Chesapeake Energy Corporation Reports 2019 First Quarter Financial And Operational Results

OKLAHOMA CITY, May 8, 2019 /PRNewswire/ -- Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operational results for the 2019 first quarter. Highlights include:

Early Brazos Valley (BVL) Success: Eliminated approximately $500,000 in costs per well since February 1, 2019, with additional savings forecasted by year-end, driven by faster drilling and more fracture stimulation stages completed per day; have achieved savings of over $1 million per well on certain individual wells; early production from first proprietary wells above expectations.
On Track to Deliver Transformational Oil Growth in 2019: Driven by shallower production declines in South Texas due to well spacing and base production improvements and continued improvement in the Powder River Basin (PRB), which achieved record production during the quarter and again in the month of April 2019, the company remains on track to deliver oil growth of approximately 32% with a year-end oil mix of approximately 26%.
Average Oil Production of Approximately 109,000 Barrels (Bbls) per Day: Year-over-year absolute growth of 18%, or 13% adjusted for asset purchases and sales, and approximately 22% of total net daily production.
Average Production of Approximately 484,000 Barrels of Oil Equivalent (Boe) per Day
Continued Shift to Higher Oil Mix and Focus on Reducing Expenses Results in Highest Operating Margin per Boe Since 2014

(PRNewsfoto/Chesapeake Energy Corporation)

Doug Lawler, Chesapeake's President and Chief Executive Officer, commented, "We continue to execute on our strategic priorities and once again delivered strong financial and operational results. The encouraging early results from our Brazos Valley business unit, which we now project will be cash flow positive at the asset operating level in 2019, demonstrates our capability to apply our capital and operating efficiency to immediately transform a new asset in our portfolio. We believe we will see significantly more savings in the year ahead as we fully integrate our Brazos Valley operations into Chesapeake. With our transformational oil growth and capital efficiency continuing to improve, our confidence is strong as we drive towards achieving our strategic priorities of meaningful margin enhancement, sustainable free cash flow and a net debt to EBITDAX ratio of two times."

2019 First Quarter Results

Average daily production for the 2019 first quarter was approximately 484,000 boe and consisted of approximately 109,000 bbls of oil, 2.023 billion cubic feet (bcf) of natural gas and 39,000 bbls of natural gas liquids. Average daily production for the 2018 first quarter was approximately 554,000 boe and consisted of approximately 92,000 bbls of oil, 2.466 bcf of natural gas and 51,000 bbls of NGL. Oil production represented approximately 22% of the company's 2019 first quarter aggregate production compared to 17% in the 2018 first quarter.

Chesapeake's operating margin per boe increased significantly in the 2019 first quarter compared to the 2018 first quarter, primarily driven by a higher oil production mix and a decrease in certain of its cash operating expenses (production expenses, gathering, processing and transportation expenses, and general and administrative expenses). Chesapeake reduced its cash operating expenses on an absolute basis by $81 million, or approximately $0.18 per boe, primarily driven by significant reductions in the company's gathering, processing and transportation expenses primarily as a result of certain 2018 divestitures.

In the 2019 first quarter, Chesapeake converted to the successful efforts method of accounting for its oil and natural gas exploration and development activities. See the table below for successful efforts-based financial results and results as calculated under the full cost method.

	Three Months Ended March 31, 2019
($ in millions, except per share amounts)	As Reported Under Successful Efforts		Under Full Cost
Net income (loss) available to common stockholders	$	(44)	$	156
Net income (loss) per diluted share	$	(0.03)	$	0.11
Adjusted net income (loss) attributable to Chesapeake (non-GAAP)	$	(27)	$	197
Adjusted net income (loss) per share attributable to Chesapeake (non-GAAP)	$	(0.02)	$	0.14
Adjusted EBITDAX (non-GAAP)	$	676	$	688

Reconciliations of financial measures calculated in accordance with GAAP to non-GAAP measures and pro forma comparisons to the previously employed method of accounting are provided on pages 14-21 of this release.

Capital Spending Overview

Chesapeake incurred total capital expenditures of approximately $559 million during the 2019 first quarter, including capitalized interest of $6 million, compared to approximately $543 million in the 2018 first quarter. The increase in capital expenditures in the 2019 first quarter was largely attributable to a higher average rig count and an increase in gross wells spud, completed and connected. A summary is provided in the table below.

