Chesapeake Energy Corporation Reports 2017 Third Quarter Financial And Operational Results
OKLAHOMA CITY, Nov. 2, 2017 /PRNewswire/ -- Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operational results for the 2017 third quarter plus other recent developments. Highlights include:
-- Average 2017 third quarter production of 541,600 boe per day and average
2017 third quarter oil production of 86,000 barrels per day, as
previously announced
-- Total production reached approximately 584,000 boe per day, including
99,000 barrels of oil, on October 30, 2017
-- On track to meet goal of averaging 100,000 barrels of oil per day in the
2017 fourth quarter
-- Upper Marcellus Shale enhanced completions yield rates exceeding
expectations; competitive with Lower Marcellus core position
Doug Lawler, Chesapeake's Chief Executive Officer, commented, "We continue to improve our capital efficiency and cost structure as we drive toward free cash flow neutrality. We have recognized greater productivity across our diverse portfolio through technical innovation and the tenacity of our employees and, accordingly, we are expanding our core position in every operated play. On October 30, 2017, total production reached 584,000 boe per day, including 99,000 barrels of oil and we remain on track to average 100,000 barrels of oil per day in the fourth quarter. As further evidence of our progress, we are pleased to announce the results of two new wells with enhanced completions in the Upper Marcellus that are producing at rates of approximately 30 million cubic feet of gas per day, exceeding expectations and competitive with our world class Lower Marcellus position."
Lawler continued, "As we look toward 2018, our priorities remain unchanged as we focus on further improving our balance sheet, increasing our margins and driving toward cash flow neutrality. While we have not announced details regarding our 2018 capital program, we will maintain a disciplined approach that provides the flexibility necessary to respond to changes in commodity prices. As of today, we anticipate spending less capital in 2018 than 2017 and, given our asset quality and industry-leading capital efficiency, we expect to deliver flat to modest production growth on a lower capital expenditure. We look forward to reporting more on our progress in the coming months."
2017 Third Quarter Results
For the 2017 third quarter, Chesapeake reported a net loss available to common stockholders of $41 million, or $0.05 per diluted share, while the company's EBITDA for the 2017 third quarter was $345 million. Adjusting for unrealized losses on commodity derivatives and other items that are typically excluded by securities analysts, the 2017 third quarter adjusted net income attributable to Chesapeake was $106 million, or $0.12 per diluted share, while the company's adjusted EBITDA was $468 million. Reconciliations of financial measures calculated in accordance with GAAP to non-GAAP measures are provided on pages 12 - 18 of this release.
Chesapeake's oil, natural gas and natural gas liquids (NGL) unhedged revenue was approximately unchanged year over year despite a 15% reduction in volume, mainly driven by asset sales. Chesapeake's oil, natural gas and NGL unhedged revenue decreased 3% quarter over quarter due to a decrease in the average commodity prices for the company's natural gas production, partially offset by an increase in natural gas and NGL production volumes sold. Average daily production for the 2017 third quarter of approximately 541,600 barrels of oil equivalent (boe) increased by 4% sequentially, adjusted for asset sales, and consisted of approximately 86,000 barrels (bbls) of oil, 2.382 billion cubic feet (bcf) of natural gas and 58,600 bbls of NGL.
Average production expenses during the 2017 third quarter were $3.03 per boe, while general and administrative (G&A) expenses (including stock-based compensation) during the 2017 third quarter were $1.08 per boe. Combined production and G&A expenses (including stock-based compensation) during the 2017 third quarter were $4.11 per boe, an increase of 6% year over year and a decrease of 6% quarter over quarter. Gathering, processing and transportation expenses during the 2017 third quarter were $7.40 per boe, a decrease of 8% year over year and a nominal decrease quarter over quarter.
Capital Spending Overview
Chesapeake's total capital investments were approximately $692 million during the 2017 third quarter, compared to approximately $667 million in the 2017 second quarter and $412 million in the 2016 third quarter. As a result of the company's year-to-date capital investment, along with its projected capital outlay in the 2017 fourth quarter, Chesapeake's current guidance range for total capital investments was raised to $2.3 to $2.5 billion from $2.1 to $2.5 billion. A summary of the company's guidance for 2017 is provided under "Management's Outlook as of November 2, 2017," beginning on page 20.
2017 2017 2016
Operated activity comparison Q3 Q2 Q3
---------------------------- --- --- ---
Average rig count 17 19 11
Gross wells spud 86 102 63
Gross wells completed 120 107 80
Gross wells connected 122 94 105
===================== === === ===
Type of cost ($ in millions)
Drilling and completion costs $626 $596 $332
Exploration costs, leasehold and
additions to other PP&E 17 24 21
-------------------------------- --- --- ---
Subtotal capital expenditures $643 $620 $353
Capitalized interest 49 47 59
--- ---
Total capital expenditures $692 $667 $412
========================== ==== ==== ====
Balance Sheet and Liquidity
As of September 30, 2017, Chesapeake's principal debt balance was approximately $9.8 billion, compared to $10.0 billion as of December 31, 2016. The company's total liquidity as of September 30, 2017 was approximately $3.0 billion, which included cash on hand and a borrowing capacity of approximately $3.0 billion under the company's senior secured revolving credit facility. As of September 30, 2017, the company had $645 million of outstanding borrowings under the revolving credit facility and had used $97 million of the revolving credit facility for various letters of credit.
On October 12, 2017, Chesapeake issued through a private placement an aggregate of $850 million of 8.00% Senior Notes due 2025 and 2027 with proceeds to be used to repurchase debt. On October 13, 2017, approximately $320 million principal amount of the company's 8.00% Senior Secured Second Lien Notes due 2022 and $193 million principal amount in various Senior Notes due 2020 and 2021 were tendered. In addition, Chesapeake also repurchased in the open market approximately $237 million principal amount of the company's secured term loan due 2021 in October 2017. As a result, Chesapeake has further reduced the principal amount of its secured debt by approximately $557 million since June 30, for a total reduction in the principal amount of secured debt of approximately $1.2 billion year to date. The company's total debt balance on October 31, 2017 was approximately $9.9 billion, including $643 million drawn on its revolving credit facility and the company's total liquidity was approximately $3.1 billion.
On October 30, 2017, the administrative agent under the company's senior revolving credit agreement, in addition to other lenders under the agreement, notified Chesapeake that the borrowing base had been reaffirmed at $3.785 billion.
Operations Update
Chesapeake's average daily production for the 2017 third quarter was approximately 541,600 boe and is further detailed in the table below. Chesapeake's projected production volumes and capital expenditure program are subject to capital allocation decisions throughout the remainder of the year and may be adjusted based on prevailing market conditions.
