CHESAPEAKE ENERGY CORPORATION OKLAHOMA CITY, Nov. 4, 2015 /PRNewswire/ -- Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operational results for the 2015 third quarter. Highlights include:
-- Production averaged approximately 667,000 boe per day, an increase of 3%
year over year, adjusted for asset sales
-- Adjusted net loss of $0.05 per fully diluted share and adjusted ebitda
of $560 million
-- 2015 total production guidance increased to 670 - 680 mboe per day
-- 2015 production expense and general and administrative expense guidance
lowered significantly
-- 2015 capital guidance reduced to $3.4 - $3.9 billion
Doug Lawler, Chesapeake's Chief Executive Officer, commented, "The many actions that we have taken this quarter, including executing new gas gathering agreements, amending our revolving credit facility, reducing complexity and commitments and lowering our business costs, have significantly increased Chesapeake's ability to create additional value. Our focus on optimizing base production and continuing to generate efficiencies in the field drove a 3% increase in production compared to last year, adjusted for asset sales. In addition, the elimination of $200 million of annualized, controllable production and general and administrative expenses represents another step in our commitment to financial discipline."
Lawler continued, "We lowered our 2015 capital guidance to $3.4 to $3.9 billion and are prepared to execute on a significantly lower capital program in 2016. While the current price environment presents many challenges for our industry, we will continue focusing on our capital and operating cost efficiency, enhancing our cash flow and financial flexibility and optimizing our base production. The power of our people, the strength of our portfolio and our operational leadership will continue to create value for Chesapeake for the long term."
2015 Third Quarter Financial Results
For the 2015 third quarter, Chesapeake reported a net loss available to common stockholders of $4.695 billion, or $7.08 per fully diluted share, which compares to net income available to common stockholders of $169 million, or $0.26 per fully diluted share, in the 2014 third quarter. Items typically excluded by securities analysts in their earnings estimates reduced 2015 third quarter net income by approximately $4.612 billion on an after-tax basis and are presented on Page 12 of this release. The primary source of this reduction was a noncash impairment of the carrying value of Chesapeake's oil and natural gas properties largely resulting from significant decreases in the trailing 12-month average first-day-of-the-month oil and natural gas prices as of September 30, 2015, compared to June 30, 2015. Adjusting for this and other items, the 2015 third quarter net loss available to common stockholders was $83 million, or $0.05 per fully diluted share, which compares to adjusted net income available to common stockholders of $251 million, or $0.38 per fully diluted share, in the 2014 third quarter.
Adjusted ebitda was $560 million in the 2015 third quarter, compared to $1.236 billion in the 2014 third quarter. Operating cash flow was $476 million in the 2015 third quarter, compared to $1.293 billion in the 2014 third quarter. The year-over-year decreases in adjusted ebitda and operating cash flow were primarily the result of lower realized oil, natural gas and natural gas liquid (NGL) prices, partially offset by higher realized hedging gains and lower production expenses, general and administrative (G&A) expenses and production taxes.
Adjusted net income available to common stockholders, operating cash flow, ebitda and adjusted ebitda are non-GAAP financial measures. Reconciliations of these measures to comparable financial measures calculated in accordance with generally accepted accounting principles are provided on pages 12 - 17 of this release.
2015 Third Quarter Average Daily Production of 667,000 Boe Increased 3% Year Over Year, Adjusted for Asset Sales
Chesapeake's daily production for the 2015 third quarter averaged approximately 667,000 barrels of oil equivalent (boe), a year-over-year increase of 3% adjusted for asset sales. Average daily production in the 2015 third quarter consisted of approximately 114,100 barrels (bbls) of oil, 2.9 billion cubic feet (bcf) of natural gas and 76,200 bbls of NGL, which represent year-over-year increases of 4%, 2% and 7%, respectively, adjusted for asset sales. During the 2015 third quarter, the company had average curtailed production of approximately 51,000 boe per day. The company has increased its total 2015 production guidance to 670,000 - 680,000 boe per day, representing a 6% - 8% increase over 2014 results, adjusted for asset sales.
