Chesapeake Energy Corporation Reports 2018 Third Quarter Financial And Operational Results And Time Change For Earnings Call
OKLAHOMA CITY, Oct. 30, 2018 /PRNewswire/ -- Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operational results for the 2018 third quarter. Highlights include:
-- 2018 third quarter net income available to common stockholders of $60
million, or $0.07 per diluted share; 2018 third quarter adjusted net
income attributable to Chesapeake of $174 million, or $0.19 per diluted
share
-- 2018 third quarter cash flow from operating activities of $504 million,
up 52 percent from 2017 third quarter levels
-- Average 2018 third quarter production of approximately 537,000 barrels
of oil equivalent (boe) per day, up 5 percent compared to 2017 third
quarter, adjusted for asset sales
-- Average 2018 third quarter oil production of approximately 89,000
barrels (bbls) of oil per day, up 13 percent compared to 2017 third
quarter, adjusted for asset sales, primarily driven by higher volume
growth from the Powder River Basin (PRB)
Doug Lawler, Chesapeake's President and Chief Executive Officer, commented, "Chesapeake continues to make significant progress on our strategic priorities, as demonstrated by our improved cash flow from operations, which was more than 50 percent higher than the 2017 third quarter due to higher average realized commodity prices and 13 percent growth in our adjusted oil production. We plan to focus the vast majority of our projected 2019 activity on our high-margin, higher-return oil opportunities in the PRB and Eagle Ford Shale, while decreasing capital and activity directed toward our natural gas portfolio, which will generate additional free cash flow. Our capital expenditures for 2018 remain on track, as we execute on our priorities of reducing leverage, increasing margins and reaching sustainable positive cash flow, and we expect continued progress in 2019."
2018 Third Quarter Results
For the 2018 third quarter, Chesapeake reported net income of $85 million and net income available to common stockholders of $60 million, or $0.07 per diluted share. The company's EBITDA for the 2018 third quarter was $504 million. Adjusting for items that are typically excluded by securities analysts, the 2018 third quarter adjusted net income attributable to Chesapeake was $174 million, or $0.19 per diluted share, while the company's adjusted EBITDA was $594 million. Reconciliations of financial measures calculated in accordance with GAAP to non-GAAP measures are provided on pages 13 - 18 of this release.
Production expenses during the 2018 third quarter were $2.68 per boe, compared to $3.03 per boe in the 2017 third quarter. The decrease was primarily a result of certain 2018 and 2017 divestitures, in addition to lower workover activity in the Eagle Ford Shale. General and administrative expenses (including stock-based compensation) during the 2018 third quarter were $1.34 per boe, compared to $1.08 per boe in the 2017 third quarter. The increase was primarily due to less overhead allocated to production expenses, marketing expenses and capitalized general and administrative costs, as well as less overhead billed to working interest owners, due to certain divestitures in 2017 and 2018. The company's gathering, processing and transportation expenses decreased to $7.36 per boe from $7.40 per boe during the 2017 third quarter primarily as a result of certain 2018 and 2017 divestitures, reduced fees due to restructured midstream contracts and lower volume commitments.
Capital Spending Overview
Chesapeake incurred total capital expenditures, including capitalized interest of $42 million, of approximately $619 million during the 2018 third quarter, compared to approximately $692 million in the 2017 third quarter. A summary is provided in the table below.
Three Months Ended
September 30,
2018 2017
Operated
activity
comparison
Average rig
count 19 17
Gross wells
spud 84 86
Gross wells
completed 81 120
Gross wells
connected 75 122
Type of cost ($
in millions)
Drilling and
completion
capital
expenditures $
549 $
626
Exploration
costs,
leasehold and
additions to
other PP&E 28 17
Subtotal
capital
expenditures $
577 $
643
Capitalized
interest 42 49
Total capital
expenditures $
619 $
692
Balance Sheet and Liquidity
As of September 30, 2018, Chesapeake's principal amount of debt outstanding was approximately $9.862 billion, compared to $9.981 billion as of December 31, 2017. Also as of September 30, 2018, the company had $645 million of outstanding borrowings and $182 million for various letters of credit under its senior secured revolving credit facility resulting in approximately $2.2 billion of available liquidity under the facility.
Chesapeake continues to focus on reducing future interest expense charges, eliminating complexity and simplifying its balance sheet. On September 12, 2018, the company amended and restated its senior secured revolving credit facility with an initial borrowing base of $3.0 billion maturing in September 2023. The collateral securing the initial borrowing base does not include any properties sold in the company's $2.0 billion Utica Shale transaction, which closed in October 2018, therefore the borrowing base was not affected.
On September 27, 2018, the company issued $1.25 billion of senior notes, consisting of $850 million of 7.00% senior notes due 2024 and $400 million of 7.50% senior notes due 2026. Chesapeake used the net proceeds from the offering, together with borrowings under its revolving credit facility, to repay its secured term loan due 2021 which carried a floating interest rate equating to approximately 9.60%, in its entirety. The impact of this refinancing is projected to result in cash interest expense savings of approximately $30 million in 2019.
On October 29, 2018, the company delivered a notice of redemption to the trustee for its 8.00% Senior Secured Second Lien Notes due 2022 to call for redemption approximately $1.416 billion aggregate principal amount of the outstanding notes, representing 100% of the aggregate principal amount of the outstanding notes. The settlement of the redemption is expected to occur approximately 30 days from the notice delivery date and be funded with proceeds from the sale of the company's Utica Shale assets in Ohio.
Operations Update
Chesapeake's average daily production for the 2018 third quarter was approximately 537,000 boe compared to approximately 542,000 boe in the 2017 third quarter. The following tables show average daily production and average daily sales prices received by the company's operating divisions for the 2018 and 2017 third quarters, respectively.