2017 2017 2016
Operating area net production
(mboe/day) Q3 Q2 Q3
----------------------------- ---
Eagle Ford 93 100 101
Haynesville 134 121 139
Marcellus 126 135 134
Utica 120 97 127
Mid-Continent 56 59 55
Powder River Basin 13 16 14
Barnett - - 59
Other - - 9
---
Total production 542 528 638
================ === === ===
Chesapeake is currently utilizing 14 drilling rigs (below the 2017 third quarter average of 17) across its operating areas, five of which are located in the Eagle Ford Shale, three in the Powder River Basin (PRB), three in the Haynesville Shale, two in Northeast Appalachia and one in the Mid-Continent area. Chesapeake plans to average 14 rigs in the 2017 fourth quarter.
In the Eagle Ford Shale, Chesapeake placed 31 wells on production in the 2017 third quarter. Included in this number were 20 wells in the company's Faith Ranch development area, of which 14 wells reached peak production of more than 1,000 bbls of oil per day. In total, the Faith Ranch wells achieved peak production of approximately 18,000 bbls of oil per day. Additionally, in October, Chesapeake placed 11 wells on production from its Vesper development area, yielding approximately 13,000 bbls of oil per day, highlighted by the Vesper Unit IV DIM H 3H well which featured a three-mile lateral and enhanced completion, and yielded an initial production of more than 2,000 bbls of oil per day. Chesapeake expects to place on production up to 73 wells in the Eagle Ford in the 2017 fourth quarter.
In the PRB, Chesapeake's third Turner well, the Graham 23-35-71 15H, was completed with a 4,500-foot lateral and placed on production in September 2017, achieving a peak rate of 1,737 boe per day (82% oil). On October 31, 2017, Chesapeake placed two additional Turner wells on production from its York pad, averaging approximately 8,500 feet in lateral length each. The company expects to provide updated results from these Turner wells later in the month. Chesapeake added a third rig in October 2017 and expects to place on production up to 11 wells in the 2017 fourth quarter, compared to seven wells in the 2017 third quarter.
In the Marcellus Shale, Chesapeake has begun to deploy its enhanced completion techniques on the Upper Marcellus formation, yielding rates that have exceeded internal expectations. The company placed two Upper Marcellus wells from its Maris pad located in Susquehanna County on production in September 2017. These wells achieved peak rates of 29,800 and 29,600 thousand cubic feet (mcf) of gas per day, respectively, more than 50% higher than the company's previous Upper Marcellus record rate of 18,700 mcf of gas per day from a well drilled in 2015. These wells have produced with pressures as expected with minimal depletion from offset wells in the Lower Marcellus, including one that was offset at 375 feet. These results confirmed positive delineation of the company's Upper Marcellus resource potential in areas where Lower Marcellus production had already existed, and have the potential to significantly increase the company's core position in the play. Chesapeake also placed the DPH SW WYO 3H well targeting the Lower Marcellus and located in the southern edge of the company's Wyoming County acreage on production, achieving a peak rate of 37,900 mcf of gas per day from a 6,100-foot lateral with an enhanced completion in October 2017. Chesapeake expects to place on production up to 17 wells in the 2017 fourth quarter, compared to 25 wells in the 2017 third quarter.
In the Utica Shale, enhanced completions techniques have yielded an approximately 25% improvement in 120-day cumulative production compared to the type curve. In July 2017, the eight-well Ellie pad was placed on production yielding an average per well initial production rate of 1,100 boe per day, 65% of which was liquids. The dry gas portion of the Utica is also delivering positive results. Chesapeake is in the initial flowback period for the Schiappa Trust A pad in Jefferson County and has seen initial production rates of 20,000 mcf of gas per well per day. Chesapeake plans to continue testing new completions designs in the 2017 fourth quarter.
In the Haynesville Shale, Chesapeake turned 12 wells on production in the 2017 third quarter, averaging lateral lengths of 8,440 feet and initial production of 31,840 mcf of gas per day. Of note, the company placed four wells from its BSNR pad located in De Soto Parish on production in September 2017, averaging 9,800-foot laterals. While these wells separately achieved peak rates ranging from 29,600 mcf to 37,200 mcf of gas per day, the combined peak rate from the BSNR pad reached approximately 134,000 mcf of gas per day. In October, the company also placed three wells from its PKY pad on production, all with 8,500-foot laterals, which achieved a combined peak rate of approximately 95,000 mcf of gas per day. As a result, last week Chesapeake's net production from the Haynesville reached 1 bcf of gas per day, which is the company's highest daily rate since November 2012. Additionally, Chesapeake expects to place on production its first 10,000-foot Bossier well, the Nabors 13&12-10-13 1HC, located in Sabine Parish in late November 2017 and intends to spud its first 15,000-foot lateral Haynesville well in the 2017 fourth quarter. The company expects to place on production up to seven wells in the Haynesville in the 2017 fourth quarter.
In the Mid-Continent, Chesapeake recently drilled and completed a 10,000-foot lateral well with an enhanced completion design on the Bravo 1H well in Major County, yielding an average production rate of approximately 1,550 bbls of oil per day and an average total production rate of 1,960 boe per day over the first 10 days.
Key Financial and Operational
Results
The table below summarizes
Chesapeake's key financial and
operational results during the
2017 third quarter compared to
results in prior periods.
Three Months Ended
09/30/17 06/30/17 09/30/16
-------- -------- --------
Oil
equivalent
production
(in mmboe) 50 48 59
Oil
production
(in mmbbls) 8 8 8
Average
realized oil
price
($/bbl)(a) 52.33 51.65 45.24
Natural gas
production
(in bcf) 219 209 268
Average
realized
natural gas
price
($/mcf)(a) 2.52 2.71 2.13
NGL
production
(in mmbbls) 5 5 6
Average
realized NGL
price
($/bbl)(a) 21.26 18.51 13.70
Production
expenses
($/boe) 3.03 2.92 2.80
Gathering,
processing
and
transportation
expenses
($/boe) 7.40 7.44 8.07
Oil - ($/bbl) 4.33 3.70 3.67
Natural Gas -
($/mcf) 1.34 1.37 1.47
NGL - ($/bbl) 7.40 7.87 8.13
Production
taxes
($/boe) 0.43 0.42 0.29
General and
administrative
expenses
($/boe)(b) 0.91 1.20 0.90
Stock-based
compensation
($/boe) 0.17 0.25 0.18
DD&A of oil
and natural
gas
properties
($/boe) 4.57 4.21 4.26
DD&A of other
assets
($/boe) 0.41 0.43 0.42
Interest
expense
($/boe)(a) 2.26 1.92 1.20
Marketing,
gathering
and
compression
net margin
($ in
millions)(c) (14) (25) (162)
Net cash
provided by
(used in)
operating
activities
($ in
millions) 331 (157) 376
Net cash
provided by
(used in)
operating
activities
($/boe) 6.62 (3.27) 6.37
Operating
cash flow ($
in
millions)(d) 337 316 214
Operating
cash flow
($/boe) 6.74 6.58 3.63
Adjusted
ebitda ($ in
millions)(e) 468 461 421
Adjusted
ebitda
($/boe) 9.36 9.60 7.17
Net income
(loss)
available to
common
stockholders
($ in
millions) (41) 470 (1,257)
Income (loss)
per share -
diluted ($) (0.05) 0.47 (1.62)
Adjusted net
income
(loss)
attributable
to
Chesapeake
($ in
millions)(f) 106 146 73
Adjusted
income
(loss) per
share -
diluted
($)(g) 0.12 0.18 0.09
(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 and
restructuring and other termination
costs.
