020	1	$	2.45
Q4 2020	2	$	2.45
Total 2020	5	$	2.45

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

Open Natural Gas Swaps
	Volume (bcf)	Avg. NYMEX Price of Swaps

Q4 2019	118	$	2.84
Total 2019	118	$	2.84

Q1 2020	66	$	2.76
Q2 2020	66	$	2.76
Q3 2020	67	$	2.76
Q4 2020	66	$	2.76
Total 2020	265	$	2.76

Natural Gas Two-Way Collars
	Volume (bcf)	Avg. NYMEX Bought Put Price		Avg. NYMEX Sold Call Price

Q4 2019	9	$	2.75	$	2.91
Total 2019	9	$	2.75	$	2.91

Natural Gas Three-Way Collars
	Volume (bcf)	Avg. NYMEX Sold Put Price		Avg. NYMEX Bought Put Price		Avg. NYMEX Sold Call Price

Q4 2019	15	$	2.50	$	2.80	$	3.10
Total 2019	15	$	2.50	$	2.80	$	3.10

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

Q4 2019	6	$	12.00
Total 2019	6	$	12.00

Q1 2020	5	$	12.00
Q2 2020	5	$	12.00
Q3 2020	6	$	12.00
Q4 2020	6	$	12.00
Total 2020	22	$	12.00

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

Q1 2020	26	$	2.77
Q2 2020	26	$	2.77
Q3 2020	27	$	2.77
Q4 2020	27	$	2.77
Total 2020	106	$	2.77

Total 2021	15	$	2.80

Total 2022	15	$	2.80

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

Q4 2019	29	$	(0.10)
Total 2019	29	$	(0.10)

Q1 2020	30	$	0.08
Total 2020	30	$	0.08

INVESTOR CONTACT:

MEDIA CONTACT:

Brad Sylvester, CFA

(405) 935-8870

[email protected]

Gordon Pennoyer

(405) 935-8878

[email protected]

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SOURCE Chesapeake Energy Corporation

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November 5, 2019 – 4:00 AM PST

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Chesapeake Energy Corporation Reports 2019 Third Quarter Financial And Operational Results, Maintains 2019 Guidance And Announces Plans To Reduce 2020 Capital Budget

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