Chesapeake Energy Corporation Reports 2019 Third Quarter Financial And Operational Results, Maintains 2019 Guidance And Announces Plans To Reduce 2020 Capital Budget
OKLAHOMA CITY, Nov. 5, 2019 /PRNewswire/ -- Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operational results for the 2019 third quarter. Highlights include:
-- Maintaining 2019 Production and Capital Expenditure Guidance:
-- 2019 fourth quarter oil production projected to increase
approximately 10% over 2019 third quarter levels
-- Brazos Valley sets net average oil production record of
approximately 40,000 barrels (bbls) of oil per day for the month of
October 2019; continue to deliver capital and operating costs ahead
of projected synergies
-- Powder River Basin (PRB) Turner well costs down approximately 10%
year to date; first Niobrara well drilled and completed since 2014
produces more than 100,000 bbls of oil in first 87 days
-- Continuing Progress on Prudently Managing Balance Sheet and Cash Costs:
-- Recently re-affirmed borrowing base of Chesapeake credit facility
-- Exchanged $693 million of Senior Notes and $40 million of preferred
shares for 319 million common shares at an average discount of
approximately 25%, reducing annual interest and preferred dividend
payments
-- Restructured gas gathering and crude oil transportation contracts in
South Texas and Brazos Valley, improving future returns
-- Reducing 2020 Capital Expenditure Forecast by Approximately 30%,
Targeting Free Cash Flow:
-- Anticipate flat oil production year over year, utilizing 10 to 13
rigs with projected total capital expenditures of approximately $1.3
to $1.6 billion, contingent upon commodity prices
-- Expect to reduce 2020 production and general and administrative
(G&A) expenses by approximately 10%
Doug Lawler, Chesapeake's President and Chief Executive Officer, commented, "We are pleased with our execution this quarter as we continue to successfully integrate and realize value from our Brazos Valley acquisition and maximize cash flow from our oil assets while reducing capital directed to our natural gas assets. We expect our oil production to grow approximately 10% in the fourth quarter, compared to the third quarter, and we remain on track to meet our 2019 total production and capital expenditure guidance. Our capital efficiency improvements, expected reduction in cash costs and anticipated capital plan position us to target free cash flow in 2020."
2019 Third Quarter Results
For the 2019 third quarter, Chesapeake reported a net loss of $61 million and a net loss available to common stockholders of $101 million, or $0.06 per diluted share. Adjusting for items typically excluded by securities analysts, the 2019 third quarter adjusted net loss attributable to Chesapeake was $188 million, or $0.11 per share, while adjusted EBITDAX was $577 million. Reconciliations of financial measures calculated in accordance with GAAP to non-GAAP measures are provided on pages 16 - 20 of this release.
Average daily production for the 2019 third quarter was approximately 478,000 barrels of oil equivalent (boe), representing year-over-year growth of 3% adjusted for asset purchases and sales, and consisted of approximately 115,000 bbls of oil, 1.989 billion cubic feet (bcf) of natural gas and 32,000 bbls of natural gas liquids (NGL). Average daily production for the 2018 third quarter was approximately 537,000 boe and consisted of approximately 89,000 bbls of oil, 2.332 bcf of natural gas and 59,000 bbls of NGL. Oil production represented approximately 24% of the company's 2019 third quarter aggregate production, compared to 17% in the 2018 third quarter.
Despite lower average prices for our oil, natural gas and NGL sold, Chesapeake's operating margin remained flat in the 2019 third quarter, compared to the 2018 third quarter, due to an increase in oil production mix and a decrease in cash costs. Gathering, processing and transportation and G&A expenses decreased by $109 million, or approximately $1.39 per boe, while production expense increased $23 million, or $0.86 per boe, when compared to the same quarter in 2018.
Capital Spending Overview
Chesapeake invested total capital expenditures of approximately $640 million during the 2019 third quarter, including capitalized interest of $6 million, compared to approximately $551 million in the 2018 third quarter. The increase in capital expenditures in the 2019 third quarter was largely attributable to an increase in net wells spud, completed and connected. See tables below for a summary of activity and expenditures.
Three Months Ended
September 30,
2019 2018
Net Gross Net Gross
Operated
activity
comparison
Average
rig
count 13 17 11 19
Wells
spud 63 87 49 84
Wells
completed 83 117 59 81
Wells
connected 83 118 53 75
Three Months Ended
September 30,
2019 2018*
Type of cost
($ in
millions)
Drilling and
completion
capital
expenditures $
613 $
531
Leasehold and
additions to
other PP&E 21 16
Subtotal
capital
expenditures $
634 $
547
Capitalized
interest 6 4
Total capital
expenditures $
640 $
551
* Financial information for 2018
has been recast to reflect the
retrospective application of
the successful efforts method
of accounting.
Balance Sheet and Liquidity
As of September 30, 2019, Chesapeake's principal amount of debt outstanding inclusive of Brazos Valley debt was approximately $9.732 billion, compared to $8.168 billion as of December 31, 2018. As of September 30, 2019, the company had borrowed $1.504 billion under the $3.0 billion Chesapeake credit facility, utilized approximately $53 million for various letters of credit, and had additional borrowing capacity of approximately $1.443 billion. Under the $1.3 billion Brazos Valley credit facility, the company had borrowed $900 million and had additional borrowing capacity of approximately $400 million. The borrowing base of the Chesapeake credit facility was re-affirmed in November 2019 and the redetermination process for the Brazos Valley credit facility is scheduled for the 2019 fourth quarter.
During the 2019 third quarter, Chesapeake exchanged approximately 319 million common shares for various series of Senior Notes and preferred shares totaling a principal amount of approximately $733 million. The company expects approximately $45 million in interest savings in 2020 as a result of these transactions. The company believes these transactions, together with its planned reduction in capital expenditures in 2020 and other efficiency measures, will reduce its debt levels and improve the ratios under the covenants in the company's revolving credit facility.