Capital Spending and Cost Overview
Chesapeake's 2015 third quarter drilling and completion capital expenditures decreased 41% sequentially to approximately $467 million, and capital expenditures for leasehold, geological and geophysical costs and other property, plant and equipment remained flat at approximately $57 million, for a total of approximately $524 million. Total 2015 third quarter capital expenditures of $623 million, including capitalized interest of $99 million, decreased 35% and 59% compared to 2015 second quarter and 2014 third quarter results, respectively, and are detailed in the table below. For 2015, the company has reduced its estimated total capital expenditures to $3.4 - $3.9 billion, compared to $3.5 - $4.0 billion as previously provided.
2015 2015 2014
Activity Comparison Q3 Q2 Q3
--- --- ---
Average operated rig count 18 26 69
Gross wells completed 84 121 309
Gross wells spud 81 109 296
Gross wells connected 112 173 311
===================== === === ===
Type of Cost ($ in millions)
Drilling and completion costs $467 $787 $1,241
Leasehold, G&G and other PP&E 57 56 110
----------------------------- ---
Subtotal capital spending $524 $843 $1,351
Capitalized interest 99 114 170
Total capital spending $623 $957 $1,521
====================== ==== ==== ======
Chesapeake's focus on cost discipline continued to generate reductions in production and G&A expenses. Production expenses during the 2015 third quarter were $4.09 per boe, while G&A expenses (including stock-based compensation) during the 2015 third quarter were $0.79 per boe. Combined production expenses and G&A expenses (including stock-based compensation) during the 2015 third quarter decreased 10% sequentially and 9% year over year.
A summary of the company's guidance for 2015 is provided in the Outlook dated November 4, 2015, beginning on Page 18.
Operational Results - Southern Division
Eagle Ford Shale (South Texas): Eagle Ford net production averaged approximately 108 thousand barrels of oil equivalent (mboe) per day (234 gross operated mboe per day) during the 2015 third quarter, an increase of 3% sequentially. Average completed well costs to date in 2015 are $5.3 million with an average completed lateral length of 6,000 feet and 21 frac stages, compared to the full-year 2014 average completed well cost of $5.9 million with an average completed lateral length of 5,850 feet and 18 frac stages. Chesapeake continues to realize significant efficiencies with longer laterals and larger completions in the area. Recent third quarter well results include the Rogers E-1H and Faith San Pedro F-4H wells, which had completed lateral lengths of 12,488 and 13,151 feet, respectively, and reached peak 24-hour production rates of 1,479 and 1,067 bbls of oil per day, respectively. These two long-lateral wells have an average field estimated completed well cost of $7.8 million each. The JEA Unit XIV LAS S 4H East Four Corners well was also completed in the third quarter using an enhanced design on a 4,611-foot completed lateral and reached a peak 24-hour rate of 1,311 bbls of oil per day. The field estimated completed well cost of this well is $4.8 million. The company placed 30 wells on production during the 2015 third quarter, compared to 89 wells in the 2014 third quarter. Chesapeake's operated rig count in the Eagle Ford averaged three rigs in the 2015 third quarter, and the company anticipates maintaining three operated rigs through the end of the year.
Haynesville Shale and Bossier Shales (Northwest Louisiana): Haynesville net production averaged approximately 636 million cubic feet of natural gas (mmcf) per day (1.03 gross operated bcf per day) during the 2015 third quarter, a decrease of 5% sequentially. Average completed well costs to date in 2015 are $7.7 million with an average completed lateral length of 5,000 feet and 14 frac stages, compared to the full-year 2014 average completed well cost of $8.4 million with an average completed lateral length of 4,900 feet and 14 frac stages. The company placed seven wells on production during the 2015 third quarter, compared to 14 wells in the 2014 third quarter. Operated rig count in the Haynesville averaged six rigs in the 2015 third quarter, and the company anticipates maintaining six operated rigs through the end of the year.