Three Months Ended September 30, 2018
Oil Natural Gas NGL
Total
mbbl
$/bbl mmcf
$/mcf mbbl
$/bbl mboe %
$/boe
per day per day per day per day
Marcellus 812 2.46 135 25 14.74
Haynesville 769 2.74 128 24 16.44
Eagle Ford 58 74.40 122 3.26 22 28.95 100 19 53.43
Utica 10 67.09 488 2.92 28 29.39 119 22 24.33
Mid-Continent 9 69.41 66 2.50 4 29.40 25 5 37.68
Powder River
Basin 12 69.23 73 2.50 5 27.89 29 5 39.79
Retained
assets(a) 89 72.39 2,330 2.69 59 29.10 536 100 26.92
Divested assets 2 2.02 1 19.17
Total 89 72.39 2,332 2.69 59 29.09 537 100
% 26.92
Three Months Ended September 30, 2017
Oil Natural Gas NGL
Total
mbbl
$/bbl mmcf
$/mcf mbbl
$/bbl mboe %
$/boe
per day per day per day per day
Marcellus 748 1.96 125 23 11.76
Haynesville 804 2.77 134 25 16.63
Eagle Ford 52 49.08 136 3.25 18 23.07 92 17 36.91
Utica 12 44.18 475 2.76 28 20.30 120 22 20.21
Mid-Continent 10 46.98 69 2.54 6 22.18 27 5 28.03
Powder River
Basin 5 47.12 35 2.91 3 26.77 14 2 31.01
Retained
assets(a) 79 47.96 2,267 2.52 55 21.70 512 94 20.94
Divested assets 7 47.71 115 2.47 4 23.63 30 6 23.25
Total 86 47.94 2,382 2.52 59 21.83 542 100
% 21.06
(a) Includes assets
retained as of September 30,
2018.
Momentum is building in the PRB, where additional spacing and step-out tests further validate the exceptional rock quality, productivity and repeatable performance of the Turner formation. Daily net production from the basin continues to climb as demonstrated by the 107 percent increase compared to the average 2017 third quarter daily rate and 32 percent sequential growth compared to the 2018 second quarter. Chesapeake expects net production from the area will reach approximately 38,000 boe per day as an exit rate in 2018, and currently projects total net annual production from the PRB to more than double in 2019 compared to 2018.
In July 2018, Chesapeake moved to five rigs in the PRB, all of which are currently drilling the Turner formation. The company placed 13 wells on production during the 2018 third quarter, eight of which were Turner wells, bringing the total number of Turner wells on production to 24. Included was the company's best well drilled to date in the Turner with the Wyoming 36-34-69 B TR 1H well reaching a peak 24-hour average rate of 3,133 boe per day (47 percent oil) from a 10,246-foot lateral. In the 2018 third quarter, Chesapeake also drilled and completed three successful step-out Turner wells located along the western periphery of its acreage position. The wells yielded peak 24-hour production rates ranging from 1,480 to 2,725 boe per day with an average oil cut of 82 percent. With these well results, Chesapeake has delineated an area covering more than 50 square miles, or approximately 60 percent of its prospective Turner acreage, strengthening its confidence in future development plans.
The company continues to experiment with tighter spacing tests and is currently drilling its second set of wells spaced at approximately 1,980 feet. In April 2018, Chesapeake drilled six Turner wells spaced at approximately 1,980 to 2,300 feet apart and, with more than 190 days on production for each well, the company has seen no degradation from the tighter-spaced Turner wells compared to wells spaced at approximately 2,680 feet. The company expects to drill additional spacing tests in 2019, as well as move to development pad drilling in the more oil-prone (lower gas-to-oil ratio) portion of the field.
Chesapeake expects to place an additional 15 wells on production in the 2018 fourth quarter and is currently projecting an additional 65 to 70 Turner wells to be placed on production in 2019. The company is exploring the potential of adding a sixth rig in 2019, which would likely begin to focus on the Parkman and Niobrara formations.
To support the company's anticipated oil production growth, Chesapeake has recently finalized an agreement, subject to a right of first refusal, to lower its gathering and transporting costs by switching from trucking to pipeline transportation. The agreement will provide for the gathering and transportation of a portion of the company's crude oil volumes via pipeline from its development area to Guernsey, Wyoming beginning in the 2019 second quarter. The company's fixed-fee rate under this agreement is approximately one-third the cost the market is presently paying to gather and transport oil volumes to Guernsey by trucking. Chesapeake is evaluating long-haul transportation options to take volumes to Cushing, Oklahoma, to increase market access as production grows.
The Eagle Ford Shale in Texas continues to deliver steady, high-margin oil volumes that receive premium Gulf Coast pricing. While the region is typically unaffected by major weather events, production from the area was affected by abnormal flooding resulting in a decline in average net oil volumes sold of approximately 1,300 bbls of oil per day for the months of September and October 2018. The company is currently utilizing four rigs in the Eagle Ford, placed 29 wells on production during the 2018 third quarter and expects to place 53 wells on production during the 2018 fourth quarter. Chesapeake plans to add a fifth rig in 2019, as it continues to delineate additional opportunities in the Upper Eagle Ford and the Austin Chalk formations.
Chesapeake's position in the Marcellus Shale in Pennsylvania continues to create significant free cash flow driven by higher realized in-basin gas prices in the 2018 third quarter compared to a year ago, enhanced completions and longer laterals. Chesapeake is currently utilizing two rigs in the Marcellus, placed seven wells on production during the 2018 third quarter, and expects to place 25 wells on production during the 2018 fourth quarter.
In the 2018 third quarter, Chesapeake entered into a long-term supply agreement with a liquefied natural gas (LNG) provider for a portion of the company's in-basin net Marcellus gas production. Chesapeake has agreed to supply approximately 260 to 365 million British thermal units per day of net Marcellus gas production to the LNG provider for a 15-year term.
In the Haynesville Shale in Louisiana, Chesapeake moved an additional rig into the area in July and is currently utilizing four rigs, one of which is drilling the company's second well with a proposed lateral length of approximately 15,000 feet. Chesapeake drilled its first 15,000-foot well, the GEPH 30&19&18-16-15 1HC, in December 2017, which was placed on production in May, 2018. After approximately 170 days, the well is producing approximately 24.9 million cubic feet of natural gas (mmcf) per day and has produced a cumulative of 5.8 billion cubic feet of natural gas (bcf). Given higher-margin oil drilling opportunities in Chesapeake's portfolio, the company expects to decrease its activity in the area and move to operating one to two rigs in 2019. The company placed four wells on production in the Haynesville Shale during the 2018 third quarter, and expects to place seven wells on production during the 2018 fourth quarter.
In July 2018, Chesapeake announced that it entered into an agreement to sell its interests in the Utica Shale operating area located in Ohio for approximately $2.0 billion, subject to certain customary closing conditions including the receipt of third-party consents. This transaction closed in October 2018. Chesapeake is currently operating two rigs in the area and placed 11 Utica wells on production during the 2018 third quarter.
Key Financial and Operational Results
The table below summarizes Chesapeake's key financial and operational results during the
2018 third quarter as compared to results in prior periods.