As of October 31, 2019, including October and November derivative contracts that have settled, approximately 80% of the company's remaining 2019 forecasted oil, natural gas and NGL production revenue was hedged, including approximately 74% and 75% of its remaining 2019 forecasted oil and natural gas production at average prices of $59.34 per bbl and $2.83 per thousand cubic feet (mcf), respectively. Additionally, Chesapeake has basis protection swaps on approximately 2 million barrels (mmbbls) of its remaining projected 2019 Eagle Ford oil production at a premium to WTI of approximately $5.67 per bbl.
In 2020, Chesapeake currently has downside protection on a portion of its 2020 projected oil production at an average price of $59.28 per bbl and on a portion of its 2020 projected gas production at an average price of $2.76 per mcf.
Operations Update and Highlights
Chesapeake's average daily production for the 2019 third quarter was approximately 478,000 boe compared to approximately 537,000 boe in the 2018 third quarter. The following tables show average daily production and average sales prices received (excluding gains/losses on derivatives) by the company's operating areas for the 2019 and 2018 third quarters.
Three Months Ended September 30, 2019
Oil Natural Gas NGL
Total
mbbl
$/bbl mmcf
$/mcf mbbl
$/bbl mboe %
$/boe
per day per day per day per day
Marcellus 928 1.85 154 32 11.11
Haynesville 694 2.03 116 24 12.17
Eagle Ford 51 60.13 161 2.13 16 14.24 94 20 38.62
Brazos Valley 36 58.23 62 1.70 6 8.84 53 11 43.07
Powder River
Basin 20 54.17 86 1.96 5 11.49 39 8 33.09
Mid-Continent 8 55.24 57 1.63 5 12.06 22 5 26.26
Retained
assets(a) 115 58.18 1,988 1.93 32 12.44 478 100 22.79
Divested assets
Total 115 58.18 1,989 1.93 32 12.44 478 100
% 22.79
Three Months Ended September 30, 2018
Oil Natural Gas NGL
Total
mbbl
$/bbl mmcf
$/mcf mbbl
$/bbl mboe %
$/boe
per day per day per day per day
Marcellus 812 2.46 135 25 14.77
Haynesville 769 2.74 128 24 16.44
Eagle Ford 58 74.38 121 3.26 21 28.94 100 19 53.48
Powder River
Basin 12 69.24 73 2.50 5 27.89 29 5 39.76
Mid-Continent 9 69.76 60 2.50 4 29.73 23 4 38.64
Retained
assets(a) 79 73.07 1,835 2.63 30 28.86 415 77 27.66
Divested assets 10 67.02 497 2.91 29 29.34 122 23 24.38
Total 89 72.39 2,332 2.69 59 29.09 537 100
% 26.92
(a) Includes assets retained as
of September 30, 2019.
Brazos Valley: Sets new production record
In Chesapeake's Brazos Valley area in central Texas, the company is currently utilizing four rigs and placed 25 wells on production during the 2019 third quarter, 14 of which were placed on production in the last five weeks of the quarter. As a result, the company set a new net oil production record for the month of October 2019 of approximately 40,000 bbls of oil per day, exceeding the monthly production record set by the previous operator in November 2018 while utilizing five rigs. The increase was also driven by improvements to the field's base decline through its well optimization and workover program.
As the company's subsurface understanding evolves, the commercial black oil area of the field continues to expand, further strengthening the inventory of the future drilling program. Since February 1, 2019, the company has placed 13 wells on production which have reached peak 24-hour rates of more than 1,000 bbls of oil per day. The company anticipates placing 20 wells on production in the 2019 fourth quarter.
Chesapeake continues to improve operational efficiencies in its Brazos Valley development program, resulting in a 21% decrease in completed well costs to approximately $830 per foot, and extending its average completed lateral length per well drilled to more than 9,000 feet.
Eagle Ford Shale: Gas gathering and crude oil transportation restructuring provides improved long term field economics, production anticipated to ramp in the fourth quarter
In the company's South Texas Eagle Ford asset, 2019 third quarter volumes were projected to represent the low for the year primarily due to timing of the company's development plan and longer cleanup periods associated with that development. Of the 47 wells Chesapeake placed on production during the 2019 third quarter, 46 were put to sales in August and September. The company is currently running four rigs in South Texas and anticipates placing 41 wells on production in the 2019 fourth quarter.
Additionally, Chesapeake continues to optimize its midstream and downstream commitments and has recently successfully restructured its gas gathering and crude transportation commitments in the Eagle Ford. These agreements allow the company to move away from a cost-of-service mechanism to fixed-fee gathering rate structures, as well as maximize its pipeline commitments going forward.
Powder River Basin: Turner capital efficiency continues to advance and first Niobrara well drilled since 2014 delivers record results
Chesapeake continues to recognize operational efficiencies in the Turner sandstone formation which have driven costs out of its operations, including reductions in cycle times by 25% year over year and in average drilling and completion costs by approximately $800,000, or 10%, per well through the first nine months of 2019 compared to 2018 results. These efficiency enhancements have resulted in a recent four-well Turner pad being drilled and completed for approximately $6.0 million per well, with the last 25 wells turned to sales averaging approximately $7.2 million per well.
While the Turner sandstone formation has been Chesapeake's primary focus in its PRB development program, the company remains enthusiastic about the stacked pay potential in the basin. The company recently placed on production its first Niobrara well since 2014, and in the first 87 days it has produced approximately 106,500 bbls of oil, reaching a 24-hour peak rate of greater than 1,600 bbls of oil per day. The company currently plans to drill and complete four additional Niobrara wells in 2019 and expects that more than 25% of its projected 2020 capital program will be targeting the Niobrara formation. The company is currently utilizing four rigs in the PRB, placed 26 wells on production in the 2019 third quarter and anticipates placing 17 wells on production in the 2019 fourth quarter.
Production volumes in the 2019 third quarter were less than expected, primarily driven by the impact from a group of nine wells placed on production earlier in the year in the northern edge of Chesapeake's Turner acreage. These isolated wells encountered poorer reservoir quality, resulting in lower than expected performance compared to other company-operated wells in the rest of the field. Production volumes were also negatively impacted by unplanned outages due to electrical power issues that interrupted portions of the field's midstream system. The company is working with local utility companies and its midstream partners to ensure reliable power to support all production, gathering and transportation systems.