Mid-Continent: Mississippian Lime (Northern Oklahoma): Mississippian Lime net production averaged approximately 31 mboe per day (74 gross operated mboe per day) during the 2015 third quarter, a decrease of 1% sequentially. Average completed well costs to date in 2015 are $2.8 million with an average completed lateral length of 4,500 feet and nine frac stages, compared to the full-year 2014 average completed well cost of $3.0 million with an average completed lateral length of 4,450 feet and nine frac stages. During the 2015 third quarter, the company drilled a record lateral length of 9,395 feet in the JJJ 23-25-11 1H well, which is currently being completed. Chesapeake also drilled its first multi-lateral well in the Mississippian Lime. The Wilber 26-27-11 1H, which had dual laterals of 4,653 feet and 4,556 feet, is currently being completed. The company placed 13 wells on production during the 2015 third quarter, compared to 44 wells in the 2014 third quarter. Operated rig count in the Mississippian Lime averaged three rigs during the 2015 third quarter, and the company has released all operated rigs in the area through the end of the year.
Oklahoma STACK (Northwest and Central Oklahoma): The company has identified multiple stacked liquids-rich opportunities on its extensive Oklahoma STACK leasehold position, substantially all of which is held by production. During the 2015 third quarter, the company drilled its first two wells targeting the Meramec formation, and is currently drilling a third well, with encouraging results. The Rouce 4-17-10 1H, which has a completed lateral of 9,350 feet, was recently placed on production and has reached over 870 bbls of oil per day after three days. The Wittrock 16-16-9 1H has been drilled with a lateral length of 9,220 feet and is currently being completed. The Stangl 36-16-9 1H is currently drilling with a planned lateral length of 9,426 feet. The company intends to keep one operated rig in the STACK area through the end of the year.
Operational Results - Northern Division
Utica Shale (Eastern Ohio): Utica net production averaged approximately 106 mboe per day (183 gross operated mboe per day) during the 2015 third quarter, a decrease of 15% sequentially, as the company voluntarily curtailed approximately 20 net mboe per day during the quarter as a result of weak product pricing. During the 2015 fourth quarter, a new regional pipeline is expected to be placed in-service, allowing the company to move an additional 350 mmcf per day out of the basin and greater access to Gulf Coast pricing. Average completed well costs to date in 2015 are $7.7 million with an average completed lateral length of 7,900 feet and 40 frac stages, compared to the full-year 2014 average completed well cost of $7.2 million with an average completed lateral length of 6,200 feet and 29 frac stages. During the 2015 third quarter, the company drilled a new record lateral length in the Utica of 12,976 feet. Additionally, the average cycle time for Utica wells drilled in the third quarter was 9.9 days, with a record cycle time of 6.8 days. Operated rig count in the Utica averaged two rigs in the 2015 third quarter, and the company anticipates maintaining two operated rigs through the end of the year.
Marcellus Shale (Northern Pennsylvania): Marcellus net production averaged approximately 809 mmcf per day (1.77 gross operated bcf per day) during the 2015 third quarter, a decrease of 1% sequentially. Chesapeake has been voluntarily curtailing production from the area since the 2015 first quarter, primarily due to weak in-basin gas prices. The company anticipates maintaining Marcellus curtailments for the remainder of the year and actively managing its production through the winter months. Average completed well costs to date in 2015 are $6.4 million with an average completed lateral length of 6,800 feet and 29 frac stages, compared to the full-year 2014 average completed well cost of $7.5 million with an average completed lateral length of 6,000 feet and 27 frac stages. Recent third quarter well results include two tests of the Upper Marcellus formation located in Bradford County, Pennsylvania, which had completed lateral lengths of 5,600 feet and 4,800 feet, respectively, and reached peak 24-hour production rates of approximately 19,000 mcf per day and 17,000 mcf per day, respectively. The company believes that these successful completions in the Upper Marcellus could provide more than 1,000 potential new drilling locations. Operated rig count in the Marcellus averaged one rig in the 2015 third quarter, and the company anticipates maintaining one operated rig through the end of the year.