Three Months Ended
September 30,
2018 2017
---
Barrels of oil
equivalent
production (in mboe) 49,413 49,831
Barrels of oil
equivalent
production (mboe/d) 537 542
Oil production (in
mbbl/d) 89 86
Average realized oil
price ($/bbl)(a) 58.77 52.33
Natural gas
production (in mmcf/
d) 2,332 2,382
Average realized
natural gas price
($/mcf)(a) 2.69 2.52
NGL production (in
mbbl/d) 59 59
Average realized NGL
price ($/bbl)(a) 27.37 21.26
Production expenses
($/boe) 2.68 3.03
Gathering, processing
and transportation
expenses ($/boe) 7.36 7.40
Oil -($/bbl) 3.83 4.33
Natural Gas -($/mcf) 1.33 1.34
NGL -($/bbl) 8.59 7.40
Production taxes
($/boe) 0.69 0.43
General and
administrative
expenses ($/boe)(b) 1.22 0.91
General and
administrative
expenses (stock-
based compensation)
(non-cash) ($/boe) 0.12 0.17
DD&A of oil and
natural gas
properties ($/boe) 5.54 4.57
DD&A of other assets
($/boe) 0.35 0.41
Interest expense
($/boe) 2.56 2.26
Marketing gross
margin ($ in
millions) (19) (14)
Net cash provided by
operating activities
($ in millions) 504 331
Net cash provided by
operating activities
($/boe) 10.20 6.62
Operating cash flow
($ in millions)(c) 482 337
Operating cash flow
($/boe) 9.75 6.74
Net income (loss) ($
in millions) 85 (17)
Net income (loss)
available to common
stockholders ($ in
millions) 60 (41)
Net income (loss) per
share available to
common stockholders
- diluted ($) 0.07 (0.05)
Adjusted EBITDA ($ in
millions)(d) 594 468
Adjusted EBITDA
($/boe) 12.01 9.36
Adjusted net income
attributable to
Chesapeake ($ in
millions)(e) 174 106
Adjusted net income
attributable to
Chesapeake
per share -diluted
($ in millions)(f) 0.19 0.12
(a) Includes the effects of realized
gains (losses) from hedging, but
excludes the effects of unrealized
gains (losses) from hedging.
(b) Excludes expenses associated with
stock-based compensation, which
are recorded in general and
administrative expenses in
Chesapeake's Condensed Consolidated
Statement of Operations.
(c) Defined as cash flow provided by
operating activities before changes
in components of working capital
and other assets and liabilities.
This is a non-GAAP measure. See
reconciliation of cash provided by
operating activities to operating
cash flow on page 16.
(d) Defined as net income (loss) before
interest expense, income taxes and
depreciation, depletion and
amortization expense, as adjusted
to remove the effects of certain
items detailed on page 18. This is
a non-GAAP measure. See
reconciliation of net income (loss)
to EBITDA on page 16 and
reconciliation of EBITDA to
adjusted EBITDA on page 18.
(e) Defined as net income (loss)
attributable to Chesapeake, as
adjusted to remove the effects of
certain items detailed on page 13.
This is a non-GAAP measure. See
reconciliation of net income to
adjusted net income (loss)
available to Chesapeake on page 13.
(f) Our presentation of diluted adjusted
net income attributable to
Chesapeake per share excludes 208
million and 206 million shares for
the three months ended September
30, 2018 and 2017, respectively,
considered antidilutive when
calculating diluted earnings per
share.
2018 Third Quarter Financial and Operational Results Conference Call Update
The conference call to discuss this release has been re-scheduled on Tuesday, October 30, 2018 at 9:00 am EDT. The telephone number to access the conference call is 877-871-3172 or 412-902-6603. The passcode for the call is 0118883. The conference call will be webcast and can be found at www.chk.com in the "Investors" section of the company's website.
Headquartered in Oklahoma City, Chesapeake Energy Corporation's (NYSE: CHK) operations are focused on discovering and developing its large and geographically diverse resource base of unconventional oil and natural gas assets onshore in the United States.
This news release and the accompanying Outlook include "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are statements other than statements of historical fact. They include statements that give our current expectations, management's outlook guidance or forecasts of future events, production and well connection forecasts, estimates of operating costs, anticipated capital and operational efficiencies, planned development drilling and expected drilling cost reductions, anticipated timing of wells to be placed into production, general and administrative expenses, capital expenditures, the timing of anticipated asset sales and proceeds to be received therefrom, the expected use of proceeds of anticipated asset sales, projected cash flow and liquidity, our ability to enhance our cash flow and financial flexibility, plans and objectives for future operations, the ability of our employees, portfolio strength and operational leadership to create long-term value, and the assumptions on which such statements are based. Although we believe the expectations and forecasts reflected in the forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate or changed assumptions or by known or unknown risks and uncertainties.
Factors that could cause actual results to differ materially from expected results include those described under "Risk Factors" in Item 1A of our annual report on Form 10-K and any updates to those factors set forth in Chesapeake's subsequent quarterly reports on Form 10-Q or current reports on Form 8-K (available at http://www.chk.com/investors/sec-filings). These risk factors include the volatility of oil, natural gas and NGL prices; the limitations our level of indebtedness may have on our financial flexibility; our inability to access the capital markets on favorable terms; the availability of cash flows from operations and other funds to finance reserve replacement costs or satisfy our debt obligations; downgrade in our credit rating requiring us to post more collateral under certain commercial arrangements; write-downs of our oil and natural gas asset carrying values due to low commodity prices; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and projecting future rates of production and the amount and timing of development expenditures; our ability to generate profits or achieve targeted results in drilling and well operations; leasehold terms expiring before production can be established; commodity derivative activities resulting in lower prices realized on oil, natural gas and NGL sales; the need to secure derivative liabilities and the inability of counterparties to satisfy their obligations; adverse developments or losses from pending or future litigation and regulatory proceedings, including royalty claims; charges incurred in response to market conditions and in connection with our ongoing actions to reduce financial leverage and complexity; drilling and operating risks and resulting liabilities; effects of environmental protection laws and regulation on our business; legislative and regulatory initiatives further regulating hydraulic fracturing; our need to secure adequate supplies of water for our drilling operations and to dispose of or recycle the water used; impacts of potential legislative and regulatory actions addressing climate change; federal and state tax proposals affecting our industry; potential OTC derivatives regulation limiting our ability to hedge against commodity price fluctuations; competition in the oil and gas exploration and production industry; a deterioration in general economic, business or industry conditions; negative public perceptions of our industry; limited control over properties we do not operate; pipeline and gathering system capacity constraints and transportation interruptions; terrorist activities and cyber-attacks adversely impacting our operations; an interruption in operations at our headquarters due to a catastrophic event; certain anti-takeover provisions that affect shareholder rights; and our inability to increase or maintain our liquidity through debt repurchases, capital exchanges, asset sales, joint ventures, farmouts or other means.