(c) Includes revenue, operating expenses
and for the three months ended
September 30, 2016, unrealized
losses on supply contract
derivatives, but excludes
depreciation and amortization of
other assets. For the three months
ended September 30, 2016,
unrealized losses on supply
contract derivatives were $280
million. No other period presented
had such gains (losses).
(d) Defined as cash flow provided by
operating activities before changes
in assets and liabilities.
(e) 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.
(f) Defined as net income (loss)
attributable to Chesapeake, as
adjusted to remove the effects of
certain items detailed on pages 12
-15.
(g) Our presentation of diluted adjusted
net income (loss) per share
excludes shares considered
antidilutive when calculating
diluted earnings per share in
accordance with GAAP.
2017 Third Quarter Financial and Operational Results Conference Call Information
A conference call to discuss this release has been scheduled on Thursday, November 2, 2017 at 9:00 am EDT. The telephone number to access the conference call is 719-785-1749 or toll-free 888-855-5428. The passcode for the call is 9224968. The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112 and the passcode for the replay is 9224968. The conference call will be webcast and can be found at www.chk.com in the "Investors" section of the company's website. The webcast of the conference will be available on the website for one year.
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. The company also owns oil and natural gas marketing and natural gas compression businesses.
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, general and administrative expenses, capital expenditures, the timing of anticipated asset sales and proceeds to be received therefrom, projected cash flow and liquidity, our ability to enhance our cash flow and financial flexibility, plans and objectives for future operations (including our ability to optimize base production and execute gas gathering, processing and transportation commitments), 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; potential challenges by Seventy Seven Energy Inc.'s (SSE) former creditors in connection with SSE's recently completed bankruptcy under Chapter 11 of the U.S. Bankruptcy Code; an interruption in operations at our headquarters due to a catastrophic event; the continuation of suspended dividend payments on our common stock; the effectiveness of our remediation plan for a material weakness; 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
September 30,
-------------
2017 2016
---- ----
REVENUES:
Oil, natural gas and NGL $979 $1,177
Marketing, gathering and compression 964 1,099
-----
Total Revenues 1,943 2,276
----- -----
OPERATING EXPENSES:
Oil, natural gas and NGL production 151 164
Oil, natural gas and NGL gathering,
processing and transportation 369 473
Production taxes 21 17
Marketing, gathering and compression 978 1,261
General and administrative 54 63
Provision for legal contingencies 20 8
Oil, natural gas and NGL depreciation,
depletion and amortization 228 251
Depreciation and amortization of other
assets 20 25
Impairment of oil and natural gas
properties - 497
Impairments of fixed assets and other 9 751
Net gains on sales of fixed assets (1) -
--- ---
Total Operating Expenses 1,849 3,510
----- -----
INCOME (LOSS) FROM OPERATIONS 94 (1,234)
--- ------
OTHER INCOME (EXPENSE):
Interest expense (114) (73)
Losses on investments - (1)
Gains (losses) on purchases or exchanges
of debt (1) 87
Other income 4 7
--- ---
Total Other Income (Expense) (111) 20
---
LOSS BEFORE INCOME TAXES (17) (1,214)
--- ------
Income Tax Expense - -
--- ---
NET LOSS (17) (1,214)
Net income attributable to
noncontrolling interests (1) (1)
--- ---
NET LOSS ATTRIBUTABLE TO CHESAPEAKE (18) (1,215)
--- ------
Preferred stock dividends (23) (42)
NET LOSS AVAILABLE TO COMMON
STOCKHOLDERS $(41) $(1,257)
==== =======
LOSS PER COMMON SHARE:
Basic $(0.05) $(1.62)
====== ======
Diluted $(0.05) $(1.62)
====== ======
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in
millions):
Basic 909 777
=== ===
Diluted 909 777
=== ===
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ in millions except per share data)
(unaudited)
Nine Months Ended
September 30,
-------------
2017 2016
---- ----
REVENUES:
Oil, natural gas and NGL $3,727 $2,610
Marketing, gathering and compression 3,250 3,241
-----
Total Revenues 6,977 5,851
----- -----
OPERATING EXPENSES:
Oil, natural gas and NGL production 426 552
Oil, natural gas and NGL gathering,
processing and transportation 1,081 1,436
Production taxes 64 54
Marketing, gathering and compression 3,333 3,410
General and administrative 189 172
Restructuring and other termination
costs - 3
Provision for legal contingencies 35 112
Oil, natural gas and NGL depreciation,
depletion and amortization 627 791
Depreciation and amortization of other
assets 62 83
Impairment of oil and natural gas
properties - 2,564
Impairments of fixed assets and other 426 795
Net gains on sales of fixed assets - (5)
--- ---
Total Operating Expenses 6,243 9,967
----- -----
INCOME (LOSS) FROM OPERATIONS 734 (4,116)
--- ------
OTHER INCOME (EXPENSE):
Interest expense (302) (197)
Losses on investments - (3)
Loss on sale of investment - (10)
Gains on purchases or exchanges of debt 183 255
Other income 6 13
--- ---
Total Other Income (Expense) (113) 58
---
INCOME (LOSS) BEFORE INCOME TAXES 621 (4,058)
--- ------
Income Tax Expense 2 -
--- ---
NET INCOME (LOSS) 619 (4,058)
Net income attributable to
noncontrolling interests (3) (1)
--- ---
NET INCOME (LOSS) ATTRIBUTABLE TO
CHESAPEAKE 616 (4,059)
--- ------
Preferred stock dividends (62) (127)
Loss on exchange of preferred stock (41) -
Earnings allocated to participating
securities (7) -
---
NET INCOME (LOSS) AVAILABLE TO COMMON
STOCKHOLDERS $506 $(4,186)
==== =======
EARNINGS (LOSS) PER COMMON SHARE:
Basic $0.56 $(5.80)
===== ======
Diluted $0.56 $(5.80)
===== ======
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in
millions):
Basic 908 722
=== ===
Diluted 908 722
=== ===
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
($ in millions)
(unaudited)
September 30, December 31,
2017 2016
---- ----