	Three Months Ended March 31,
	2019		2018
	Net	Gross	Net	Gross
Operated activity comparison
Average rig count	12	20	10	15
Wells spud	53	79	53	77
Wells completed	60	83	56	76
Wells connected	60	83	44	57

Three Months Ended March 31, 2019
	Under Full Cost		Successful Efforts Adjustments		As Reported
Type of cost ($ in millions)
Drilling and completion capital expenditures	$	560	$	(18)	$	542
Leasehold and additions to other PP&E	13		(2)		11
Subtotal capital expenditures	$	573	$	(20)	$	553
Capitalized interest	32		(26)		6
Total capital expenditures	$	605	$	(46)	$	559


Three Months Ended March 31, 2018
	Under Full Cost		Successful Efforts Adjustments		As Reported
Type of cost ($ in millions)
Drilling and completion capital expenditures	$	539	$	(17)	$	522
Leasehold and additions to other PP&E	29		(12)		17
Subtotal capital expenditures	$	568	$	(29)	$	539
Capitalized interest	43		(39)		4
Total capital expenditures	$	611	$	(68)	$	543

Balance Sheet and Liquidity

As of March 31, 2019, Chesapeake's principal amount of debt outstanding inclusive of BVL debt was approximately $9.978 billion, compared to $8.168 billion as of December 31, 2018. The increase in debt outstanding was largely a result of $1.375 billion in debt assumed by Chesapeake as part of the WildHorse acquisition on February 1, 2019. As of March 31, 2019, under the $3.0 billion Chesapeake credit facility, the company had borrowed $842 million, utilized approximately $61 million for various letters of credit and had additional borrowing capacity of approximately $2.097 billion. Under the $1.3 billion BVL credit facility, BVL had borrowed $688 million, utilized approximately $47 million for a letter of credit and had additional borrowing capacity of approximately $565 million.

On April 3, 2019, Chesapeake exchanged approximately $919 million of new 8.0% Senior Notes due 2026 for approximately $884 million aggregate principal amount of its Senior Notes due 2020 and 2021. On April 15, 2019, Chesapeake repaid at maturity approximately $380 million of its Floating Rate Senior Notes due 2019.

Chesapeake has a robust hedge portfolio in place for 2019 to reduce its future revenue risk. As of May 3, 2019, including April and May derivative contracts that have settled, approximately 70% of the company's 2019 forecasted oil, natural gas and NGL production revenue was hedged, including approximately 70% and 80% of its remaining 2019 forecasted oil and natural gas production at average prices of $58.75 per bbl and $2.83 per thousand cubic feet (mcf), respectively. Additionally, Chesapeake has basis protection on approximately 6 million barrels (mmbbls) of its remaining projected 2019 Eagle Ford oil production at a premium to WTI of approximately $5.69 per bbl.

Operations Update

Chesapeake's average daily production for the 2019 first quarter was approximately 484,000 boe compared to approximately 554,000 boe in the 2018 first quarter. The following tables show average daily production and average daily sales prices received (excluding gains/losses on derivatives) by the company's operating areas for the 2019 and 2018 first quarters.

	Three Months Ended March 31, 2019
	Oil		Natural Gas		NGL		Total
	mbbl per day	$/bbl	mmcf per day	$/mcf	mbbl per day	$/bbl	mboe per day	%		$/boe
Marcellus	—	—	948	3.54	—	—	158	33		21.23
Haynesville	—	—	759	2.94	—	—	126	26		17.63
Eagle Ford	62	59.77	149	3.58	24	21.69	110	23		42.97
Brazos Valley^(a)	23	59.32	23	2.04	3	8.25	30	6		47.55
Powder River Basin	16	50.90	82	3.38	6	18.57	36	7		33.72
Mid-Continent	8	52.75	61	2.82	6	21.69	24	5		30.57
Retained assets^(b)	109	57.81	2,022	3.27	39	20.05	484	100		28.23
Divested assets	—	—	1	—	—	—	—	—		6.82
Total	109	57.80	2,023	3.27	39	20.03	484	100	%	28.22


	Three Months Ended March 31, 2018
	Oil		Natural Gas		NGL		Total
	mbbl per day	$/bbl	mmcf per day	$/mcf	mbbl per day	$/bbl	mboe per day	%		$/boe
Marcellus	—	—	874	3.74	—	—	146	26		22.45
Haynesville	—	—	832	2.80	—	—	139	25		16.79
Eagle Ford	61	66.16	141	3.30	18	24.72	102	19		48.21
Powder River Basin	7	62.87	47	2.82	3	28.77	18	3		37.66
Mid-Continent	8	61.92	62	2.68	4	26.06	23	4		34.74
Retained assets^(b)	76	65.36	1,956	3.25	25	25.38	428	77		28.07
Divested assets	16	60.98	510	2.92	26	25.53	126	23		24.54
Total	92	64.61	2,466	3.18	51	25.45	554	100	%	27.27


(a)	Average production per day since date of acquisition, 59 days, was approximately 35 mbbls of oil, 35 mmcf of natural gas and 5 mbbls of NGLs, respectively, for an average total production of 45 mboe per day.

(b)	Includes assets retained as of March 31, 2019.