Marcellus Shale: Recent well performance highlights capital efficiency gains
In the Marcellus Shale, the company continues its strategy of maintaining its operated production to capture the value from seasonal basin congestion and pricing, while achieving lower costs and capital requirements due to the strong performance of recent wells. Wider spacing averaging approximately 1,350 feet between well bores, fit-for-purpose modern completions and improved cycle times continue to yield impressive results for Chesapeake in the Marcellus Shale, with six wells recently turned to sales reaching peak 24-hour flow rates between 60 million cubic feet (mmcf) of gas per day to a record 85 mmcf per day. The company is currently utilizing two rigs in the Marcellus, placed 17 wells on production in the 2019 third quarter and anticipates placing four wells on production in the 2019 fourth quarter.
Haynesville Shale, Mid-Continent: Allocating capital to higher-return areas in 2020
In the Haynesville Shale in Louisiana, Chesapeake placed five wells on production during the 2019 third quarter. The company has released its operated rigs and completion crews in both the Haynesville Shale and Mid-Continent areas for the rest of the year.
Key Financial and Operational Results
The table below summarizes Chesapeake's key financial and operational results during the 2019 third quarter as compared to results in the same quarter in 2018. The three months ended September 30, 2019 include Brazos Valley operations. The three months ended September 30, 2018 do not include Brazos Valley operations.
Three Months Ended
September 30,
2019 2018*
Barrels of oil
equivalent
production (in
mboe) 43,991 49,413
Barrels of oil
equivalent
production (mboe/
d) 478 537
Oil production (in
mbbl/d) 115 89
Average realized
oil price
($/bbl)(a) 60.66 58.77
Natural gas
production (in
mmcf/d) 1,989 2,332
Average realized
natural gas price
($/mcf)(a) 2.38 2.69
NGL production (in
mbbl/d) 32 59
Average realized
NGL price
($/bbl)(a) 12.44 27.37
Production
expenses ($/boe) 3.54 2.68
Gathering,
processing and
transportation
expenses ($/boe) 6.12 7.36
Oil -($/bbl) 3.53 3.83
Natural Gas -
($/mcf) 1.19 1.33
NGL -($/bbl) 5.19 8.59
Production taxes
($/boe) 0.79 0.69
Exploration
expenses ($ in
millions) 17 22
General and
administrative
expenses
($/boe)(b) 1.35 1.51
General and
administrative
expenses (stock-
based
compensation)
(non-cash)
($/boe) 0.13 0.12
Depreciation,
depletion, and
amortization
($/boe) 13.04 8.20
Interest expense
($/boe)(c) 3.99 3.32
Marketing net
margin ($ in
millions)(d) (13) (14)
Net cash provided
by operating
activities ($ in
millions) 329 444
Net cash provided
by operating
activities
($/boe) 7.48 8.99
Net loss ($ in
millions) (61) (146)
Net loss available
to common
stockholders ($
in millions) (101) (169)
Net loss per share
available to
common
stockholders -
diluted ($) (0.06) (0.19)
Adjusted EBITDAX
($ in
millions)(e) 577 584
Adjusted EBITDAX
($/boe) 13.12 11.82
Adjusted net loss
attributable to
Chesapeake ($ in
millions)(f) (188) (8)
Adjusted net loss
attributable to
Chesapeake per
share -diluted
($)(g) (0.11) (0.01)
* Financial information for 2018
has been recast to reflect the
retrospective application of
the successful efforts method
of accounting.
(a) Includes the effects of realized
gains (losses) from hedging, but
excludes the effects of unrealized
gains (losses) from hedging.
(b) Excludes expenses associated with
stock-based compensation, which
are recorded in general and
administrative expenses in
Chesapeake's Condensed Consolidated
Statement of Operations.
(c) Includes the effects of realized
(gains) losses from interest rate
derivatives, excludes the effects
of unrealized (gains) losses from
interest rate derivatives and is
shown net of amounts capitalized.
(d) Marketing net margin is marketing
gross margin of ($12) million and
($19) million for the three months
ended September 30, 2019 and 2018,
excluding non-cash amortization of
($1) million and $5 million,
respectively, related to the buy
down of a transportation agreement.
(e) Defined as net income (loss) before
interest expense, income taxes,
depreciation, depletion and
amortization expense, and
exploration expense, as adjusted to
remove the effects of certain items
detailed in the Reconciliation of
Net Income (Loss) to Adjusted
EBITDAX. This is a non-GAAP
measure.
(f) Defined as net income (loss)
attributable to Chesapeake, as
adjusted to remove the effects of
certain items detailed in the
Reconciliation of Adjusted Net
Income (Loss) Attributable to
Chesapeake. This is a non-GAAP
measure.
(g) Our presentation of diluted adjusted
net loss attributable to Chesapeake
per share excludes 183 million and
208 million shares for the three
months ended September 30, 2019 and
2018, respectively, which are
considered antidilutive when
calculating diluted earnings per
share.
2019 Third Quarter Financial and Operational Results Conference Call Update
The conference call to discuss the company's financial and operational results has been scheduled on Tuesday, November 5 at 9:00 am EDT. The telephone number to access the conference call is 1-888-317-6003 or 1-412-317-6061 for international callers. The passcode for the call is 2440889. The conference call will be webcast and can be found at www.chk.com in the "Investors" section of the company's website.
Headquartered in Oklahoma City, Chesapeake Energy Corporation's (NYSE: CHK) operations are focused on discovering and developing its large and geographically diverse resource base of unconventional oil and natural gas assets onshore in the United States.