Cash and cash equivalents $5 $882
Other current assets 1,173 1,260
-----
Total Current Assets 1,178 2,142
----- -----
Property and equipment, net 10,580 10,609
Other assets 223 277
--- ---
Total Assets $11,981 $13,028
======= =======
Current liabilities $2,218 $3,648
Long-term debt, net 9,899 9,938
Other long-term liabilities 568 645
Total Liabilities 12,685 14,231
------ ------
Preferred stock 1,671 1,771
Noncontrolling interests 253 257
Common stock and other
stockholders' equity (deficit) (2,628) (3,231)
------ ------
Total Equity (Deficit) (704) (1,203)
---- ------
Total Liabilities and Equity $11,981 $13,028
======= =======
Common shares outstanding (in
millions) 909 896
=== ===
Principal amount of debt
outstanding $9,775 $9,989
====== ======
CHESAPEAKE ENERGY CORPORATION
SUPPLEMENTAL DATA - OIL, NATURAL GAS AND NGL PRODUCTION, SALES AND INTEREST EXPENSE
(unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
------------- -------------
2017 2016 2017 2016
---- ---- ---- ----
Net Production:
Oil (mmbbl) 8 8 23 25
Natural gas (bcf) 219 268 639 814
NGL (mmbbl) 5 6 15 19
Oil equivalent (mmboe) 50 59 145 180
Oil, natural gas and NGL Sales ($
in millions):
Oil sales $379 $342 $1,140 $952
Oil derivatives - realized gains
(losses)(a) 35 18 79 102
Oil derivatives - unrealized
gains (losses)(a) (96) 23 45 (217)
Total oil sales 318 383 1,264 837
--- --- ----- ---
Natural gas sales 553 622 1,807 1,545
Natural gas derivatives -
realized gains (losses)(a) (1) (50) (53) 192
Natural gas derivatives -
unrealized gains (losses)(a) (3) 131 384 (204)
--- --- --- ----
Total natural gas sales 549 703 2,138 1,533
--- --- ----- -----
NGL sales 117 84 328 247
NGL derivatives - realized gains
(losses)(a) (3) (2) (1) (5)
NGL derivatives - unrealized
gains (losses)(a) (2) 9 (2) (2)
--- ---
Total NGL sales 112 91 325 240
--- --- --- ---
Total oil, natural gas and NGL
sales $979 $1,177 $3,727 $2,610
==== ====== ====== ======
Average Sales Price
(excluding gains (losses) on
derivatives):
Oil ($ per bbl) $47.94 $42.94 $48.53 $38.21
Natural gas ($ per mcf) $2.52 $2.32 $2.83 $1.90
NGL ($ per bbl) $21.83 $13.93 $21.28 $12.90
Oil equivalent ($ per boe) $21.06 $17.86 $22.53 $15.27
Average Sales Price
(including realized gains
(losses) on derivatives):
Oil ($ per bbl) $52.33 $45.24 $51.90 $42.31
Natural gas ($ per mcf) $2.52 $2.13 $2.75 $2.13
NGL ($ per bbl) $21.26 $13.70 $21.21 $12.66
Oil equivalent ($ per boe) $21.67 $17.30 $22.70 $16.88
Interest Expense ($ in millions):
Interest expense(b) $115 $74 $302 $199
Interest rate derivatives -
realized (gains) losses(c) (1) (3) (3) (9)
Interest rate derivatives -
unrealized (gains) losses(c) - 2 3 7
Total Interest Expense $114 $73 $302 $197
==== === ==== ====
(a) Realized gains (losses) include
the following items: (i)
settlements and accruals for
settlements of undesignated
derivatives related to current
period production revenues, (ii)
prior period settlements for
option premiums and for early-
terminated derivatives originally
scheduled to settle against
current period production
revenues, and (iii) gains and
losses related to de-designated
cash flow hedges originally
designated to settle against
current period production
revenues. Unrealized gains
(losses) include the change in
fair value of open derivatives
scheduled to settle against
future period production revenues
(including current period
settlements for option premiums
and early terminated derivatives)
offset by amounts reclassified as
realized gains and losses during
the period. Although we no longer
designate our derivatives as cash
flow hedges for accounting
purposes, we believe these
definitions are useful to
management and investors in
determining the effectiveness of
our price risk management
program.
(b) Net of amounts capitalized.
(c) Realized (gains) losses include
settlements related to the
current period interest accrual
and the effect of (gains) losses
on early termination trades.
Unrealized (gains) losses include
changes in the fair value of open
interest rate derivatives offset
by amounts reclassified to
realized (gains) losses during
the period.
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
($ in millions)
(unaudited)
THREE MONTHS ENDED: September 30, September 30,
2017 2016
--- ---- ----
Beginning cash $13 $4
--- ---
Net cash provided by operating
activities 331 376
---
Cash flows from investing
activities:
Drilling and completion costs(a) (566) (339)
Acquisitions of proved and unproved
properties(b) (64) (157)
Proceeds from divestitures of
proved and unproved properties 242 24
Additions to other property and
equipment(c) (5) (7)
Proceeds from sales of other
property and equipment 14 -
Other - (1)
--- ---
Net cash used in investing
activities (379) (480)
---- ----
Net cash provided by financing
activities 40 104
--- ---
Change in cash and cash equivalents (8) -
--- ---
Ending cash $5 $4
=== ===
(a) Includes capitalized interest of $2
million and $1 million for the
three months ended September 30,
2017 and 2016, respectively.
(b) Includes capitalized interest of $47
million and $56 million for the
three months ended September 30,
2017 and 2016, respectively.
(c) Includes capitalized interest of a
nominal amount for the three months
ended September 30, 2017 and 2016,
respectively.
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
($ in millions)
(unaudited)
NINE MONTHS ENDED: September 30, September 30,
2017 2016
--- ---- ----
Beginning cash $882 $825
---- ----
Net cash provided by operating
activities 273 50
--- ---
Cash flows from investing
activities:
Drilling and completion costs(a) (1,597) (948)
Acquisitions of proved and unproved
properties(b) (226) (583)
Proceeds from divestitures of
proved and unproved properties 1,193 988
Additions to other property and
equipment(c) (12) (32)
Proceeds from sales of other
property and equipment 40 70
Cash paid for title defects - (69)
Other - (5)
--- ---
Net cash used in investing
activities (602) (579)
---- ----
Net cash used in financing
activities (548) (292)
---- ----
Change in cash and cash equivalents (877) (821)
---- ----
Ending cash $5 $4
=== ===
(a) Includes capitalized interest of $7
million and $5 million for the nine
months ended September 30, 2017 and
2016, respectively.
