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
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 Under Full Cost
Successful Efforts
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 $543 million in the 2018 first quarter. The increase in capital expenditures in the 2019 first quarter was largely attributable to a higher average rig count and an increase in gross wells spud, completed and connected. A summary is provided in the table below.
Three Months Ended
March 31,
2019 2018
Net Gross Net Gross
Operated
activity
comparison
Average
rig
count 12 20 10 15
Wells
spud 53 79 53 77
Wells
completed 60 83 56 76
Wells
connected 60 83 44 57
Three Months Ended March 31, 2019
Under Successful As Reported
Full Cost Efforts
Adjustments
Type of cost ($ 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 Successful As Reported
Full Cost Efforts
Adjustments
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
$/bbl mmcf
$/mcf mbbl
$/bbl mboe %
$/boe
per day per day per day per day
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
$/bbl mmcf
$/mcf mbbl
$/bbl mboe %
$/boe
per day per day per day per day
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
Gordon Pennoyer
(405) 935-8870
(405) 935-8878
ir@chk.com
media@chk.com
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ in millions except per share data)
(unaudited)
Three Months Ended
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 Successful As
Full Cost Efforts Reported
Adjustments
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 Successful As
Full Cost Efforts Reported
Adjustments
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 Successful As
Full Cost Efforts Reported
Adjustments
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 Successful As
Full Cost Efforts Reported
Adjustments
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 Successful As
Full Cost Efforts Reported
Adjustments
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 Successful As
Full Cost Efforts Reported
Adjustments
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 Successful As
Full Cost Efforts Reported
Adjustments
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 Successful As
Full Cost Efforts Reported
Adjustments
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
Successful
Other
Year Ending
Effort Adjustments
12/31/2019 Adjustments
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 Avg. NYMEX
(mmbbls) 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 Avg. NYMEX Avg. NYMEX
Bought Put Price Sold Call Price
(mmbbls)
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 Avg. NYMEX
(mbbls) 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 Avg. NYMEX
(mmbbls) Strike Price
Total 2020 4 $
62.45
Oil Basis Protection Swaps
Volume Avg. NYMEX
(mmbbls) 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 Avg. NYMEX
(bcf) 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 Avg. NYMEX Avg. NYMEX
Bought Put Price Sold Call Price
(bcf)
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 Avg. Avg. Avg.
NYMEX NYMEX NYMEX
(bcf) Sold Put Bought Put Sold
Price Price 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 Avg. NYMEX
(bcf) 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 Avg. NYMEX
(bcf) Strike Price
Total 2020 106 $
2.77
Natural Gas Basis Protection Swaps
Volume Avg. NYMEX
plus/(minus)
(bcf)
Q2 2019 17 $
(0.84)
Q3 2019 15 $
(0.45)
Q4 2019 6 $
(0.39)
Total 2019 38 $
(0.62)
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SOURCE Chesapeake Energy Corporation