In addition, disclosures concerning the estimated contribution of derivative contracts to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility. Our production forecasts are also dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Expected asset sales may not be completed in the time frame anticipated or at all. We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this news release, and we undertake no obligation to update any of the information provided in this release or the accompanying Outlook, except as required by applicable law. In addition, this news release contains time-sensitive information that reflects management's best judgment only as of the date of this news release.
INVESTOR CONTACT:
MEDIA CONTACT:
Brad Sylvester, CFA
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 Nine Months Ended
September 30, September 30,
2018 2017 2018 2017
REVENUES:
Oil, natural gas and NGL(a) $
1,199 $
979 $
3,424 $
3,727
Marketing 1,219 964 3,738 3,250
Total Revenues 2,418 1,943 7,162 6,977
OPERATING EXPENSES:
Oil, natural gas and NGL production 132 151 417 426
Oil, natural gas and NGL gathering,
processing and transportation 364 369 1,060 1,081
Production taxes 34 21 91 64
Marketing 1,238 978 3,798 3,333
General and administrative 66 54 229 189
Restructuring and other termination
costs 38
Provision for legal contingencies, net 8 20 17 35
Oil, natural gas and NGL depreciation,
depletion and amortization 274 228 813 627
Depreciation and amortization of other
assets 17 20 54 62
Impairments 5 3 51 3
Other operating (income) expense 6 (1) 423
Net (gains) losses on sales of fixed
assets (1) 7
Total Operating Expenses 2,138 1,849 6,574 6,243
INCOME FROM OPERATIONS 280 94 588 734
OTHER INCOME (EXPENSE):
Interest expense (127) (114) (367) (302)
Gains on investments 139
Gains (losses) on purchases or
exchanges of debt (68) (1) (68) 183
Other income 1 4 63 6
Total Other Expense (194) (111) (233) (113)
INCOME (LOSS) BEFORE INCOME TAXES 86 (17) 355 621
Income tax expense (benefit) 1 (8) 2
NET INCOME (LOSS) 85 (17) 363 619
Net income attributable to
noncontrolling interests (1) (1) (3) (3)
NET INCOME (LOSS) ATTRIBUTABLE TO
CHESAPEAKE 84 (18) 360 616
Preferred stock dividends (23) (23) (69) (62)
Loss on exchange of preferred stock (41)
Earnings allocated to participating
securities (1) (3) (7)
NET INCOME (LOSS) AVAILABLE TO COMMON
STOCKHOLDERS $
60 $
(41) $
288 $
506
EARNINGS (LOSS) PER COMMON SHARE:
Basic $
0.07 $
(0.05) $
0.32 $
0.56
Diluted $
0.07 $
(0.05) $
0.32 $
0.56
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in
millions):
Basic 910 909 909 908
Diluted 911 909 909 908
(a) See page 10 for a reconciliation
of oil, natural gas and NGL
revenue before and after the
effect of financial derivatives.
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
($ in millions)
(unaudited)
September 30, December 31,
2018 2017
Cash and cash equivalents $
4 $
5
Other current assets 1,231 1,520
Total Current Assets 1,235 1,525
Property and equipment, net 11,177 10,680
Other long-term assets 247 220
Total Assets $
12,659 $
12,425
Current liabilities $
2,976 $
2,356
Long-term debt, net 9,380 9,921
Other long-term liabilities 342 520
Total Liabilities 12,698 12,797
Preferred stock 1,671 1,671
Noncontrolling interests 123 124
Common stock and other
stockholders' equity (deficit) (1,833) (2,167)
Total Equity (Deficit) (39) (372)
Total Liabilities and Equity $
12,659 $
12,425
Common shares outstanding (in
millions) 914 909
Principal amount of debt
outstanding $
9,862 $
9,981
CHESAPEAKE ENERGY CORPORATION
SUPPLEMENTAL DATA - OIL, NATURAL GAS AND NGL PRODUCTION, SALES AND INTEREST EXPENSE
(unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
2018 2017 2018 2017
---
Net Production:
Oil (mmbbl) 8 8 25 23
Natural gas (bcf) 215 219 647 639
NGL (mmbbl) 5 5 15 15
Oil equivalent (mmboe) 50 50 148 145
Average daily production
(mboe) 537 542 540 532
Oil, Natural Gas and NGL Sales ($ in
millions):
Oil sales $
594 $
379 $
1,698 $
1,140
Natural gas sales 578 553 1,822 1,807
NGL sales 159 117 404 328
Total oil, natural gas
and NGL sales $
1,331 $
1,049 $
3,924 $
3,275
Financial Derivatives:
Oil derivatives -
realized gains
(losses)(a) (112) 35 $
(273) 79
Natural gas derivatives -
realized gains
(losses)(a) (1) (1) 83 (53)
NGL derivatives -
realized gains
(losses)(a) (10) (3) (14) (1)
Total realized gains
(losses) on financial
derivatives $
(123) $
31 $
(204) $
25
Oil derivatives -
unrealized gains
(losses)(a) 12 (96) (115) 45
Natural gas derivatives -
unrealized gains
(losses)(a) (17) (3) (168) 384
NGL derivatives -
unrealized gains
(losses)(a) (4) (2) (13) (2)
Total unrealized gains
(losses) on financial
derivatives $
(9) $
(101) $
(296) $
427
Total financial
derivatives $
(132) $
(70) $
(500) $
452
Total oil, natural gas
and NGL sales $
1,199 $
979 $
3,424 $
3,727
Average Sales Price (excluding gains
(losses) on derivatives):
Oil ($ per bbl) $
72.39 $
47.94 $
68.63 $
48.53
Natural gas ($ per mcf) $
2.69 $
2.52 $
2.82 $
2.83
NGL ($ per bbl) $
29.09 $
21.83 $
26.87 $
21.28
Oil equivalent ($ per
boe) $
26.92 $
21.06 $
26.59 $
22.53
Average Sales Price (excluding
unrealized gains (losses) on
derivatives):
Oil ($ per bbl) $
58.77 $
52.33 $
57.61 $
51.90
Natural gas ($ per mcf) $
2.69 $
2.52 $
2.94 $
2.75
NGL ($ per bbl) $
27.37 $
21.26 $
25.96 $
21.21
Oil equivalent ($ per
boe) $
24.44 $
21.67 $
25.21 $
22.70
Interest Expense ($ in millions):
Interest expense(b) $
127 $
115 $
367 $
302
Interest rate derivatives
- realized gains(c) (1) (1) (2) (3)
Interest rate derivatives
- unrealized losses(c) 1 2 3
Total Interest Expense $
127 $
114 $
367 $
302
(a) Realized gains (losses) include
the following items: (i)
settlements and accruals for
settlements of undesignated
derivatives related to current
period production revenues, (ii)
prior period settlements for
option premiums and for early-
terminated derivatives originally
scheduled to settle against
current period production
revenues, and (iii) gains
(losses) related to de-
designated cash flow hedges
originally designated to settle
against current period production
revenues. Unrealized gains
(losses) include the change in
fair value of open derivatives
scheduled to settle against
future period production revenues
(including current period
settlements for option premiums
and early terminated derivatives)
offset by amounts reclassified as
realized gains (losses) during
the period. Although we no longer
designate our derivatives as cash
flow hedges for accounting
purposes, we believe these
definitions are useful to
management and investors in
determining the effectiveness of
our price risk management
program.