(b) Includes capitalized interest of
$139 million and $179 million for
the nine months ended September 30,
2017 and 2016, respectively.
(c) Includes capitalized interest of $1
million and $1 million for the nine
months ended September 30, 2017 and
2016, respectively.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS
($ in millions except per share data)
(unaudited)
THREE MONTHS ENDED: September 30, 2017
------------------- ------------------
$ $/Diluted
Share(b)(c)
----------
Net loss available to common
stockholders (GAAP) $(41) $(0.05)
Adjustments:
Unrealized losses on commodity
derivatives 101 0.12
Provision for legal contingencies 20 0.02
Impairments of fixed assets and other 9 0.01
Net gains on sales of fixed assets (1) -
Losses on purchases or exchanges of
debt 1 -
Income tax expense (benefit)(a) - -
Other (6) (0.01)
Adjusted net income available to common
stockholders(b) 83 0.09
(Non-GAAP)
Preferred stock dividends 23 0.03
---
Total adjusted net income attributable
to Chesapeake(b) (c) (Non-GAAP) $106 $0.12
==== =====
(a) Due to our
valuation
allowance
position, no
income tax effect
from the
adjustments has
been included in
determining
adjusted net
income.
(b) Adjusted net
income (loss)
available to
common
stockholders and
total adjusted
net income (loss)
attributable to
Chesapeake, both
in the aggregate
and per dilutive
share, are not
measures of
financial
performance under
accounting
principles
generally
accepted in the
United States
(GAAP), and
should not be
considered as an
alternative to
net income (loss)
available to
common
stockholders or
earnings (loss)
per share.
Adjusted net
income (loss)
available to
common
stockholders and
adjusted earnings
(loss) per share
exclude certain
items that
management
believes affect
the comparability
of operating
results. The
company believes
these adjusted
financial
measures are a
useful adjunct to
earnings
calculated in
accordance with
GAAP because:
(i) Management uses adjusted net
income (loss) available to
common stockholders to evaluate
the company's operational trends
and performance relative to
other oil and natural gas
producing companies.
(ii) Adjusted net income (loss)
available to common stockholders
is more comparable to earnings
estimates provided by securities
analysts.
(iii) Items excluded generally are one-
time items or items whose timing
or amount cannot be reasonably
estimated. Accordingly, any
guidance provided by the company
generally excludes information
regarding these types of items.
(c) Our presentation
of diluted
adjusted net
income (loss) per
share excludes
206 million
shares considered
antidilutive when
calculating
diluted earnings
per share in
accordance with
GAAP.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS
($ in millions except per share data)
(unaudited)
THREE MONTHS ENDED: September 30, 2016
------------------- ------------------
$ $/Diluted
Share(b)(c)
----------
Net loss available to common
stockholders (GAAP) $(1,257) $(1.62)
Adjustments:
Unrealized gains on commodity
derivatives (163) (0.21)
Unrealized losses on supply contract
derivatives 280 0.36
Provision for legal contingencies 8 0.01
Impairment of natural gas properties 497 0.64
Impairments of fixed assets and other 751 0.97
Gains on purchases or exchanges of debt (87) (0.11)
Income tax expense (benefit)(a) - -
Other 2 -
Adjusted net income available to common
stockholders(b) 31 0.04
(Non-GAAP)
Preferred stock dividends 42 0.05
Total adjusted net income attributable
to Chesapeake(b) (c) (Non-GAAP) $73 $0.09
=== =====
(a) Due to our
valuation
allowance
position, no
income tax effect
from the
adjustments has
been included in
determining
adjusted net
income.
(b) Adjusted net
income (loss)
available to
common
stockholders and
total adjusted
net income (loss)
attributable to
Chesapeake, both
in the aggregate
and per dilutive
share, are not
measures of
financial
performance under
accounting
principles
generally
accepted in the
United States
(GAAP), and
should not be
considered as an
alternative to
net income (loss)
available to
common
stockholders or
earnings (loss)
per share.
Adjusted net
income (loss)
available to
common
stockholders and
adjusted earnings
(loss) per share
exclude certain
items that
management
believes affect
the comparability
of operating
results. The
company believes
these adjusted
financial
measures are a
useful adjunct to
earnings
calculated in
accordance with
GAAP because:
(i) Management uses adjusted net
income (loss) available to
common stockholders to evaluate
the company's operational trends
and performance relative to
other oil and natural gas
producing companies.
(ii) Adjusted net income (loss)
available to common stockholders
is more comparable to earnings
estimates provided by securities
analysts.
(iii) Items excluded generally are one-
time items or items whose timing
or amount cannot be reasonably
estimated. Accordingly, any
guidance provided by the company
generally excludes information
regarding these types of items.
(c) Our presentation
of diluted
adjusted net
income (loss) per
share excludes
113 million
shares considered
antidilutive when
calculating
diluted earnings
per share in
accordance with
GAAP.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS
($ in millions except per share data)
(unaudited)
NINE MONTHS ENDED: September 30, 2017
------------------ ------------------
$ $/Diluted
Share(b)(c)
----------
Net income available to common stockholders (GAAP) $506 $0.56
Adjustments:
Unrealized gains on commodity derivatives (427) (0.47)
Provision for legal contingencies 35 0.04
Impairments of fixed assets and other 426 0.47
Gains on purchases or exchanges of debt (183) (0.21)
Loss on exchange of preferred stock 41 0.05
Income tax expense (benefit)(a) - -
Other (3) -
Adjusted net income available to common stockholders(b) 395 0.44
(Non-GAAP)
Preferred stock dividends 62 0.07
Earnings allocated to participating securities 7 -
---
Total adjusted net income attributable to Chesapeake(b) (c) $464 $0.51
(Non-GAAP)
(a) Due to our
valuation
allowance
position, no
income tax effect
from the
adjustments has
been included in
determining
adjusted net
income.
(b) Adjusted net
income (loss)
available to
common
stockholders and
total adjusted
net income (loss)
attributable to
Chesapeake, both
in the aggregate
and per dilutive
share, are not
measures of
financial
performance under
accounting
principles
generally
accepted in the
United States
(GAAP), and
should not be
considered as an
alternative to
net income (loss)
available to
common
stockholders or
earnings (loss)
per share.