Brazos Valley

The company's new business unit, which operates in the northern part of the Eagle Ford Shale and Austin Chalk Trend located primarily in Burleson, Lee and Washington counties in Texas, has already seen significant operational improvements since the company's acquisition closed on February 1, 2019. Within the first two months of owning the asset, Chesapeake has dramatically improved cycle times with faster drilling and more fracture stimulation stages completed per day, resulting in significant cost reductions. Through the first two months of operations, the company has already realized savings of approximately $500,000 per well due to improved drilling and completion techniques, supply chain and logistics synergies and the switch to regional sand sourced from its wholly owned sand mine in Burleson County that commenced operations in February 2019. Additional cost savings have been identified and the company expects the per-well savings to increase throughout the year.

On the company's Eagle Ford Easy Rider pad located in Burleson County, Chesapeake initiated its first choke management test in the area yielding significantly improved results. With completed laterals of approximately 7,500 feet, the pad's two wells achieved 24-hour peak oil production rates of 898 bbls per day and 1,546 bbls per day, respectively, demonstrating an approximate 35% uplift to historical type curve estimates from the area.

Additionally, Chesapeake has drilled and completed its first set of proprietary Eagle Ford wells on the Bell pad located in Burleson County. These four wells were completed with decreased fluid volumes (8,000 bbls per stage compared to 10,000 to 12,000 bbls per stage previously) and were placed on production in April 2019. While the average production rate from the pad is still climbing, the pad has already achieved a peak 24-hour oil production rate of 2,723 bbls of oil. These results are encouraging as the company optimizes fracture stimulations with lower fluids and higher sand volumes, simultaneously reducing costs and increasing productivity.

The company is currently utilizing four rigs in the area, placed 13 wells on production (five gas wells and eight oil wells) during the 2019 first quarter and expects to place 27 wells on production (four gas wells and 23 oil wells) during the 2019 second quarter. Included in the company's first quarter capital program were wells in the process of being completed in the gas window of the Austin Chalk play at the time of the closing of the acquisition. The company has since moved all four rigs to the oil and volatile oil windows of the Eagle Ford due to better economics and oil volumes. Chesapeake now anticipates its 2019 drilling program will average a lateral length of approximately 9,000 feet per well, representing a 27% increase over 2018 levels. The combination of longer laterals, optimized completions and effective flow back procedures have already delivered significant improvements in capital efficiency and returns, as expected as part of the company's original acquisition analysis, with more improvements expected in the next few months.

Eagle Ford Shale

In the company's Eagle Ford Shale position in South Texas, Chesapeake continues to generate free cash flow through steady oil volume production. Well performance has been especially strong due to optimized well spacing, enhanced completion designs and base production improvements resulting in consistent, high-margin oil volumes and markedly shallower production declines. Additional base production management efforts are expected throughout the year. Chesapeake is currently utilizing four rigs in South Texas, placed 29 wells on production during the 2019 first quarter and expects to place 16 wells on production during the 2019 second quarter.

The company is able to access Gulf Coast premium markets resulting in higher realized crude oil pricing for both its Brazos Valley and legacy Eagle Ford areas, contributing to higher margins. The company has protected a portion of this pricing advantage with basis hedges on approximately 6 mmbbls of remaining projected 2019 oil production at a premium to WTI of approximately $5.69 per bbl.

Powder River Basin

As a part of its ongoing portfolio optimization, Chesapeake has recently shifted a portion of its planned capital dollars from its Marcellus Shale and Mid-Continent areas to the PRB, where the company has recently moved a sixth rig. While all six rigs are currently drilling in the Turner formation, the company will transition one of the rigs to selectively drill Niobrara wells later in the year.

Average net production from the PRB for the 2019 first quarter was approximately 36,000 boe per day, including 16,000 bbls of oil, after experiencing several significant downtime events due to winter weather. Average net production from the PRB for the month of April was approximately 39,000 boe per day, including 18,000 bbls of oil and, as of May 1, 2019, the company set a new production record of approximately 42,000 boe per day, including 20,000 bbls of oil. The company placed 13 wells on production during the 2019 first quarter and expects to place 15 wells on production during the 2019 second quarter. As a result of the additional capital allocated to the PRB, the company now expects to place an additional eight wells to sales during the 2019 third and fourth quarters than initially forecasted.

Chesapeake recently achieved a new record-setting Turner oil well, the RRC 5-34-70 USA B TR 21H, which reached a peak rate of approximately 4,000 boe per day (75% oil) on May 4, 2019, while flowing at 2,000 psi wellhead pressure on a 48/64 inch choke. The company is encouraged by the exceptional well results in this area and expects continued success in the 2019 development program.

In May 2019, Chesapeake began connecting pads into a new oil gathering pipeline system which will transport volumes to Guernsey, Wyoming. The company expects the system to be fully operational across the field by June 2019, resulting in significant cost savings and improved certainty of delivery compared to trucking volumes. Chesapeake will use this new gathering system as an entry point into interstate pipelines and is working to deliver these volumes both to Cushing, Oklahoma beginning this summer and to Gulf Coast premium markets at Corpus Christi beginning in late 2020.