(b) Net of amounts capitalized.
(c) Realized (gains) losses include
interest rate derivative
settlements related to current
period interest and the effect of
(gains) losses on early-
terminated trades. Settlements of
early-terminated trades are
reflected in realized (gains)
losses over the original life of
the hedged item. Unrealized
(gains) losses include amounts
reclassified to realized (gains)
losses during the period.
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
($ in millions)
(unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
2018 2017 2018 2017
---
Beginning cash and cash
equivalents $
3 $
13 $
5 $
882
Net cash provided by
operating activities 504 331 1,595 273
Cash flows from investing activities:
Drilling and completion
costs(a) (502) (566) (1,481) (1,597)
Acquisitions of proved and
unproved properties(b) (53) (64) (244) (226)
Proceeds from divestitures
of proved and unproved
properties 11 242 395 1,193
Additions to other
property and equipment (6) (5) (11) (12)
Proceeds from sales of
other property and
equipment 1 14 75 40
Proceeds from sales of
investments 74
Net cash used in investing
activities (549) (379) (1,192) (602)
Net cash provided by (used
in) financing activities 46 40 (404) (548)
Change in cash and cash
equivalents 1 (8) (1) (877)
Ending cash and cash
equivalents $
4 $
5 $
4 $
5
(a) Includes capitalized interest of $2
million and $2 million for the three
months ended September 30, 2018 and
2017, respectively, and includes
capitalized interest of $7 million
and $7 million for the nine months
ended September 30, 2018 and 2017,
respectively.
(b) Includes capitalized interest of $40
million and $47 million for the
three months ended September 30,
2018 and 2017, respectively, and
includes capitalized interest of
$121 million and $139 million for
the nine months ended September 30,
2018 and 2017, respectively.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS
($ in millions except per share data)
(unaudited)
Three Months Ended September 30,
2018 2017
$
$/Share(a)(b)
$
$/Share(a)(b)
Net income (loss) available to common
stockholders (GAAP) $
60 $
0.07 $
(41) $
(0.05)
Effect of dilutive securities
Diluted earnings (losses) per common
stockholder (GAAP) $
60 $
0.07 $
(41) $
(0.05)
Adjustments:
Unrealized losses on oil, natural gas
and NGL derivatives 9 0.01 101 0.12
Provision for legal contingencies,
net 8 0.01 20 0.02
Other operating expense 6 0.01
Impairments 5 3
Net gains on sales of fixed assets (1)
Losses on purchases or exchanges of
debt 68 0.07 1
Income tax expense (benefit)(c)
Other (6) (0.01)
Adjusted net income available to
common stockholders(a) (Non-GAAP) 150 0.16 83 0.09
Preferred stock dividends 23 0.03 23 0.03
Earnings allocated to participating
securities 1
Total adjusted net income
attributable to Chesapeake(a) (b)
(Non-GAAP) $
174 $
0.19 $
106 $
0.12
(a) Adjusted net
income (loss)
available to
common
stockholders and
total adjusted
net income (loss)
attributable to
Chesapeake, both
in the aggregate
and per dilutive
share, are not
measures of
financial
performance under
GAAP, and should
not be considered
as an alternative
to, or more
meaningful than,
net income (loss)
available to
common
stockholders or
earnings (loss)
per share.
Adjusted net
income (loss)
available to
common
stockholders and
adjusted earnings
(loss) per share
exclude certain
items that
management
believes affect
the comparability
of operating
results. The
company believes
these adjusted
financial
measures are a
useful adjunct to
earnings
calculated in
accordance with
GAAP because:
(i) Management uses adjusted net
income (loss) available to
common stockholders to evaluate
the company's operational trends
and performance relative to
other oil and natural gas
producing companies.
(ii) Adjusted net income (loss)
available to common stockholders
is more comparable to earnings
estimates provided by securities
analysts.
(iii) Items excluded generally are one-
time items or items whose timing
or amount cannot be reasonably
estimated. Accordingly, any
guidance provided by the company
generally excludes information
regarding these types of items.
Because adjusted
net income (loss)
available to
common
stockholders and
total adjusted
net income (loss)
attributable to
Chesapeake
exclude some, but
not all, items
that affect net
income (loss)
available to
common
stockholders and
total adjusted
net income (loss)
attributable to
Chesapeake may
vary among
companies, our
calculation of
adjusted net
income (loss)
available to
common
stockholders and
total adjusted
net income (loss)
attributable to
Chesapeake may
not be comparable
to similarly
titled financial
measures of other
companies.
(b) Our presentation
of diluted net
income (loss)
available to
common
stockholders and
diluted adjusted
net income (loss)
per share
excludes 208
million and 206
million shares
considered
antidilutive for
the three months
ended September
30, 2018 and
2017,
respectively. The
number of shares
used for the non-
GAAP calculation
was determined in
a manner
consistent with
GAAP.