This news release and the accompanying outlook include "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are statements other than statements of historical fact. They include statements that give our current expectations, management's outlook guidance or forecasts of future events, cost-cutting measures, reductions in expenditures, proposed refinancing transactions, capital exchange transactions, asset divestitures, reductions in capital expenditures, operational efficiencies, production and well connection forecasts, estimates of operating costs, anticipated capital and operational efficiencies, planned development drilling and expected drilling cost reductions, expected lateral lengths of wells, anticipated timing and number of wells to be placed into production, expected oil growth trajectory, anticipated timing of execution of new gathering agreement, expected savings in connection with new oil gathering and pipeline agreements, projected capital expenditures, projected cash flow and liquidity, our ability to enhance our cash flow and financial flexibility, plans and objectives for future operations, the ability of our employees, portfolio strength and operational leadership to create long-term value, and the assumptions on which such statements are based. Although we believe the expectations and forecasts reflected in the forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate or changed assumptions or by known or unknown risks and uncertainties.
Factors that could cause actual results to differ materially from expected results include those described under "Risk Factors" in Item 1A of our annual report on Form 10-K and any updates to those factors set forth in Chesapeake's subsequent quarterly reports on Form 10-Q or current reports on Form 8-K (available at http://www.chk.com/investors/sec-filings). These risk factors include our ability to comply with the covenants under our revolving credit facilities and other indebtedness and the related impact on our ability to continue as a going concern, the volatility of oil, natural gas and NGL prices; the limitations our level of indebtedness may have on our financial flexibility; our inability to access the capital markets on favorable terms; the availability of cash flows from operations and other funds to finance reserve replacement costs or satisfy our debt obligations; downgrade in our credit rating requiring us to post more collateral under certain commercial arrangements; write-downs of our oil and natural gas asset carrying values due to low commodity prices; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and projecting future rates of production and the amount and timing of development expenditures; our ability to generate profits or achieve targeted results in drilling and well operations; leasehold terms expiring before production can be established; commodity derivative activities resulting in lower prices realized on oil, natural gas and NGL sales; the need to secure derivative liabilities and the inability of counterparties to satisfy their obligations; adverse developments or losses from pending or future litigation and regulatory proceedings, including royalty claims; charges incurred in response to market conditions and in connection with our ongoing actions to reduce financial leverage and complexity; drilling and operating risks and resulting liabilities; effects of environmental protection laws and regulation on our business; legislative and regulatory initiatives further regulating hydraulic fracturing; our need to secure adequate supplies of water for our drilling operations and to dispose of or recycle the water used; impacts of potential legislative and regulatory actions addressing climate change; federal and state tax proposals affecting our industry; potential OTC derivatives regulation limiting our ability to hedge against commodity price fluctuations; competition in the oil and gas exploration and production industry; a deterioration in general economic, business or industry conditions; negative public perceptions of our industry; limited control over properties we do not operate; pipeline and gathering system capacity constraints and transportation interruptions; terrorist activities and cyber-attacks adversely impacting our operations; an interruption in operations at our headquarters due to a catastrophic event; certain anti-takeover provisions that affect shareholder rights; and our inability to increase or maintain our liquidity through debt repurchases, capital exchanges, asset sales, joint ventures, farmouts or other means.
In addition, disclosures concerning the estimated contribution of derivative contracts to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility. Our production forecasts are also dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Expected asset sales may not be completed in the time frame anticipated or at all. We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this news release, and we undertake no obligation to update any of the information provided in this release or the accompanying Outlook, except as required by applicable law. In addition, this news release contains time-sensitive information that reflects management's best judgment only as of the date of this news release.
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ in millions except per share data)
(unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
2019 2018* 2019 2018*
REVENUES AND OTHER:
Oil, natural gas and NGL(a) $
1,170 $
1,199 $
3,553 $
3,424
Marketing 889 1,219 3,038 3,738
Total Revenues 2,059 2,418 6,591 7,162
Other 15 16 45 48
Gains (losses) on sales of assets 13 (10) 33 27
Total Revenues and Other 2,087 2,424 6,669 7,237
OPERATING EXPENSES:
Oil, natural gas and NGL production 155 132 453 417
Oil, natural gas and NGL gathering,
processing and transportation 270 364 815 1,060
Production taxes 35 34 109 91
Exploration 17 22 56 123
Marketing 901 1,238 3,071 3,798
General and administrative 66 81 258 273
Restructuring and other termination
costs 38
Provision for legal contingencies, net 8 3 17
Depreciation, depletion and amortization 573 405 1,672 1,335
Impairments 9 58 11 122
Other operating (income) expense 15 79 (1)
Total Operating Expenses 2,041 2,342 6,527 7,273
INCOME (LOSS) FROM OPERATIONS 46 82 142 (36)
OTHER INCOME (EXPENSE):
Interest expense (177) (165) (513) (482)
Gains (losses) on investments (4) (28) 139
Gains (losses) on purchases or exchanges
of debt 70 (68) 70 (68)
Other income 3 6 30 62
Total Other Expense (108) (227) (441) (349)
LOSS BEFORE INCOME TAXES (62) (145) (299) (385)
Income tax expense (benefit) (1) 1 (315) (8)
NET INCOME (LOSS) (61) (146) 16 (377)
Net income attributable to
noncontrolling interests (1)
NET INCOME (LOSS) ATTRIBUTABLE TO
CHESAPEAKE (61) (146) 16 (378)
Preferred stock dividends (23) (23) (69) (69)
Loss on exchange of preferred stock (17) (17)
NET LOSS AVAILABLE TO COMMON
STOCKHOLDERS $
(101) $
(169) $
(70) $
(447)
LOSS PER COMMON SHARE:
Basic $
(0.06) $
(0.19) $
(0.04) $
(0.49)
Diluted $
(0.06) $
(0.19) $
(0.04) $
(0.49)
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in
millions):
Basic 1,698 910 1,570 909
Diluted 1,698 910 1,570 909
* Financial information for 2018
has been recast to reflect the
retrospective application of
the successful efforts method
of accounting.
(a) See Supplemental Data -Oil,
Natural Gas and NGL Production and
Sales Prices for a reconciliation
of oil, natural gas and NGL
revenue before and after the
effect of financial derivatives.