Marcellus Shale

Chesapeake continues to generate significant free cash flow in the Marcellus Shale in northeast Pennsylvania, primarily driven by strong realized in-basin gas prices and record production from improved well productivity through enhanced completions and longer laterals. Chesapeake achieved a record daily gross production level of approximately 2.5 bcf of gas per day in January 2019, resulting in record average net production of 948 mcf of gas per day during the 2019 first quarter. The company is currently utilizing three rigs but plans to move to two rigs by the end of June 2019. Chesapeake placed nine wells on production during the 2019 first quarter and expects to place 14 wells on production during the 2019 second quarter.

Haynesville Shale

In the Haynesville Shale in Louisiana, Chesapeake expects to decrease its activity throughout the year, moving from two rigs to one rig by the end of May 2019. The company placed ten wells on production in the Haynesville Shale during the 2019 first quarter and expects to place nine wells on production during the 2019 second quarter.

Mid-Continent

In the company's Mid-Continent operating area in Oklahoma, Chesapeake dropped its only rig in May 2019. The company placed nine wells on production during the 2019 first quarter and expects to place five wells on production during the 2019 second quarter. The company expects to increase activity in the Mid-Continent area in 2020, after newly acquired 3D seismic has been interpreted and its drilling inventory has been high-graded.

Key Financial and Operational Results

The table below summarizes Chesapeake's key financial and operational results during the 2019 first quarter as compared to results in prior periods. The three months ended March 31, 2019 include two months of Brazos Valley operations. The three months ending March 31, 2018 do not include Brazos Valley operations.

	Three Months Ended March 31,
	2019	2018
Barrels of oil equivalent production (in mboe)	43,600	49,879
Barrels of oil equivalent production (mboe/d)	484	554
Oil production (in mbbl/d)	109	92
Average realized oil price ($/bbl)^(a)	56.86	56.89
Natural gas production (in mmcf/d)	2,023	2,466
Average realized natural gas price ($/mcf)^(a)	3.07	3.49
NGL production (in mbbl/d)	39	51
Average realized NGL price ($/bbl)^(a)	20.03	25.36
Production expenses ($/boe)	3.02	2.94
Gathering, processing and transportation expenses ($/boe)	6.29	7.15
Oil - ($/bbl)	3.47	4.18
Natural Gas - ($/mcf)	1.21	1.27
NGL - ($/bbl)	5.57	8.83
Production taxes ($/boe)	0.78	0.62
Exploration expenses ($ in millions)	24	81
General and administrative expenses ($/boe)^(b)	2.20	1.60
General and administrative expenses (stock-based compensation) (non-cash) ($/boe)	0.14	0.14
DD&A of oil and natural gas properties ($/boe)	11.90	9.20
Interest expense ($/boe)^(c)	3.67	3.25
Marketing net margin ($ in millions)^(d)	8	(17)
Net cash provided by operating activities ($ in millions)	456	588
Net cash provided by operating activities ($/boe)	10.46	11.79
Net income (loss) ($ in millions)	(21)	18
Net loss available to common stockholders ($ in millions)	(44)	(6)
Net loss per share available to common stockholders – diluted ($)	(0.03)	(0.01)
Adjusted EBITDAX ($ in millions)^(e)	676	717
Adjusted EBITDAX ($/boe)	15.50	14.37
Adjusted net income (loss) attributable to Chesapeake ($ in millions)^(f)	(27)	16
Adjusted net income (loss) attributable to Chesapeake per share - diluted ($)^(g)	(0.02)	0.02


(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)	Excludes non-cash amortization of $5 million for the three months ended March 31, 2019 and 2018, related to the buydown 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 on page 20. This is a non-GAAP measure. See reconciliation of cash provided by operating activities to adjusted EBITDAX on page 19 and reconciliation of net income (loss) to adjusted EBITDAX on page 20.
(f)	Defined as net income (loss) attributable to Chesapeake, as adjusted to remove the effects of certain items detailed on pages 14-18. This is a non-GAAP measure. See reconciliation of net income (loss) to adjusted net income (loss) available to Chesapeake on pages 14-18.
(g)	Our presentation of diluted adjusted net income (loss) attributable to Chesapeake per share excludes 206 million shares for the three months ended March 31, 2019 and 2018, which are considered antidilutive when calculating diluted earnings per share.