(c) Our effective tax
rate in the three
months ended
September 30,
2018 was 0%. Due
to our valuation
allowance
position, no
income tax effect
from the
adjustments has
been included in
determining
adjusted net
income for the
three months
ended September
30, 2017.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS
($ in millions except per share data)
(unaudited)
Nine Months Ended September 30,
2018 2017
$
$/Share(a)(b)
$
$/Share(a)(b)
Net income available to common
stockholders (GAAP) $
288 $
0.32 $
506 $
0.56
Effect of dilutive securities
Diluted earnings per common
stockholder (GAAP) $
288 $
0.32 $
506 $
0.56
Adjustments:
Unrealized (gains) losses on oil,
natural gas and NGL derivatives 296 0.32 (427) (0.47)
Restructuring and other termination
costs 38 0.04
Provision for legal contingencies,
net 17 0.02 35 0.04
Other operating expense (income) (1) 423 0.47
Impairments 51 0.06 3
Net losses on sales of fixed assets 7 0.01
Gains on investments (139) (0.15)
(Gains) losses on purchases or
exchanges of debt 68 0.07 (183) (0.21)
Loss on exchange of preferred stock 41 0.05
Income tax expense (benefit)(c)
Other (d) (59) (0.06) (3)
Adjusted net income available to
common stockholders(a) (Non-GAAP) 566 0.63 395 0.44
Preferred stock dividends 69 0.07 62 0.07
Earnings allocated to participating
securities 3 7
Total adjusted net income
attributable to Chesapeake(a) (b)
(Non-GAAP) $
638 $
0.70 $
464 $
0.51
(a) Adjusted net
income (loss)
available to
common
stockholders and
total adjusted
net income (loss)
attributable to
Chesapeake, both
in the aggregate
and per dilutive
share, are not
measures of
financial
performance under
GAAP, and should
not be considered
as an alternative
to, or more
meaningful than,
net income (loss)
available to
common
stockholders or
earnings (loss)
per share.
Adjusted net
income (loss)
available to
common
stockholders and
adjusted earnings
(loss) per share
exclude certain
items that
management
believes affect
the comparability
of operating
results. The
company believes
these adjusted
financial
measures are a
useful adjunct to
earnings
calculated in
accordance with
GAAP because:
(i) Management uses adjusted net
income (loss) available to
common stockholders to evaluate
the company's operational trends
and performance relative to
other oil and natural gas
producing companies.
(ii) Adjusted net income (loss)
available to common stockholders
is more comparable to earnings
estimates provided by securities
analysts.
(iii) Items excluded generally are one-
time items or items whose timing
or amount cannot be reasonably
estimated. Accordingly, any
guidance provided by the company
generally excludes information
regarding these types of items.
Because adjusted
net income (loss)
available to
common
stockholders and
total adjusted
net income (loss)
attributable to
Chesapeake
exclude some, but
not all, items
that affect net
income (loss)
available to
common
stockholders and
total adjusted
net income (loss)
attributable to
Chesapeake may
vary among
companies, our
calculation of
adjusted net
income (loss)
available to
common
stockholders and
total adjusted
net income (loss)
attributable to
Chesapeake may
not be comparable
to similarly
titled financial
measures of other
companies.
(b) Our presentation
of diluted net
income (loss)
available to
common
stockholders and
diluted adjusted
net income (loss)
per share
excludes 207
million and 207
million shares
considered
antidilutive for
the nine months
ended September
30, 2018 and
2017,
respectively. The
number of shares
used for the non-
GAAP calculation
was determined in
a manner
consistent with
GAAP.
(c) Our effective tax
rate in the nine
months ended
September 30,
2018 was 0%. Due
to our valuation
allowance
position, no
income tax effect
from the
adjustments has
been included in
determining
adjusted net
income for the
nine months ended
September 30,
2017.
(d) Other for the nine
months ended
September 30,
2018 includes a
$61 million gain
related to an
extinguishment of
the CHK Utica
overriding
royalty interest
conveyance
obligation.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
($ in millions)
(unaudited)
Three Months Ended Nine Months Ended
September 30,
September 30,
2018 2017 2018 2017
---
CASH PROVIDED BY
OPERATING
ACTIVITIES (GAAP) $
504 $
331 $
1,595 $
273
Changes in
components of
working capital
and other assets
and liabilities (22) 6 (116) 366
OPERATING CASH
FLOW (Non-
GAAP)(a) $
482 $
337 $
1,479 $
639
Three Months Ended Nine Months Ended
September 30, September 30,
2018 2017 2018 2017
NET INCOME (LOSS)
(GAAP) $
85 $
(17) $
363 $
619
Interest expense 127 114 367 302
Income tax
expense
(benefit) 1 (8) 2
Depreciation and
amortization of
other assets 17 20 54 62
Oil, natural gas
and NGL
depreciation,
depletion and
amortization 274 228 813 627
EBITDA (Non-
GAAP)(b) $
504 $
345 $
1,589 $
1,612
Three Months Ended Nine Months Ended
September 30, September 30,
2018 2017 2018 2017
CASH PROVIDED BY
OPERATING
ACTIVITIES (GAAP) $
504 $
331 $
1,595 $
273
Changes in assets
and liabilities (22) 6 (116) 366
Interest expense 127 114 367 302
Gains (losses) on
oil, natural gas
and NGL
derivatives, net (132) (70) (500) 452
Cash (receipts)
payments on
derivative
settlements, net 107 (20) 162 46
Stock-based
compensation (7) (11) (25) (38)
Impairments (5) (3) (51) (3)
Gains (losses) on
sales of fixed
assets 1 (7)
Gains on investments 139
Gains (losses) on
purchases or
exchanges of debt (68) (68) 185
Other items (c) (3) 93 29
EBITDA (Non-
GAAP)(b) $
504 $
345 $
1,589 $
1,612
(a) Operating cash flow represents net cash
provided by operating activities before
changes in components of working capital
and other. Operating cash flow is
presented because management believes it
is a useful adjunct to net cash provided
by operating activities under GAAP and
provides useful information to investors
for analysis of the Company's ability to
generate cash to fund exploration and
development, and to service debt.
Operating cash flow is widely accepted as
a financial indicator of an oil and
natural gas company's ability to generate
cash that is used to internally fund
exploration and development activities and
to service debt. This measure is widely
used by investors and rating agencies in
the valuation, comparison, rating and
investment recommendations of companies
within the oil and natural gas exploration
and production industry. Operating cash
flow is not a measure of financial
performance under GAAP and should not be
considered as an alternative to cash flows
from operating activities as an indicator
of cash flows, or as a measure of
liquidity. Because operating cash flow
excludes some, but not all, items that
affect net cash provided by operating
activities and may vary among companies,
our calculation of operating cash flow may
not be comparable to similarly titled
measures of other companies. The increase
in operating cash flow for the nine months
ended September 30, 2018 is mainly due to
an increase in realized prices and
volumes.