Powder River Basin (PRB) (Wyoming): PRB net production averaged approximately 21 mboe per day (31 gross operated mboe per day) during the 2015 third quarter, an increase of 5% sequentially. Average completed well costs to date in 2015 are $10.6 million with an average completed lateral length of 5,900 feet and 22 frac stages, compared to the full-year 2014 average completed well cost of $10.6 million with an average completed lateral length of 5,400 feet and 20 frac stages. Recent third quarter well results include the Barton 32-34-67 USA A 1H, which was placed on production in October with a completed lateral length of 9,500 feet and reached a peak 24-hour production rate of 1,500 boe per day (85% black oil) from the Niobrara formation. Operated rig count in the PRB averaged one rig in the 2015 third quarter, and the company has released all operated rigs in the area through the end of the year.
Key Financial and Operational Results
The table below summarizes Chesapeake's key financial and operational results during the 2015 third quarter, as compared to results in prior periods.
Three Months Ended
------------------
09/30/15 06/30/15 09/30/14
-------- -------- --------
Oil equivalent
production (in mmboe) 61.3 63.9 66.8
Oil production (in
mmbbls) 10.5 10.8 10.9
Average realized oil
price ($/bbl)(a) 62.68 67.91 84.81
Oil as % of total
production 17 17 16
Natural gas production
(in bcf) 263.0 275.4 282.0
Average realized natural
gas price ($/mcf)(a) 1.14 1.01 2.09
Natural gas as % of
total production 72 72 71
NGL production (in
mmbbls) 7.0 7.2 8.8
Average realized NGL
price ($/bbl)(a) (1.38) 1.90 22.95
NGL as % of total
production 11 11 13
Production expenses
($/boe) (4.09) (4.32) (4.47)
Production taxes ($/boe) (0.42) (0.52) (0.94)
General and
administrative costs
($/boe)(b) (0.64) (0.89) (0.72)
Stock-based
compensation ($/boe) (0.15) (0.19) (0.18)
DD&A of natural gas and
liquids properties
($/boe) (7.95) (9.39) (10.31)
DD&A of other assets
($/boe) (0.51) (0.52) (0.55)
Interest expense
($/boe)(a) (1.41) (1.12) (0.16)
Marketing, gathering and
compression net margin
($ in millions)(c) 58 209 (7)
Operating cash flow ($
in millions)(d) 476 572 1,293
Operating cash flow
($/boe) 7.76 8.95 19.37
Adjusted ebitda ($ in
millions)(e) 560 600 1,236
Adjusted ebitda ($/boe) 9.12 9.37 18.52
Net income (loss)
available to common
stockholders ($ in
millions) (4,695) (4,151) 169
Earnings (loss) per
share - diluted ($) (7.08) (6.27) 0.26
Adjusted net income
(loss) available to
common stockholders ($
in millions)(f) (83) (126) 251
Adjusted earnings (loss)
per share - diluted ($) (0.05) (0.11) 0.38
(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 $70 million and $220
million of unrealized gains on
supply contract derivatives for
the three months ended September
30, 2015 and June 30, 2015,
respectively. Excludes
depreciation and amortization of
other assets.
(d) Defined as cash flow provided by
operating activities before
changes in assets and
liabilities.
(e) Defined as net income before
interest expense, income taxes
and depreciation, depletion and
amortization expense, as adjusted
to remove the effects of certain
items detailed on Pages 16 - 17.
(f) Defined as net income available to
common stockholders, as adjusted
to remove the effects of certain
items detailed on Page 12.
2015 Third Quarter Financial and Operational Results Conference Call Information
A conference call to discuss this release has been scheduled for Wednesday, November 4, 2015 at 9:00 am EST. The telephone number to access the conference call is 913-312-6690 or toll-free 888-600-4885. The passcode for the call is 4959206. We encourage those who would like to participate in the call to place calls between 8:50 and 9:00 am EST. For those unable to participate in the live conference call, a replay will be available for audio playback at 12:00 pm EST on Wednesday, November 4, 2015, and will run through 12:00 pm EST on Wednesday, November 18, 2015. The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112. The passcode for the replay is 4959206. The conference call will also be webcast live 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.