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
($ in millions)
(unaudited)
September 30, December 31,
2019 2018
Cash and cash equivalents $
14 $
4
Other current assets 1,389 1,594
Total Current Assets 1,403 1,598
Property and equipment, net 14,876 10,818
Other long-term assets 300 319
Total Assets $
16,579 $
12,735
Current liabilities $
2,348 $
2,887
Long-term debt, net 9,133 7,341
Other long-term liabilities 363 374
Total Liabilities 11,844 10,602
Preferred stock 1,631 1,671
Noncontrolling interests 39 41
Common stock and other
stockholders' equity 3,065 421
Total Equity 4,735 2,133
Total Liabilities and Equity $
16,579 $
12,735
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
($ in millions)
(unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
2019 2018* 2019 2018*
Beginning cash and cash equivalents $
4 $
3 $
4 $
5
Net cash provided by operating
activities 329 444 1,182 1,395
Cash flows from investing
activities:
Drilling and completion costs(a) (570) (479) (1,640) (1,407)
Business combination, net (353)
Acquisitions of proved and unproved
properties (14) (16) (31) (118)
Proceeds from divestitures of
proved and unproved properties 28 11 110 395
Additions to other property and
equipment (9) (6) (27) (11)
Proceeds from sales of other
property and equipment 2 1 6 75
Proceeds from sales of investments 74
Net cash used in investing
activities (563) (489) (1,935) (992)
Net cash provided by (used in)
financing activities 244 46 763 (404)
Change in cash and cash equivalents 10 1 10 (1)
Ending cash and cash equivalents $
14 $
4 $
14 $
4
* Financial information for 2018
has been recast to reflect the
retrospective application of
the successful efforts method
of accounting.
(a) Includes capitalized interest of $6
million and $4 million for the
three months ended September 30,
2019 and 2018, respectively, and
includes capitalized interest of
$19 million and $13 million for the
nine months ended September 30,
2019 and 2018, respectively.
CHESAPEAKE ENERGY CORPORATION
SUPPLEMENTAL DATA - OIL, NATURAL GAS AND NGL PRODUCTION AND SALES PRICES
(unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
---
2019 2018 2019 2018
---
Net Production:
Oil (mmbbl) 10 9 31 25
Natural gas (bcf) 183 215 550 647
NGL (mmbbl) 3 5 10 15
Oil equivalent (mmboe) 44 49 133 148
Average daily production
(mboe) 478 537 486 540
Oil, Natural Gas and NGL Sales ($ in
millions):
Oil sales $
613 $
594 $
1,879 $
1,698
Natural gas sales 353 578 1,384 1,822
NGL sales 37 159 149 404
Total oil, natural gas
and NGL sales $
1,003 $
1,331 $
3,412 $
3,924
Financial Derivatives:
Oil derivatives -
realized gains
(losses)(a) $
26 $
(112) $
18 $
(273)
Natural gas derivatives -
realized gains
(losses)(a) 83 (1) 71 83
NGL derivatives -
realized losses(a) - (10) (14)
Total realized gains
(losses) on financial
derivatives $
109 $
(123) $
89 $
(204)
Oil derivatives -
unrealized gains
(losses)(b) $
98 $
12 $
(67) $
(115)
Natural gas derivatives -
unrealized gains
(losses)(b) (40) (17) 119 (168)
NGL derivatives -
unrealized losses(b) - (4) (13)
Total unrealized gains
(losses) on financial
derivatives $
58 $
(9) $
52 $
(296)
Total financial
derivatives $
167 $
(132) $
141 $
(500)
Total oil, natural gas
and NGL sales $
1,170 $
1,199 $
3,553 $
3,424
Average Sales Price (excluding gains
(losses) on derivatives):
Oil ($ per bbl) $
58.18 $
72.39 $
59.78 $
68.63
Natural gas ($ per mcf) $
1.93 $
2.69 $
2.51 $
2.82
NGL ($ per bbl) $
12.44 $
29.09 $
15.50 $
26.87
Oil equivalent ($ per
boe) $
22.79 $
26.92 $
25.70 $
26.59
Average Sales Price (excluding
unrealized gains (losses) on
derivatives):
Oil ($ per bbl) $
60.66 $
58.77 $
60.37 $
57.61
Natural gas ($ per mcf) $
2.38 $
2.69 $
2.64 $
2.94
NGL ($ per bbl) $
12.44 $
27.37 $
15.50 $
25.96
Oil equivalent ($ per
boe) $
25.26 $
24.44 $
26.37 $
25.21
(a) Realized gains (losses) include
the following items: (i)
settlements and accruals for
settlements of undesignated
derivatives related to current
period production revenues, (ii)
prior period settlements for
option premiums and for early-
terminated derivatives originally
scheduled to settle against
current period production
revenues, and (iii) gains
(losses) related to de-
designated cash flow hedges
originally designated to settle
against current period production
revenues. Although we no longer
designate our derivatives as cash
flow hedges for accounting
purposes, we believe these
definitions are useful to
management and investors in
determining the effectiveness of
our price risk management
program.
(b) Unrealized gains (losses) include
the change in fair value of open
derivatives scheduled to settle
against future period production
revenues offset by amounts
reclassified as realized gains
(losses) during the period.