Adjusted net
income (loss)
available to
common
stockholders and
adjusted earnings
(loss) per share
exclude certain
items that
management
believes affect
the comparability
of operating
results. The
company believes
these adjusted
financial
measures are a
useful adjunct to
earnings
calculated in
accordance with
GAAP because:
(i) Management uses adjusted net
income (loss) available to
common stockholders to evaluate
the company's operational trends
and performance relative to
other oil and natural gas
producing companies.
(ii) Adjusted net income (loss)
available to common stockholders
is more comparable to earnings
estimates provided by securities
analysts.
(iii) Items excluded generally are one-
time items or items whose timing
or amount cannot be reasonably
estimated. Accordingly, any
guidance provided by the company
generally excludes information
regarding these types of items.
(c) Our presentation
of diluted
adjusted net
income (loss) per
share excludes
207 million
shares considered
antidilutive when
calculating
diluted earnings
per share in
accordance with
GAAP.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS
($ in millions except per share data)
(unaudited)
NINE MONTHS ENDED: September 30, 2016
------------------ ------------------
$ $/Diluted
Share(b)(c)
----------
Net loss available to common stockholders (GAAP) $(4,186) (5.80)
Adjustments:
Unrealized losses on commodity derivatives 423 0.58
Unrealized losses on supply contract derivatives 297 0.41
Restructuring and other termination costs 3 -
Provision for legal contingencies 112 0.16
Impairment of natural gas properties 2,564 3.56
Impairments of fixed assets and other 795 1.10
Net gains on sales of fixed assets (5) (0.01)
Loss on sale of investment 10 0.01
Gains on purchases or exchanges of debt (255) (0.35)
Income tax expense (benefit)(a) - -
Other 8 0.01
Adjusted net loss available to common stockholders(b) (234) (0.33)
(Non-GAAP)
Preferred stock dividends 127 0.18
Total adjusted net loss attributable to Chesapeake(b) (c) $(107) $(0.15)
(Non-GAAP)
(a) Due to our
valuation
allowance
position, no
income tax effect
from the
adjustments has
been included in
determining
adjusted net
income.
(b) Adjusted net
income (loss)
available to
common
stockholders and
total adjusted
net income (loss)
attributable to
Chesapeake, both
in the aggregate
and per dilutive
share, are not
measures of
financial
performance under
accounting
principles
generally
accepted in the
United States
(GAAP), and
should not be
considered as an
alternative to
net income (loss)
available to
common
stockholders or
earnings (loss)
per share.
Adjusted net
income (loss)
available to
common
stockholders and
adjusted earnings
(loss) per share
exclude certain
items that
management
believes affect
the comparability
of operating
results. The
company believes
these adjusted
financial
measures are a
useful adjunct to
earnings
calculated in
accordance with
GAAP because:
(i) Management uses adjusted net
income (loss) available to
common stockholders to evaluate
the company's operational trends
and performance relative to
other oil and natural gas
producing companies.
(ii) Adjusted net income (loss)
available to common stockholders
is more comparable to earnings
estimates provided by securities
analysts.
(iii) Items excluded generally are one-
time items or items whose timing
or amount cannot be reasonably
estimated. Accordingly, any
guidance provided by the company
generally excludes information
regarding these types of items.
(c) Our presentation
of diluted
adjusted net
income (loss) per
share excludes
113 million
shares considered
antidilutive when
calculating
diluted earnings
per share in
accordance with
GAAP.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
($ in millions)
(unaudited)
THREE MONTHS ENDED: September 30, September 30,
2017 2016
--- ---- ----
CASH PROVIDED BY OPERATING
ACTIVITIES $331 $376
Changes in assets and
liabilities 6 (162)
--- ----
OPERATING CASH FLOW(a) $337 $214
==== ====
THREE MONTHS ENDED: September 30, September 30,
2017 2016
--- ---- ----
NET LOSS $(17) $(1,214)
Interest expense 114 73
Depreciation and amortization
of other assets 20 25
Oil, natural gas and NGL
depreciation, depletion and
amortization 228 251
--- ---
EBITDA(b) $345 $(865)
==== =====
THREE MONTHS ENDED: September 30, September 30,
2017 2016
--- ---- ----
CASH PROVIDED BY OPERATING
ACTIVITIES $331 $376
Changes in assets and
liabilities 6 (162)
Interest expense, net of
unrealized gains (losses) on
derivatives 114 71
Gains (losses) on commodity
derivatives, net (70) 129
Losses on supply contract
derivatives, net - (134)
Cash receipts on commodity
and supply contract
derivative settlements,
net (20) (101)
Renegotiation of gas
gathering contract - 66
Stock-based compensation (11) (15)
Restructuring and other
termination costs - 1
Provision for legal
contingencies (20) 27
Impairment of oil and natural
gas properties - (497)
Impairments of fixed assets
and other (8) (751)
Net gains on sales of fixed
assets 1 -
Investment activity - (1)
Gains on purchases or
exchanges of debt - 87
Other items 22 39
--- ---
EBITDA(b) $345 $(865)
==== =====
(a) Operating cash flow represents net cash
provided by operating activities before
changes in assets and liabilities.
Operating cash flow is presented because
management believes it is a useful
adjunct to net cash provided by operating
activities under GAAP. Operating cash
flow is widely accepted as a financial
indicator of an oil and natural gas
company's ability to generate cash that
is used to internally fund exploration
and development activities and to service
debt. This measure is widely used by
investors and rating agencies in the
valuation, comparison, rating and
investment recommendations of companies
within the oil and natural gas
exploration and production industry.
Operating cash flow is not a measure of
financial performance under GAAP and
should not be considered as an
alternative to cash flows from operating
activities as an indicator of cash flows,
or as a measure of liquidity.
(b) EBITDA represents net income before
interest expense, income taxes, and
depreciation, depletion and amortization
expense. EBITDA is presented as a
supplemental financial measurement in the
evaluation of our business. We believe
that it provides additional information
regarding our ability to meet our future
debt service, capital expenditures and
working capital requirements. This
measure is widely used by investors and
rating agencies in the valuation,
comparison, rating and investment
recommendations of companies. EBITDA is
also a financial measurement that, with
certain negotiated adjustments, is
reported to our lenders pursuant to our
bank credit agreements and is used in the
financial covenants in our bank credit
agreements. EBITDA is not a measure of
financial performance under GAAP.