(b) EBITDA represents net income before
interest expense, income tax expense, and
depreciation, depletion and amortization
expense. EBITDA is presented as a
supplemental financial measurement in the
evaluation of our business. We believe
that it provides additional information
regarding our ability to meet our future
debt service, capital expenditures and
working capital requirements. This measure
is widely used by investors and rating
agencies in the valuation, comparison,
rating and investment recommendations of
companies. EBITDA is also a financial
measurement that, with certain negotiated
adjustments, is reported to our lenders
pursuant to our bank credit agreements and
is used in the financial covenants in our
bank credit agreements. EBITDA is not a
measure of financial performance (or
liquidity) under GAAP. Accordingly, it
should not be considered as a substitute
for net income, income from operations or
cash flows from operating activities
prepared in accordance with GAAP.
(c) Other items for the nine months ended
September 30, 2018 includes a $61 million
gain related to an extinguishment of the
CHK Utica overriding royalty interest
conveyance obligation.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED EBITDA
($ in millions)
(unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
2018 2017 2018 2017
---
EBITDA (Non-GAAP) (a) $
504 $
345 $
1,589 $
1,612
Adjustments:
Unrealized (gains) losses
on oil, natural gas and
NGL derivatives 9 101 296 (427)
Restructuring and other
termination costs - 38
Provision for legal
contingencies, net 8 20 17 35
Other operating expense
(income) - 6 (1) 423
Impairments 5 3 51 3
(Gains) losses on sales
of fixed assets - (1) 7
Gains on investments - (139)
(Gains) losses on
purchases or exchanges
of debt 68 1 68 (183)
Net income attributable
to noncontrolling
interests (1) (1) (3) (3)
Other (b) 1 (6) (60) (6)
Adjusted EBITDA (Non-
GAAP)(a) $
594 $
468 $
1,863 $
1,454
(a) EBITDA and
Adjusted EBITDA
are not measures
of financial
performance under
GAAP, and should
not be considered
as an alternative
to, or more
meaningful than,
net income (loss)
or cash flow
provided by (used
in) operations
prepared in
accordance with
GAAP. Adjusted
EBITDA excludes
certain items
that management
believes affect
the comparability
of operating
results. The
company believes
these non-GAAP
financial
measures are a
useful adjunct to
EBITDA because:
(i) Management uses adjusted EBITDA
to evaluate the company's
operational trends and
performance relative to other
oil and natural gas producing
companies.
(ii) Adjusted EBITDA is more
comparable to estimates provided
by securities analysts.
(iii) Items excluded generally are one-
time items or items whose timing
or amount cannot be reasonably
estimated. Accordingly, any
guidance provided by the company
generally excludes information
regarding these types of items.
Because adjusted
EBITDA excludes
some, but not
all, items that
affect net
income, our
calculations of
adjusted EBITDA
may not be
comparable to
similarly titled
measures of other
companies.
(b) Other for the nine
months ended
September 30,
2018 includes a
$61 million gain
related to an
extinguishment of
the CHK Utica
overriding
royalty interest
conveyance
obligation.
CHESAPEAKE ENERGY CORPORATION
MANAGEMENT'S OUTLOOK AS OF OCTOBER 30, 2018
Chesapeake periodically provides guidance on certain
factors that affect the company's future financial
performance. New information or changes from the
company's August 1, 2018 outlook are italicized bold
below.
Year Ending
12/31/2018
Production Growth
adjusted for asset
sales(a) 1% to 5%
Absolute Production
Liquids -mmbbls
48.5 - 52.5
Oil - mmbbls
31.5 - 33.5
NGL - mmbbls
17.0 - 19.0
Natural gas -bcf
790 - 830
Total absolute production
-mmboe
180 - 191
Absolute daily rate -
mboe
494 - 524
Estimated Realized Hedging Effects(b) (based on
10/25/18 strip prices):
Oil -$/bbl ($11.85)
Natural gas -$/mcf $0.07
NGL -$/bbl $(0.95)
Estimated Basis to NYMEX Prices:
Oil -$/bbl
$2.05 - $2.25
Natural gas -$/mcf ($0.10) -($0.15)
NGL -$/bbl ($6.20) -($6.60)
Operating Costs per Boe of Projected Production:
Production expense
$2.85 - $2.95
Gathering, processing and
transportation expenses
$6.85 - $7.35
Oil - $/bbl
$3.60 - $3.80
Natural Gas -$/mcf
$1.25 - $1.35
NGL -$/bbl
$8.25 - $8.65
Production taxes
$0.60 - $0.70
General and
administrative(c)
$1.25 - $1.35
Stock-based compensation
(noncash)
$0.10 - $0.20
DD&A of natural gas and
liquids assets
$5.25 - $6.25
Depreciation of other
assets
$0.35 - $0.45
Interest expense
$2.40 - $2.60
Marketing net margin(d) ($55) -($35)
Book Tax Rate 0%
Adjusted EBITDA, based on
10/25/18 strip prices ($
in millions)(e)
$2,300 - $2,500
Capital Expenditures ($
in millions)(f)
$2,000 - $2,300
Capitalized Interest ($
in millions) $175
Total Capital
Expenditures ($ in
millions)
$2,175 - $2,475
(a) Based on 2017 production of 407 mboe
per day, adjusted for 2017 asset
sales and 2018 asset sales signed
to date.
(b) Includes expected settlements for
oil, natural gas and NGL
derivatives adjusted for option
premiums. For derivatives closed
early, settlements are reflected in
the period of original contract
expiration.
(c) Excludes expenses associated with
stock-based compensation, which
are recorded in general and
administrative expenses in
Chesapeake's Consolidated Statement
of Operations.
(d) Excludes non-cash amortization of
approximately $19 million.
(e) Adjusted EBITDA is a non-GAAP
measure used by management to
evaluate the company's operational
trends and performance relative to
other oil and natural gas producing
companies. Adjusted EBITDA excludes
certain items that management
believes affect the comparability
of operating results. The most
directly comparable GAAP measure is
net income but, it is not possible,
without unreasonable efforts, to
identify the amount or significance
of events or transactions that may
be included in future GAAP net
income but that management does not
believe to be representative of
underlying business performance.
The company further believes that
providing estimates of the amounts
that would be required to reconcile
forecasted adjusted EBITDA to
forecasted GAAP net income would
imply a degree of precision that
may be confusing or misleading to
investors. Items excluded from net
income to arrive at adjusted EBITDA
include interest expense, income
taxes, and depreciation, depletion
and amortization expense as well as
one-time items or items whose
timing or amount cannot be
reasonably estimated.
(f) Includes capital expenditures for
drilling and completion, leasehold,
geological and geophysical costs,
rig termination payments and other
property, plant and equipment.
Excludes any additional proved
property acquisitions.