Although we no longer designate
our derivatives as cash flow
hedges for accounting purposes,
we believe these definitions are
useful to management and
investors in determining the
effectiveness of our price risk
management program.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE
($ in millions)
(unaudited)
Three Months Ended September 30,
2019 2018
$
$/Share
$
$/Share
Net loss available to common
stockholders (GAAP) $
(101) $
(0.06) $
(169) $
(0.19)
Effect of dilutive securities
Diluted loss available to common
stockholders (GAAP)(a) $
(101) $
(0.06) $
(169) $
(0.19)
Adjustments:
Unrealized (gains) losses on oil,
natural gas and NGL derivatives (58) (0.03) 9 0.01
Provision for legal contingencies, net 8 0.01
(Gains) losses on sales of assets (13) (0.01) 10 0.01
Other operating expense 15 0.01
Impairments 9 0.01 58 0.06
Losses on investments 4
(Gains) losses on purchases or
exchanges of debt (70) (0.04) 68 0.08
Loss on exchange of preferred stock 17 0.01
Other revenue (15) (0.01) (16) (0.02)
Other 1 1
Income tax benefit(b)
Adjusted net loss available to common
stockholders(c) (Non-GAAP) (211) (0.12) (31) (0.04)
Preferred stock dividends 23 0.01 23 0.03
Total adjusted net loss attributable to
Chesapeake(a)(c) (Non-GAAP) $
(188) $
(0.11) $
(8) $
(0.01)
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE
($ in millions)
(unaudited)
Nine Months Ended September 30,
2019 2018
$
$/Share
$
$/Share
Net loss available to common
stockholders (GAAP) $
(70) $
(0.04) $
(447) $
(0.49)
Effect of dilutive securities
Diluted loss available to common
stockholders (GAAP)(d) $
(70) $
(0.04) $
(447) $
(0.49)
Adjustments:
Unrealized (gains) losses on oil,
natural gas and NGL derivatives (45) (0.03) 296 0.33
Restructuring and other termination
costs 38 0.04
Provision for legal contingencies, net 3 17 0.02
Gains on sales of assets (33) (0.02) (27) (0.03)
Other operating (income) expense(e) 79 0.05 (1)
Impairments 11 0.01 122 0.13
(Gains) losses on investments 28 0.02 (139) (0.15)
(Gains) losses on purchases or
exchanges of debt (70) (0.04) 68 0.07
Loss on exchange of preferred stock 17 0.01
Other revenue (45) (0.03) (48) (0.05)
Other (3) (60) (0.07)
Income tax benefit(f) (314) (0.20)
Adjusted net loss available to common
stockholders(c) (Non-GAAP) (442) (0.27) (181) (0.20)
Preferred stock dividends 69 0.04 69 0.08
Total adjusted net loss attributable to
Chesapeake(d)(c) (Non-GAAP) $
(373) $
(0.23) $
(112) $
(0.12)
(a) Our presentation
of diluted net
losses available
to common
stockholders per
share and diluted
adjusted net loss
per share
excludes 183
million and 208
million shares
considered
antidilutive for
the three months
ended September
30, 2019 and
2018. The number
of shares used
for the non-GAAP
calculation was
determined in a
manner consistent
with GAAP.
(b) No income tax
effect from the
adjustments has
been included in
determining
adjusted net
income for the
three months
ended September
30, 2019 and
2018. Our
effective tax
rate was 0% due
to our valuation
allowance
position.
(c) Adjusted net
income (loss)
available to
common
stockholders and
total adjusted
net income (loss)
attributable to
Chesapeake, both
in the aggregate
and per dilutive
share, are not
measures of
financial
performance under
GAAP, and should
not be considered
as an alternative
to, or more
meaningful than,
net income (loss)
available to
common
stockholders or
earnings (loss)
per share.
Adjusted net
income (loss)
available to
common
stockholders and
adjusted earnings
(loss) per share
exclude certain
items that
management
believes affect
the comparability
of operating
results. The
company believes
these adjusted
financial
measures are a
useful adjunct to
earnings
calculated in
accordance with
GAAP because:
(i) Management uses adjusted net
income (loss) available to
common stockholders to evaluate
the company's operational trends
and performance relative to
other oil and natural gas
producing companies.
(ii) Adjusted net income (loss)
available to common stockholders
is more comparable to earnings
estimates provided by securities
analysts.
(iii) Items excluded generally are one-
time items or items whose timing
or amount cannot be reasonably
estimated. Accordingly, any
guidance provided by the company
generally excludes information
regarding these types of items.
Because adjusted
net income (loss)
available to
common
stockholders and
total adjusted
net income (loss)
attributable to
Chesapeake
exclude some, but
not all, items
that affect net
income (loss)
available to
common
stockholders our
calculations of
adjusted net
income (loss)
available to
common
stockholders and
total adjusted
net income (loss)
attributable to
Chesapeake may
not be comparable
to similarly
titled measures
of other
companies.
(d) Our presentation
of diluted net
losses available
to common
stockholders per
share and diluted
adjusted net loss
per share
excludes 184
million and 207
million shares
considered
antidilutive for
the nine months
ended September
30, 2019 and
2018. The number
of shares used
for the non-GAAP
calculation was
determined in a
manner consistent
with GAAP.
(e) The nine months
ended September
30, 2019 includes
$34 million in
integration and
acquisition costs
as a result of
Chesapeake's
merger with
WildHorse
Resource
Development
Corporation
(WRD).
Additionally,
most WRD
executives and
employees were
terminated and
entitled to
severance
benefits of
approximately $38
million in
accordance with
certain
provisions of
existing
employment
agreements that
were triggered by
the change in
control.
(f) For the nine
months ended
September 30,
2019, we recorded
a net deferred
tax liability of
$314 million
associated with
the acquisition
of WildHorse
Resource
Development
Corporation. As a
result of
recording this
net deferred tax
liability through
business
combination
accounting, we
released a
corresponding
amount of the
valuation
allowance that we
maintain against
our net deferred
tax asset
position. This
release resulted
in an income tax
benefit of $314
million. Further,
no income tax
expense or
benefit is shown
for the
adjustments being
made to arrive at
adjusted net loss
available to
common
stockholders as a
result of not
recording an
income tax
expense or
benefit on
current period
results due to
maintaining a
full valuation
allowance against
our net deferred
tax asset
position.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF CASH PROVIDED BY OPERATING ACTIVITIES TO ADJUSTED EBITDAX
($ in millions)
(unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
2019 2018 2019 2018
CASH PROVIDED BY OPERATING
ACTIVITIES (GAAP) $
329 $
444 $
1,182 $
1,395
Adjustments:
Changes in assets and liabilities 77 (7) 214 (69)
Other revenue (15) (16) (45) (48)
Interest expense 177 165 513 482
Exploration 7 14 21 42
Income tax expense (1) 2 (1) 2
Stock-based compensation (7) (7) (24) (25)
Restructuring and other
termination costs 38
Losses on investments 6
Net income attributable to
noncontrolling interests (1)
Other items 10 (11) (1) 3
Adjusted EBITDAX (Non-GAAP)(a) $
577 $
584 $
1,865 $
1,819
(a) Adjusted EBITDAX
is not a measure
of financial
performance under
GAAP, and should
not be considered
as an alternative
to, or more
meaningful than,
cash flow
provided by
operating
activities
prepared in
accordance with
GAAP. Adjusted
EBITDAX excludes
certain items
that management
believes affect
the comparability
of operating
results. The
company believes
this non-GAAP
financial measure
is a useful
adjunct to cash
flow provided by
operating
activities
because:
(i) Management uses adjusted EBITDAX
to evaluate the company's
operational trends and
performance relative to other
oil and natural gas producing
companies.