Accordingly, it should not be considered
as a substitute for net income, income
from operations or cash flows from
operating activities prepared in
accordance with GAAP.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
($ in millions)
(unaudited)
NINE MONTHS ENDED: September 30, September 30,
2017 2016
--- ---- ----
CASH PROVIDED BY OPERATING
ACTIVITIES $273 $50
Changes in assets and
liabilities 366 614
--- ---
OPERATING CASH FLOW(a) $639 $664
==== ====
NINE MONTHS ENDED: September 30, September 30,
2017 2016
--- ---- ----
NET INCOME (LOSS) $619 $(4,058)
Interest expense 302 197
Income tax expense 2 -
Depreciation and amortization
of other assets 62 83
Oil, natural gas and NGL
depreciation, depletion and
amortization 627 791
--- ---
EBITDA(b) $1,612 $(2,987)
====== =======
NINE MONTHS ENDED: September 30, September 30,
2017 2016
--- ---- ----
CASH USED IN OPERATING
ACTIVITIES $273 $50
Changes in assets and
liabilities 366 614
Interest expense, net of
unrealized gains (losses) on
derivatives 299 190
Gains (losses) on commodity
derivatives, net 452 (134)
Losses on supply contract
derivatives, net - (151)
Cash (receipts) payments on
commodity and supply
contract derivative
settlements, net 46 (487)
Renegotiation of gas
gathering contract - 66
Stock-based compensation (38) (40)
Restructuring and other
termination costs - (1)
Provision for legal
contingencies (35) (77)
Impairment of oil and natural
gas properties - (2,564)
Impairments of fixed assets
and other (9) (785)
Net gains on sales of fixed
assets - 5
Investment activity - (13)
Gains on purchases or
exchanges of debt 185 255
Other items 73 85
--- ---
EBITDA(b) $1,612 $(2,987)
====== =======
(a) Operating cash flow represents net cash
provided by operating activities before
changes in assets and liabilities.
Operating cash flow is presented because
management believes it is a useful
adjunct to net cash provided by operating
activities under GAAP. 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. Operating
cash flow for the nine months ended
September 30, 2017 includes $290 million
paid to assign an oil transportation
agreement to a third party and $126
million paid to terminate future natural
gas transportation commitments.
(b) EBITDA represents net income before
interest expense, income taxes, and
depreciation, depletion and amortization
expense. EBITDA is presented as a
supplemental financial measurement in the
evaluation of our business. We believe
that it provides additional information
regarding our ability to meet our future
debt service, capital expenditures and
working capital requirements. This
measure is widely used by investors and
rating agencies in the valuation,
comparison, rating and investment
recommendations of companies. EBITDA is
also a financial measurement that, with
certain negotiated adjustments, is
reported to our lenders pursuant to our
bank credit agreements and is used in the
financial covenants in our bank credit
agreements. EBITDA is not a measure of
financial performance under GAAP.
Accordingly, it should not be considered
as a substitute for net income, income
from operations or cash flows from
operating activities prepared in
accordance with GAAP.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED EBITDA
($ in millions)
(unaudited)
THREE MONTHS
ENDED: September 30, September 30,
2017 2016
--- ---- ----
EBITDA $345 $(865)
Adjustments:
Unrealized
(gains) losses
on commodity
derivatives 101 (163)
Unrealized
losses on
supply
contract
derivatives - 280
Provision for
legal
contingencies 20 8
Impairment of
oil and
natural gas
properties - 497
Impairments of
fixed assets
and other 9 751
Net gains on
sales of fixed
assets (1) -
(Gains) losses
on purchases
or exchanges
of debt 1 (87)
Net income
attributable
to
noncontrolling
interests (1) (1)
Other (6) 1
--- ---
Adjusted
EBITDA(a) $468 $421
==== ====
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED EBITDA
($ in millions)
(unaudited)
NINE MONTHS ENDED: September 30, September 30,
2017 2016
--- ---- ----
EBITDA $1,612 $(2,987)
Adjustments:
Unrealized (gains) losses on
commodity derivatives (427) 423
Unrealized losses on supply
contract derivatives - 297
Restructuring and other
termination costs - 3
Provision for legal contingencies 35 112
Impairment of oil and natural gas
properties - 2,564
Impairments of fixed assets and
other 426 795
Net gains on sales of fixed assets - (5)
Loss on sale of investment - 10
Gains on purchases or exchanges of
debt (183) (255)
Net income attributable to
noncontrolling interests (3) (1)
Other (6) (1)
--- ---
Adjusted EBITDA(a) $1,454 $955
====== ====
(a) 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.
Accordingly, adjusted EBITDA
should not be considered as a
substitute for net income,
income from operations or cash
flow provided by operating
activities prepared in
accordance with GAAP.
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CHESAPEAKE ENERGY CORPORATION
MANAGEMENT'S OUTLOOK AS OF NOVEMBER 2, 2017
Chesapeake periodically provides guidance on
certain factors that affect the company's
future financial performance. New
information or changes from the company's
September 26, 2017 Outlook are italicized
bold below.
Year Ending
12/31/2017
----------
Adjusted Production Growth(a) (1%) to 1%
Absolute Production
Liquids - mmbbls 51.5 - 53.5
Oil - mmbbls 32.0 - 33.0
NGL - mmbbls 19.5 - 20.5
Natural gas - bcf 855 - 875
Total absolute production - mmboe 194.0 - 199.0
Absolute daily rate - mboe 532 - 545
Estimated Realized Hedging Effects(b)
(based on 10/30/17 strip prices):
Oil - $/bbl $2.61
Natural gas - $/mcf $0.00
NGL - $/bbl ($0.20)
Estimated Basis to NYMEX Prices:
Oil - $/bbl $0.45 - $0.55
Natural gas - $/mcf $0.30 - $0.35
NGL - $/bbl $3.75 - $4.15
Operating Costs per Boe of Projected
Production:
Production expense $2.80 - $2.95
Gathering, processing and transportation
expenses $7.15 - $7.40
Oil - $/bbl $3.90 - $4.00
Natural Gas - $/mcf $1.30 - $1.35
NGL - $/bbl $7.70 - $7.90
Production taxes $0.40 - $0.50
General and administrative(c) $1.10 - $1.20
Stock-based compensation (noncash) $0.10 - $0.20
DD&A of natural gas and liquids assets $4.00 - $5.00
Depreciation of other assets $0.40 - $0.50
Interest expense(d) $2.05 - $2.15
Marketing, gathering and compression net
margin(e) ($80) - ($60)
Book Tax Rate 0%
Capital Expenditures ($ in millions)(f) $2,100 - $2,300
Capitalized Interest ($ in millions) $200
Total Capital Expenditures ($ in millions) $2,300 - $2,500
(a) Based on 2016 production of 529 mboe
per day, adjusted for 2016 and 2017
sales.
(b) Includes expected settlements for
commodity 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.
(d) Excludes unrealized gains (losses)
on interest rate derivatives.