Oil, Natural Gas and Natural Gas Liquids Hedging Activities
Chesapeake enters into oil, natural gas and NGL derivative transactions in order to mitigate a portion of its exposure to adverse changes in market prices. Please see the quarterly reports on Form 10-Q and annual reports on Form 10-K filed by Chesapeake with the SEC for detailed information about derivative instruments the company uses, its quarter-end derivative positions and accounting for oil, natural gas and natural gas liquids derivatives.
As of October 26, 2018, including October derivative contracts that have settled, the company had downside price protection on a portion of its 2018 oil, natural gas and natural gas liquids production. The company had downside oil price protection through swaps at an average price of $54.09 per bbl, and under three-way collar arrangements based on an average bought put NYMEX price of $47.00 per bbl and exposure below an average sold put NYMEX price of $39.15 per bbl. The company had downside natural gas price protection through swaps and two-way collars at an average price of $3.00 per mcf. Chesapeake also had downside ethane, propane, butane, isobutane and natural gasoline price protection through swaps at an average price of $0.29, $0.79, $0.88, $0.92 and $1.42 per gallon (as well as a portion of butane at 70.5 percent of WTI), respectively. Further details summarized below.
In addition, the company had downside protection, through open swaps on a portion of its 2019 oil production at an average price of $59.44 per bbl. The company also initiated downside protection on a portion of its 2019 natural gas production through open swaps and two-way collars at an average price of $2.82 per mcf and under three-way collar arrangements based on an average bought put NYMEX price of $2.80 per mcf and exposure below an average sold put NYMEX price of $2.50 per mcf.
The company's crude oil hedging positions were as follows:
Crude Oil Swaps
Losses from Closed Crude Oil Trades
Swaps Avg. NYMEX Losses from
Closed
Trades
(mmbbls) Price of
($ in
millions)
Swaps
---
Q4 2018 7 $
54.09 (1)
Total
2018 7 $
54.09 $
(1)
Q1 2019 4 $
59.06 (1)
Q2 2019 4 $
59.06 (1)
Q3 2019 3 $
59.96 (1)
Q4 2019 3 $
59.96 (1)
Total
2019 14 $
59.44 $
(4)
Total
2020-2022 3 $
69.47 $
(4)
Crude Oil Three-Way Collars
Collars Avg. NYMEX Avg. NYMEX Avg. NYMEX
(mmbbls) Sold Put Bought Put Sold Call
Price Price Price
Q4 2018 1 $
39.15 $
47.00 $
55.00
Total 2018 1 $
39.15 $
47.00 $
55.00
Oil Basis Protection Swaps
Volume Avg. NYMEX
(mmbbls) plus/
(minus)
---
Q4 2018 4 $
3.52
Total 2018 4 $
3.52
Q1 2019 2 $
5.93
Q2 2019 3 $
5.93
Q3 2019 1 $
6.20
Q4 2019 1 $
6.20
Total 2019 7 $
6.01
The company's natural gas hedging positions were as follows:
Natural Gas Swaps
Losses from Closed Natural Gas Trades
Swaps Avg. NYMEX Losses
(bcf) Price of from Closed
Trades
Swaps
($ in
millions)
---
Q4
2018 120 $
3.00 (5)
Total
2018 120 $
3.00 $
(5)
Q1
2019 81 $
2.83 (6)
Q2
2019 81 $
2.83 (4)
Q3
2019 82 $
2.83 (4)
Q4
2019 81 $
2.83 (5)
Total
2019 325 $
2.83 $
(19)
Total
2020
-
2022
$ $
(29)
Natural Gas Two-Way Collars
Collars Avg. NYMEX Avg. NYMEX
(bcf) Bought Put Sold Call
Price Price
---
Q4
2018 12 $
3.00 $
3.25
Total
2018 12 $
3.00 $
3.25
Q1
2019 27 $
2.75 $
3.13
Q2
2019 9 $
2.75 $
2.91
Q3
2019 9 $
2.75 $
2.91
Q4
2019 9 $
2.75 $
2.91
Total
2019 54 $
2.75 $
3.02
Natural Gas Three-Way Collars
Collars Avg. NYMEX Avg. NYMEX Avg. NYMEX
(bcf) Sold Put Bought Put Sold Call
Price Price Price
Q1 2019 22 $
2.50 $
2.80 $
3.10
Q2 2019 22 $
2.50 $
2.80 $
3.10
Q3 2019 22 $
2.50 $
2.80 $
3.10
Q4 2019 22 $
2.50 $
2.80 $
3.10
Total 2019 88 $
2.50 $
2.80 $
3.10
Natural Gas Net Written Call Options
Call Options Avg. NYMEX
(bcf) Strike Price
---
Q4 2018 17 $
6.27
Total
2018 17 $
6.27
Q1 2019 5 $
12.00
Q2 2019 5 $
12.00
Q3 2019 6 $
12.00
Q4 2019 6 $
12.00
Total
2019 22 $
12.00
Total
2020 22 $
12.00
Natural Gas Basis Protection Swaps
Volume Avg. NYMEX
plus/(minus)
(bcf)
---
Q4 2018 6 $
(0.77)
Total 2018 6 $
(0.77)
Q1 2019 7 $
1.07
Q2 2019 12 $
(0.17)
Q3 2019 12 $
(0.17)
Q4 2019 6 $
(0.39)
Total 2019 37 $
0.03
The company's natural gas liquids hedging positions were as follows:
Ethane Swaps
Volume Avg. NYMEX
Price of
Swaps
(mmgal)
Q4 2018 23 $
0.29
Total 2018 23 $
0.29
Propane Swaps
Volume Avg. NYMEX
Price of
Swaps
(mmgal)
---
Q4 2018 15 $
0.79
Total 2018 15 $
0.79
Butane Swaps
Volume Avg. NYMEX
Price of
Swaps
(mmgal)
---
Q4 2018 1 $
0.88
Total 2018 1 $
0.88
Butane Swaps Priced as a Percentage of WTI
Volume Avg.
NYMEX
as a % of
WTI
Swaps
(mmgal)
---
Q4 2018 1 70.5%
Total 2018 1 70.5%
Iso-Butane Swaps
Volume Avg. NYMEX
Price of
Swaps
(mmgal)
---
Q4 2018 4 $
0.92
Total 2018 4 $
0.92
Natural Gasoline Swaps
Volume Avg. NYMEX
Price of
Swaps
(mmgal)
---
Q4 2018 12 $
1.42
Total 2018 12 $
1.42
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SOURCE Chesapeake Energy Corporation