(ii) Adjusted EBITDAX is more
comparable to estimates provided
by securities analysts.
(iii) Items excluded generally are one-
time items or items whose timing
or amount cannot be reasonably
estimated. Accordingly, any
guidance provided by the company
generally excludes information
regarding these types of items.
Because adjusted
EBITDAX excludes
some, but not
all, items that
affect net income
(loss), our
calculations of
adjusted EBITDAX
may not be
comparable to
similarly titled
measures of other
companies.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF NET INCOME (LOSS) TO ADJUSTED EBITDAX
($ in millions)
(unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
2019 2018 2019 2018
NET INCOME (LOSS) (GAAP) $
(61) $
(146) $
16 $
(377)
Adjustments:
Interest expense 177 165 513 482
Income tax expense (benefit) (1) 1 (315) (8)
Depreciation, depletion and
amortization 573 405 1,672 1,335
Exploration 17 22 56 123
Unrealized (gains) losses on oil,
natural gas and NGL derivatives (58) 9 (45) 296
Restructuring and other termination
costs 38
Provision for legal contingencies, net 8 3 17
(Gains) losses on sales of assets (13) 10 (33) (27)
Other operating (income) expense 15 79 (1)
Impairments 9 58 11 122
(Gains) losses on investments 4 28 (139)
(Gains) losses on purchases or
exchanges of debt (70) 68 (70) 68
Net (income) loss attributable to
noncontrolling interests (1)
Other revenue (15) (16) (45) (48)
Other (5) (61)
Adjusted EBITDAX (Non-GAAP)(a) $
577 $
584 $
1,865 $
1,819
(a) Adjusted EBITDAX
is not a measure
of financial
performance under
GAAP, and should
not be considered
as an alternative
to, or more
meaningful than,
net income (loss)
prepared in
accordance with
GAAP. Adjusted
EBITDAX excludes
certain items
that management
believes affect
the comparability
of operating
results. The
company believes
this non-GAAP
financial measure
is a useful
adjunct to net
income (loss)
because:
(i) Management uses adjusted EBITDAX
to evaluate the company's
operational trends and
performance relative to other
oil and natural gas producing
companies.
(ii) Adjusted EBITDAX is more
comparable to estimates provided
by securities analysts.
(iii) Items excluded generally are one-
time items or items whose timing
or amount cannot be reasonably
estimated. Accordingly, any
guidance provided by the company
generally excludes information
regarding these types of items.
Because adjusted
EBITDAX excludes
some, but not
all, items that
affect net income
(loss), our
calculations of
adjusted EBITDAX
may not be
comparable to
similarly titled
measures of other
companies.
CHESAPEAKE ENERGY CORPORATION
MANAGEMENT'S OUTLOOK AS OF NOVEMBER 5, 2019
Chesapeake periodically provides guidance on certain
factors that affect the company's future financial
performance. New information or changes from the
company's August 6, 2019 outlook are italicized bold
below.
Year Ending
12/31/2019
Absolute Production:
Oil - mmbbls
43.0 - 44.5
NGL - mmbbls
13.0 - 15.0
Natural gas -bcf
725 - 750
Total absolute production
-mmboe
177 - 184
Absolute daily rate -
mboe
484 - 505
Estimated Realized Hedging Effects(a) (based on
10/31/19 strip prices)
Oil -$/bbl $1.52
Natural gas -$/mcf $0.15
Estimated Basis to NYMEX Prices:
Oil -$/bbl
$1.85 - $2.05
Natural gas -$/mcf ($0.15) -($0.25)
NGL -realizations as a %
of WTI 25% - 28%
Operating Costs per boe of Projected Production:
Production expense
$3.20 - $3.40
Gathering, processing and
transportation expenses
$5.90 - $6.40
Oil - $/bbl
$2.95 - $3.15
Natural Gas -$/mcf
$1.20 - $1.30
Production taxes
$0.80 - $0.90
General and
administrative(b)
$1.75 - $1.85
Stock-based compensation
(non-cash)
$0.10 - $0.20
Marketing Net Margin and
Other ($ in millions)(c)
($15) - ($35)
Adjusted EBITDAX, based
on 10/31/19 strip prices
($ in millions)(d)
$2,400 - $2,600
Depreciation, depletion
and amortization expense
$12.50 - $13.50
Interest expense
$3.70 - $3.90
Exploration expense ($ in
millions, cash only)
$35 - $45
Book Tax Rate 0%
Capital Expenditures ($
in millions)(e)
$2,085 - $2,285
Capitalized Interest ($
in millions) $20
Total Capital
Expenditures ($ in
millions)
$2,105 - $2,305
(a) Includes expected settlements for
oil, natural gas and NGL
derivatives adjusted for option
premiums. For derivatives closed
early, settlements are reflected in
the period of original contract
expiration.
(b) Excludes expenses associated with
stock-based compensation, which
are recorded in general and
administrative expenses in
Chesapeake's Condensed Consolidated
Statement of Operations.
(c) Excludes non-cash amortization of
approximately $8.7 million related
to the buydown of a transportation
agreement.