2019 First Quarter Financial and Operational Results Conference Call Update

The conference call to discuss the company's financial and operational results has been scheduled on Wednesday, May 8 at 9:00 am EDT. The telephone number to access the conference call is 877-870-4263 or 1-412-317-0790 for international callers. The passcode for the call is 4269013. 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, expected lateral lengths of wells, anticipated timing of wells to be placed into production, anticipated timing of the Brazos Valley business unit becoming cash flow positive, general and administrative expenses, 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 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 March 31,
	2019		2018*
REVENUES AND OTHER:
Oil, natural gas and NGL^(a)	$	929	$	1,243
Marketing	1,233		1,246
Total Revenues	2,162		2,489
Other	15		16
Gains on sales of assets	19		19
Total Revenues and Other	2,196		2,524
OPERATING EXPENSES:
Oil, natural gas and NGL production	132		147
Oil, natural gas and NGL gathering, processing and transportation	274		356
Production taxes	34		31
Exploration	24		81
Marketing	1,230		1,268
General and administrative	103		87
Restructuring and other termination costs	—		38
Provision for legal contingencies, net	—		5
Depreciation, depletion and amortization	519		459
Impairments	1		10
Other operating expense	61		—
Total Operating Expenses	2,378		2,482
INCOME (LOSS) FROM OPERATIONS	(182)		42
OTHER INCOME (EXPENSE):
Interest expense	(161)		(162)
Gains (losses) on investments	(1)		139
Other income (expense)	9		(1)
Total Other Expense	(153)		(24)
INCOME (LOSS) BEFORE INCOME TAXES	(335)		18
Income tax benefit	(314)		—
NET INCOME (LOSS)	(21)		18
Net income attributable to noncontrolling interests	—		(1)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(21)		17
Preferred stock dividends	(23)		(23)
NET LOSS AVAILABLE TO COMMON STOCKHOLDERS	$	(44)	$	(6)
EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	(0.03)	$	(0.01)
Diluted	$	(0.03)	$	(0.01)
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic	1,380		907
Diluted	1,380		907


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

(a)	See page 12 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)
	March 31, 2019		December 31, 2018

Cash and cash equivalents	$	8	$	4
Other current assets	1,357		1,594
Total Current Assets	1,365		1,598

Property and equipment, net	14,939		10,818
Other long-term assets	333		319
Total Assets	$	16,637	$	12,735

Current liabilities	$	2,930	$	2,887
Long-term debt, net	9,167		7,341
Other long-term liabilities	402		374
Total Liabilities	12,499		10,602

Preferred stock	1,671		1,671
Noncontrolling interests	41		41
Common stock and other stockholders' equity	2,426		421
Total Equity	4,138		2,133

Total Liabilities and Equity	$	16,637	$	12,735

CHESAPEAKE ENERGY CORPORATION SUPPLEMENTAL DATA – OIL, NATURAL GAS AND NGL PRODUCTION AND SALES PRICES (unaudited)
	Three Months Ended March 31,
	2019		2018
Net Production:
Oil (mmbbl)	10		8
Natural gas (bcf)	182		222
NGL (mmbbl)	4		5
Oil equivalent (mmboe)	44		50
Average daily production (mboe)	484		554
Oil, Natural Gas and NGL Sales ($ in millions):
Oil sales	$	566	$	537
Natural gas sales	595		706
NGL sales	69		117
Total oil, natural gas and NGL sales	$	1,230	$	1,360

Financial Derivatives:
Oil derivatives – realized gains (losses)^(a)	$	10	(64)
Natural gas derivatives – realized gains (losses)^(a)	(36)		67
NGL derivatives – realized losses^(a)	—		(1)
Total realized gains (losses) on financial derivatives	$	(26)	$	2

Oil derivatives – unrealized losses^(b)	(269)		(22)
Natural gas derivatives – unrealized losses^(b)	(6)		(99)
NGL derivatives – unrealized gains^(b)	—		2
Total unrealized losses on financial derivatives	$	(275)	$	(119)

Total financial derivatives	$	(301)	$	(117)

Total oil, natural gas and NGL sales	$	929	$	1,243
Average Sales Price (excluding gains (losses) on derivatives):
Oil ($ per bbl)	$	57.80	$	64.61
Natural gas ($ per mcf)	$	3.27	$	3.18
NGL ($ per bbl)	$	20.03	$	25.45
Oil equivalent ($ per boe)	$	28.22	$	27.27
Average Sales Price (excluding unrealized gains (losses) on derivatives):
Oil ($ per bbl)	$	58.86	$	56.89
Natural gas ($ per mcf)	$	3.07	$	3.49
NGL ($ per bbl)	$	20.03	$	25.36
Oil equivalent ($ per boe)	$	27.62	$	27.31


(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 (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.

CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED CASH FLOW DATA ($ in millions) (unaudited)
	Three Months Ended March 31,
	2019		2018*

Beginning cash and cash equivalents	$	4	$	5

Net cash provided by operating activities	456		588

Cash flows from investing activities:
Drilling and completion costs^(a)	(515)		(420)
Business combination, net	(353)		—
Acquisitions of proved and unproved properties	(6)		(17)
Proceeds from divestitures of proved and unproved properties	26		319
Additions to other property and equipment	(9)		(3)
Proceeds from sales of other property and equipment	1		68
Proceeds from sales of investments	—		74
Net cash provided by (used in) investing activities	(856)		21

Net cash provided by (used in) financing activities	404		(610)
Change in cash and cash equivalents	4		(1)
Ending cash and cash equivalents	$	8	$	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 March 31, 2019 and 2018, respectively.

CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS ($ in millions) (unaudited)
	Three Months Ended March 31, 2019
	Under Full Cost		Successful Efforts Adjustments		As Reported
Net income (loss) available to common stockholders (GAAP)	$	156	$	(200)	$	(44)
Effect of dilutive securities	—		—		—
Diluted earnings (losses) available to common stockholders (GAAP)^(a)	$	156	$	(200)	$	(44)

Adjustments:
Unrealized losses on oil, natural gas and NGL derivatives	281		—		281
Gains on sales of assets	—		(19)		(19)
Other operating expense^(b)	51		10		61
Impairments	1		—		1
Losses on investments	1		—		1
Other revenue (VPP deferred revenue)	—		(15)		(15)
Other	(2)		—		(2)
Income tax benefit^(c)	(314)		—		(314)
Adjusted net income (loss) available to common stockholders^(d) (Non-GAAP)	174		(224)		(50)

Preferred stock dividends	23		—		23
Earnings allocated to participating securities	—		—		—
Total adjusted net income (loss) attributable to Chesapeake^(d)(a) (Non-GAAP)	$	197	$	(224)	$	(27)

CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED NET INCOME (LOSS) PER SHARE AVAILABLE TO COMMON STOCKHOLDERS (unaudited)
	Three Months Ended March 31, 2019
	Under Full Cost		Successful Efforts Adjustments		As Reported
Net income (loss) per share available to common stockholders (GAAP)	$	0.11	$	(0.14)	$	(0.03)
Effect of dilutive securities	—		—		—
Diluted earnings (losses) per common stockholder (GAAP)^(a)	$	0.11	$	(0.14)	$	(0.03)

Adjustments:
Unrealized losses on oil, natural gas and NGL derivatives	0.20		—		0.20
Gains on sales of assets	—		(0.01)		(0.01)
Other operating expense^(b)	0.04		—		0.04
Impairments	—		—		—
Losses on investments	—		—		—
Other revenue (VPP deferred revenue)	—		(0.01)		(0.01)
Other	—		—		—
Income tax benefit^(c)	(0.23)		—		(0.23)
Adjusted net income (loss) per share available to common stockholders^(d) (Non-GAAP)	0.12		(0.16)		(0.04)

Preferred stock dividends	0.02		—		0.02
Earnings allocated to participating securities	—		—		—
Total adjusted net income (loss) per share attributable to Chesapeake^(d)(a) (Non-GAAP)	$	0.14	$	(0.16)	$	(0.02)

CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS ($ in millions) (unaudited)
	Three Months Ended March 31, 2018
	Under Full Cost		Successful Efforts Adjustments		As Reported
Net income (loss) available to common stockholders (GAAP)	$	268	$	(274)	$	(6)
Effect of dilutive securities	36		(36)		—
Diluted earnings (losses) available to common stockholders (GAAP)^(a)	$	304	$	(310)	$	(6)

Adjustments:
Unrealized losses on oil, natural gas and NGL derivatives	119		—		119
Restructuring and other termination costs	38		—		38
Provision for legal contingencies, net	5		—		5
Gains on sales of assets	—		(19)		(19)
Other operating expense	8		(8)		—
Impairments	—		10		10
Gains on investments	(139)		—		(139)
Other revenue (VPP deferred revenue)	—		(16)		(16)
Other	1		—		1
Income tax expense^(e)	—		—		—
Adjusted net income (loss) available to common stockholders^(d) (Non-GAAP)	336		(343)		(7)

Preferred stock dividends	23		—		23
Earnings allocated to participating securities	2		(2)		—
Total adjusted net income (loss) attributable to Chesapeake^(d)(a) (Non-GAAP)	$	361	$	(345)	$	16

CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED NET INCOME (LOSS) PER SHARE AVAILABLE TO COMMON STOCKHOLDERS (unaudited)
	Three Months Ended March 31, 2018
	Under Full Cost		Successful Efforts Adjustments		As Reported
Net income (loss) per share available to common stockholders (GAAP)	$	0.30	$	(0.31)	$	(0.01)
Effect of dilutive securities	(0.01)		0.01		—
Diluted earnings (losses) per common stockholder (GAAP)^(a)	$	0.29	$	(0.30)	$	(0.01)

Adjustments:
Unrealized losses on oil, natural gas and NGL derivatives	0.11		0.02		0.13
Restructuring and other termination costs	0.04		—		0.04
Provision for legal contingencies, net	—		0.01		0.01
Gains on sales of assets	—		(0.02)		(0.02)
Other operating expense	0.01		(0.01)		—
Impairments	—		0.01		0.01
Gains on investments	(0.13)		(0.02)		(0.15)
Other revenue (VPP deferred revenue)	—		(0.02)		(0.02)
Other	—		—		—
Income tax expense^(e)	—		—		—
Adjusted net income (loss) per share available to common stockholders^(d) (Non-GAAP)	0.32		(0.33)		(0.01)