(e) Excludes non-cash amortization of
approximately $22 million related
to the buydown of a transportation
agreement.
(f) Includes capital expenditures for
drilling and completion, leasehold,
geological and geophysical costs,
rig termination payments and other
property and plant and equipment.
Excludes any additional proved
property acquisitions.
Oil, Natural Gas and Natural Gas Liquids Hedging Activities
Chesapeake enters into commodity 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, 2017, the company had downside protection, through open swaps, on a portion of its remaining 2017 oil production at an average price of $50.36 per bbl. The company had downside price protection, through open swaps and two-way collars, on a portion of its remaining 2017 natural gas production at an average price of $3.17 per mcf. Chesapeake also had downside price protection, through open swaps, on a portion of its remaining 2017 propane production at an average price of $0.76 per gallon.
In addition, the company had downside protection, through open swaps and two-way collars, on a portion of its 2018 natural gas production at an average price of $3.10 per mcf. Chesapeake also had downside price protection through open swaps on a portion of its 2018 oil production at an average price of $51.74 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 $39.15 per bbl.
The company's crude oil hedging positions as of October 31, 2017 were as follows:
Open Crude Oil Swaps
Gains (Losses) from Closed Crude Oil Trades
Open Swaps Avg. NYMEX Gains/Losses
from Closed
(mbbls) Price of Trades
Open Swaps ($ in
millions)
---------- ----------
Q4
2017 5,612 $50.36 23
Total
2017 5,612 $50.36 $23
===== ====== ===
Q1
2018 5,099 $51.84 $(1)
Q2
2018 5,187 $51.85 (1)
Q3
2018 4,324 $51.63 (1)
Q4
2018 4,324 $51.63 (1)
Total
2018 18,934 $51.74 $(4)
====== ====== ===
Total
2019
-
2022 - $ - $(8)
=== === === ===
Crude Oil Net Written Call Options
Call Options Avg. NYMEX
(mbbls) Strike Price
------ ------------
Q4 2017 1,334 $83.50
----- ------
Total 2017 1,334 $83.50
===== ======
Q3 2018 920 $52.87
Q4 2018 920 $52.87
--- ------
Total 2018 1,840 $52.87
===== ======
Crude Oil Three-Way Collars
Open Collars Avg. NYMEX Avg. NYMEX Avg. NYMEX
(mmbbls) Sold Put Price Bought Put Price Sold Call Price
------- -------------- ---------------- ---------------
Q1
2018 450 $39.15 $47.00 $55.00
Q2
2018 455 $39.15 $47.00 $55.00
Q3
2018 460 $39.15 $47.00 $55.00
Q4
2018 460 $39.15 $47.00 $55.00
--- ------ ------
Total
2018 1,825 $39.15 $47.00 $55.00
===== ====== ====== ======
Oil Basis Protection Swaps
Volume Avg. NYMEX
(mmbbls) plus/(minus)
------- ------------
Q4 2017 1 $3.15
--- -----
Total 2017 1 $3.15
=== =====
Q1 2018 2 $3.12
Q1 2018 2 $3.12
Q3 2018 2 $3.28
Q4 2018 2 $3.28
--- -----
Total 2018 8 $3.19
=== =====
The company's natural gas hedging positions as of October 31, 2017 were as follows:
Open Natural Gas Swaps
Losses from Closed Natural Gas Trades
Open Swaps Avg. NYMEX Losses
(bcf) Price of from Closed Trades
Open Swaps ($ in millions)
---------- --------------
Q4
2017 164 $3.16 (3)
--- ----- ---
Total
2017 164 $3.16 $(3)
=== ===== ===
Q1
2018 174 $3.44 $(6)
Q1
2018 118 $2.92 (4)
Q3
2018 120 $2.94 (4)
Q4
2018 120 $3.00 (6)
--- -----
Total
2018 532 $3.11 $(20)
=== ===== ====
Total
2019
-
2022 - $ - $(49)
=== === === ====
Natural Gas Two-Way Collars
Open Collars Avg. NYMEX Avg. NYMEX
(bcf) Bought Put Sold Call
Price Price
---- ---------- ----------
Q4 2017 24 $3.25 $3.68
Total 2017 24 $3.25 $3.68
=== ===== =====
Q1 2018 11 $3.00 $3.25
Q2 2018 12 $3.00 $3.25
Q3 2018 12 $3.00 $3.25
Q4 2018 12 $3.00 $3.25
--- ----- -----
Total 2018 47 $3.00 $3.25
=== ===== =====
Natural Gas Net Written Call Options
Call Options Avg. NYMEX
(bcf) Strike Price
---- ------------
Q4 2017 12 $9.43
--- -----
Total 2017 12 $9.43
=== =====
Q1 2018 16 $6.27
Q4 2018 16 $6.27
Q3 2018 17 $6.27
Q4 2018 17 $6.27
--- -----
Total 2018 66 $6.27
=== =====
Total 2019 - 2020 44 $12.00
=== ======
Natural Gas Basis Protection Swaps
Volume Avg. NYMEX
plus/(minus)
(bcf)
----
Q4 2017 17 $(0.66)
--- ------
Total 2017 17 $(0.66)
=== ======
Q1 2018 18 $(0.78)
Q4 2018 18 $(0.77)
Q3 2018 17 $(0.77)
Q4 2018 6 $(0.77)
--- ------
Total 2018 59 $(0.78)
=== ======
The company's natural gas liquids hedging positions as of October 31, 2017 were as follows:
Open Propane Swaps
Volume Avg. NYMEX Price
of Open Swaps
(mmgal)
------
Q4 2017 15 $0.76
Total 2017 15 $0.76
=== =====
Q1 2018 3 $0.73
Q4 2018 4 $0.73
Q3 2018 4 $0.73
Q4 2018 4 $0.73
--- -----
Total 2018 15 $0.73
=== =====
Open Butane Swaps
Volume Avg. NYMEX
Price of Open
(mmgal) Swaps
------ -----
Q1 2018 1 $0.88
Q4 2018 1 $0.88
Q3 2018 1 $0.88
Q4 2018 1 $0.88
--- -----
Total 2018 5 $0.88
=== =====
Open Butane Swaps Priced as a Percentage of WTI
Volume Avg. NYMEX as a
(mmgal) % of WTI Open
Swaps
-----
Q1 2018 1 70.5%
Q4 2018 1 70.5%
Q3 2018 1 70.5%
Q4 2018 1 70.5%
--- ----
Total 2018 5 70.5%
=== ====
View original content:http://www.prnewswire.com/news-releases/chesapeake-energy-corporation-reports-2017-third-quarter-financial-and-operational-results-300548219.html
SOURCE Chesapeake Energy Corp.