(d) Adjusted EBITDAX is a non-GAAP
measure used by management to
evaluate the company's operational
trends and performance relative to
other oil and natural gas producing
companies. Adjusted EBITDAX
excludes certain items that
management believes affect the
comparability of operating results.
The most directly comparable GAAP
measure is net income (loss) but,
it is not possible, without
unreasonable efforts, to identify
the amount or significance of
events or transactions that may be
included in future GAAP net income
(loss) but that management does not
believe to be representative of
underlying business performance.
The company further believes that
providing estimates of the amounts
that would be required to reconcile
forecasted adjusted EBITDAX to
forecasted GAAP net income (loss)
would imply a degree of precision
that may be confusing or misleading
to investors. Items excluded from
net income to arrive at adjusted
EBITDAX include interest expense,
income taxes, and depreciation,
depletion and amortization expense,
exploration expense as well as one-
time items or items whose timing or
amount cannot be reasonably
estimated.
(e) Includes capital expenditures for
drilling and completion, leasehold,
developmental geological and
geophysical costs, rig termination
payments and other property, plant
and equipment. Excludes any
additional proved property
acquisitions and expenditures
classified as exploration expense.
Oil, Natural Gas and Natural Gas Liquids Hedging Activities
Chesapeake enters into oil, natural gas and NGL derivative transactions in order to mitigate a portion of its exposure to adverse changes in market prices. Please see the quarterly reports on Form 10-Q and annual reports on Form 10-K filed by Chesapeake with the SEC for detailed information about derivative instruments the company uses, its quarter-end derivative positions and accounting for oil, natural gas and natural gas liquids derivatives.
As of October 31, 2019, including October and November derivative contracts that have settled, approximately 80% of the company's 2019 forecasted oil, natural gas and NGL production revenue was hedged, including approximately 74% and 75% of its remaining 2019 forecasted oil and natural gas production at average prices of $59.34 per bbl and $2.83 per mcf, respectively.
In addition, the company had downside protection on a portion of its 2020 oil production at an average price of $59.28 per bbl and on a portion of its 2020 gas production at an average price of $2.76 per mcf.
The company's crude oil hedging positions were as follows:
Open Crude Oil Swaps
Volume Avg. NYMEX
(mmbbls) Price of Swaps
Q4 2019 7 $
60.24
Total 2019 7 $
60.24
Q1 2020 4 $
58.50
Q2 2020 4 $
58.57
Q3 2020 4 $
58.64
Q4 2020 3 $
58.71
Total 2020 15 $
58.60
Oil Two-Way Collars
Volume Avg. NYMEX Avg. NYMEX
Bought Put Sold Call
Price Price
(mmbbls)
Q4
2019 1 $
58.00 $
67.75
Total
2019 1 $
58.00 $
67.75
Q1
2020 0.5 $
65.00 $
83.25
Q2
2020 0.5 $
65.00 $
83.25
Q3
2020 0.5 $
65.00 $
83.25
Q4
2020 0.5 $
65.00 $
83.25
Total
2020 2 $
65.00 $
83.25
Oil Puts
Volume Avg. NYMEX
(mmbbls) Bought Put
Price
Q4 2019 1 $
54.43
Total 2019 1 $
54.43
Oil Swaptions
Volume Avg. NYMEX
(mmbbls) Strike Price
Q1 2020 1 $
63.15
Q2 2020 1 $
63.15
Total 2020 2 $
63.15
Oil Basis Protection Swaps
Volume Avg. NYMEX
(mmbbls) plus/(minus)
Q4 2019 2 $
5.67
Total 2019 2 $
5.67
Q1 2020 1 $
2.45
Q2 2020 1 $
2.45
Q3 2020 1 $
2.45
Q4 2020 2 $
2.45
Total 2020 5 $
2.45
The company's natural gas hedging positions were as follows:
Open Natural Gas Swaps
Volume Avg. NYMEX
(bcf) Price of
Swaps
Q4 2019 118 $
2.84
Total 2019 118 $
2.84
Q1 2020 66 $
2.76
Q2 2020 66 $
2.76
Q3 2020 67 $
2.76
Q4 2020 66 $
2.76
Total 2020 265 $
2.76
Natural Gas Two-Way Collars
Volume Avg. NYMEX Avg. NYMEX
Bought Put Sold Call
Price Price
(bcf)
Q4
2019 9 $
2.75 $
2.91
Total
2019 9 $
2.75 $
2.91
Natural Gas Three-Way Collars
Volume Avg. Avg. Avg.
NYMEX NYMEX NYMEX
(bcf) Sold Put Bought Put Sold Call
Price Price Price
Q4
2019 15 $
2.50 $
2.80 $
3.10
Total
2019 15 $
2.50 $
2.80 $
3.10
Natural Gas Net Written Call Options
Volume Avg. NYMEX
(bcf) Strike Price
Q4 2019 6 $
12.00
Total 2019 6 $
12.00
Q1 2020 5 $
12.00
Q2 2020 5 $
12.00
Q3 2020 6 $
12.00
Q4 2020 6 $
12.00
Total 2020 22 $
12.00
Natural Gas Net Written Call Swaptions
Volume Avg. NYMEX
(bcf) Strike Price
Q1 2020 26 $
2.77
Q2 2020 26 $
2.77
Q3 2020 27 $
2.77
Q4 2020 27 $
2.77
Total 2020 106 $
2.77
Total 2021 15 $
2.80
Total 2022 15 $
2.80
Natural Gas Basis Protection Swaps
Volume Avg. NYMEX
plus/(minus)
(bcf)
Q4 2019 29 $
(0.10)
Total 2019 29 $
(0.10)
Q1 2020 30 $
0.08
Total 2020 30 $
0.08
INVESTOR CONTACT:
MEDIA CONTACT:
Brad Sylvester, CFA
Gordon Pennoyer
(405) 935-8870
(405) 935-8878
ir@chk.com
media@chk.com
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SOURCE Chesapeake Energy Corporation