Preferred stock dividends	0.02		0.01		0.03
Earnings allocated to participating securities	—		—		—
Total adjusted net income (loss) per share attributable to Chesapeake^(d)(a) (Non-GAAP)	$	0.34	$	(0.32)	$	0.02


(a)	Our presentation of diluted net income (loss) available to common stockholders and diluted adjusted net income (loss) per share excludes 206 million shares considered antidilutive for the three months ended March 31, 2019 and 2018. The number of shares used for the non-GAAP calculation was determined in a manner consistent with GAAP.

(b)	As a result of the merger with Chesapeake, most WildHorse Resource Development Corporation executives and employees were terminated. These executives and employees were 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.

(c)	For the three months ending March 31, 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. The effective tax rate for the quarter ended March 31, 2019 was 93.7%. Further, no income tax expense or benefit is shown for the adjustments being made to arrive at adjusted net income (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.

(d)	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.

(e)	No income tax effect from the adjustments has been included in determining adjusted net income for the three months ended March 31, 2018. Our effective tax rate was 0% due to our valuation allowance position.

CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF CASH PROVIDED BY OPERATING ACTIVITIES TO ADJUSTED EBITDAX ($ in millions) (unaudited)
	Three Months Ended March 31, 2019
	Under Full Cost		Successful Efforts Adjustments		As Reported

CASH PROVIDED BY OPERATING ACTIVITIES (GAAP)	$	502	$	(46)	$	456
Changes in assets and liabilities	78		15		93
Interest expense	135		26		161
Exploration expense	—		6		6
Stock-based compensation	(6)		—		(6)
Losses on investments	(1)		—		(1)
Net income attributable to noncontrolling interest	(1)		1		—
Other revenue (VPP deferred revenue)	—		(15)		(15)
Other items	(19)		1		(18)
Adjusted EBITDAX (Non-GAAP)^(a)	$	688	$	(12)	$	676


	Three Months Ended March 31, 2018
	Under Full Cost		Successful Efforts Adjustments		As Reported

CASH PROVIDED BY OPERATING ACTIVITIES (GAAP)	$	656	$	(68)	$	588
Changes in assets and liabilities	(104)		16		(88)
Interest expense	123		39		162
Exploration expense	—		13		13
Stock-based compensation	(9)		—		(9)
Restructuring and other termination costs	38		—		38
Provision for legal contingencies, net	5		—		5
Net income attributable to noncontrolling interest	(1)		—		(1)
Other revenue (VPP deferred revenue)	—		(16)		(16)
Other items	25		—		25
Adjusted EBITDAX (Non-GAAP)^(a)	$	733	$	(16)	$	717


(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 operations 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 operations 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, 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 March 31, 2019
	Under Full Cost		Successful Efforts Adjustments		As Reported
NET INCOME (LOSS) (GAAP)	$	180	$	(201)	$	(21)

Adjustments:
Interest expense	135		26		161
Income tax benefit	(314)		—		(314)
Depreciation, depletion and amortization	357		162		519
Exploration expense	—		24		24
Unrealized losses on oil, natural gas and NGL derivatives	281		—		281
Gains on sales of assets	—		(19)		(19)
Other operating expense	51		10		61
Impairments	1		—		1
Losses on investments	1		—		1
Net income attributable to noncontrolling interests	(1)		1		—
Other revenue (VPP deferred revenue)	—		(15)		(15)
Other	(3)		—		(3)
Adjusted EBITDAX (Non-GAAP)^(a)	$	688	$	(12)	$	676


	Three Months Ended March 31, 2018
	Under Full Cost		Successful Efforts Adjustments		As Reported
NET INCOME (GAAP)	$	294	$	(276)	$	18

Adjustments:
Interest expense	123		39		162
Depreciation, depletion and amortization	286		173		459
Exploration expense	—		81		81
Unrealized losses on oil, natural gas and NGL derivatives	119		—		119
Restructuring and other termination costs	38		—		38
Provision for legal contingencies, net	5		—		5
Gains on sales of assets	—		(19)		(19)
Other operating expense	8		(8)		—
Impairments	—		10		10
Gains on investments	(139)		—		(139)
Net income attributable to noncontrolling interests	(1)		—		(1)
Other revenue (VPP deferred revenue)	—		(16)		(16)
Adjusted EBITDAX (Non-GAAP)^(a)	$	733	$	(16)	$	717


(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 MAY 8, 2019

Chesapeake periodically provides guidance on certain factors that affect the company's future financial performance. New information or changes from the company's February 27, 2019 outlook are italicized bold below.

	Year Ending 12/31/2019	Successful Effort Adjustments	Other Adjustments	Year Ending 12/31/2019 Revised
Absolute Production:
Oil - mmbbls	42.5 - 44.5			42.5 - 44.5
NGL - mmbbls	13.0 - 15.0			13.0 - 15.0
Natural gas - bcf	710 - 750			710 - 750
Total absolute production - mmboe	174 - 184			174 - 184
Absolute daily rate - mboe	475 - 505			475 - 505
Estimated Realized Hedging Effects^(a) (based on 5/3/19 strip prices):
*Oil - $/bbl*	($0.17)		($0.76)	($0.93)
*Natural gas - $/mcf*	($0.07)		$0.10	$0.03
Estimated Basis to NYMEX Prices:
*Oil - $/bbl*	$1.20 - $1.60		$0.40	*$1.60 - $2.00*
Natural gas - $/mcf	($0.10) - ($0.20)			($0.10) - ($0.20)
NGL - realizations as a % of WTI	33% - 36%			33% - 36%
Operating Costs per Boe of Projected Production:
Production expense	$3.25 - $3.50			$3.25 - $3.50
Gathering, processing and transportation expenses	$6.00 - $6.50			$6.00 - $6.50
Oil - $/bbl	$3.35 - $3.55			$3.35 - $3.55
Natural Gas - $/mcf	$1.20 - $1.30			$1.20 - $1.30
*Production taxes*	$0.75 - $0.85		$0.05	*$0.80 - $0.90*
*General and administrative^(b)*	$1.50 - $1.60	$0.25		*$1.75 - $1.85*
Stock-based compensation (non-cash)	$0.10 - $0.20			$0.10 - $0.20
*Marketing Net Margin and Other ($ in millions)^(c)*	($25) - ($45)		$10	*($15) - ($35)*
*Adjusted EBITDAX, based on 5/3/19 strip prices ($ in millions)^(d)*	$2,500 - $2,700	($45)	$95	*$2,550 - $2,750*
*Depreciation, depletion and amortization expense*	$5.50 - $6.50	$6.00		*$11.50 - $12.50*
Depreciation of other assets	$0.40 - $0.50			$0.40 - $0.50
*Interest expense*	$3.20 - $3.40	$0.60		*$3.80 - $4.00*
*Exploration expense ($ in millions, cash only)*		$45		*$40 - $50*
Book Tax Rate	0%			0%
*Capital Expenditures ($ in millions)^(e)*	$2,175 - $2,375	($90)		*$2,085 - $2,285*
*Capitalized Interest ($ in millions)*	$125	$(105)		$20
*Total Capital Expenditures ($ in millions)*	$2,300 - $2,500			*$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 and $58.6 million in deferred revenue related to VPP9.

(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 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 EBITDAX 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 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, 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 May 3, 2019, including April and May derivative contracts that have settled, approximately 70% of the company's 2019 forecasted oil, natural gas and NGL production revenue was hedged, including approximately 70% and 80% of its remaining 2019 forecasted oil and natural gas production at average prices of $58.75 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 $60.10 per bbl and on a portion of its 2020 gas production at an average price of $2.75 per mcf.

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

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

Q2 2019	5	$	57.09
Q3 2019	6	$	60.22
Q4 2019	6	$	60.30
Total 2019	17	$	59.38

Total 2020	11	$	59.32

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

Q2 2019	1	$	58.00	$	67.75
Q3 2019	2	$	58.00	$	67.75
Q4 2019	1	$	58.00	$	67.75
Total 2019	4	$	58.00	$	67.75

Total 2020	2	$	65.00	$	83.25

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

Q2 2019	221	$	52.63
Q3 2019	587	$	54.14
Q4 2019	832	$	54.43
Total 2019	1,640	$	54.08

Oil Swaptions
	Volume (mmbbls)	Avg. NYMEX Strike Price

Total 2020	4	$	62.45

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

Q2 2019	3	$	5.71
Q3 2019	2	$	5.67
Q4 2019	1	$	5.67
Total 2019	6	$	5.69

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

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

Q2 2019	119	$	2.84
Q3 2019	115	$	2.84
Q4 2019	110	$	2.84
Total 2019	344	$	2.84

Total 2020	250	$	2.75

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

Q2 2019	9	$	2.75	$	2.91
Q3 2019	10	$	2.75	$	2.91
Q4 2019	9	$	2.75	$	2.91
Total 2019	28	$	2.75	$	2.91

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

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	66	$	2.50	$	2.80	$	3.10

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

Q2 2019	6	$	12.00
Q3 2019	6	$	12.00
Q4 2019	5	$	12.00
Total 2019	17	$	12.00

Total 2020	22	$	12.00

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

Total 2020	106	$	2.77

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

Q2 2019	17	$	(0.84)
Q3 2019	15	$	(0.45)
Q4 2019	6	$	(0.39)
Total 2019	38	$	(0.62)

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