Chesapeake Energy Corporation (NYSE:CHK) is the second-largest producer of natural gas and the 12th largest producer of oil and natural gas liquids in the U.S. Headquartered in Oklahoma City, the company's operations are focused on discovering and developing its large and geographically diverse resource base of unconventional oil and natural gas assets onshore in the U.S. The company also owns substantial marketing and compression businesses. Further information is available at www.chk.com where Chesapeake routinely posts announcements, updates, events, investor information, presentations and news releases.
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 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 noncore 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 agreements), 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; write-downs of our oil and natural gas carrying values due to declines in prices; the availability of operating cash flow and other funds to finance reserve replacement costs; 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; the limitations our level of indebtedness may have on our financial flexibility; charges incurred in response to market conditions and in connection with 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; federal and state tax proposals affecting our industry; potential OTC derivatives regulation limiting our ability to hedge against commodity price fluctuations; impacts of potential legislative and regulatory actions addressing climate change; 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; cyber attacks adversely impacting our operations; and interruption in operations at our headquarters due to a catastrophic event.
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.
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,
------------- -------------
2015 2014 2015 2014
---- ---- ---- ----
REVENUES:
Oil, natural gas and NGL $880 $2,341 $2,693 $5,812
Marketing, gathering and compression 2,013 3,362 5,993 9,543
Oilfield services - - - 546
--- --- --- ---
Total Revenues 2,893 5,703 8,686 15,901
----- ----- ----- ------
OPERATING EXPENSES:
Oil, natural gas and NGL production 251 298 826 868
Production taxes 25 62 87 185
Marketing, gathering and compression 1,955 3,369 5,751 9,515
Oilfield services - - - 431
General and administrative 49 60 174 229
Restructuring and other termination
costs 53 (14) 39 12
Provision for legal contingencies - 100 359 100
Oil, natural gas and NGL depreciation,
depletion and amortization 488 688 1,773 1,977
Depreciation and amortization of other
assets 31 37 100 194
Impairment of oil and natural gas
properties 5,416 - 15,407 -
Impairments of fixed assets and other 79 15 167 75
Net (gains) losses on sales of fixed
assets (1) (86) 3 (201)
--- --- --- ----
Total Operating Expenses 8,346 4,529 24,686 13,385
----- ----- ------ ------
INCOME (LOSS) FROM OPERATIONS (5,453) 1,174 (16,000) 2,516
------ ----- ------- -----
OTHER INCOME (EXPENSE):
Interest expense (88) (17) (210) (82)
Losses on investments (33) (27) (57) (72)
Net gain on sales of investments - - - 67
Losses on purchases of debt - - - (195)
Other income (expense) (2) (1) 3 12
--- --- --- ---
Total Other Expense (123) (45) (264) (270)
---- --- ---- ----
INCOME (LOSS) BEFORE INCOME TAXES (5,576) 1,129 (16,264) 2,246
------ ----- ------- -----
INCOME TAX EXPENSE (BENEFIT):
Current income taxes - 2 (6) 10
Deferred income taxes (937) 435 (3,808) 849
---- --- ------ ---
Total Income Tax Expense (Benefit) (937) 437 (3,814) 859
---- --- ------ ---
NET INCOME (LOSS) (4,639) 692 (12,450) 1,387
Net income attributable to
noncontrolling interests (13) (30) (50) (110)
--- --- --- ----
NET INCOME (LOSS) ATTRIBUTABLE TO
CHESAPEAKE (4,652) 662 (12,500) 1,277
------ --- ------- -----
Preferred stock dividends (43) (43) (128) (128)
Repurchase of preferred shares of CHK
Utica - (447) - (447)
Earnings allocated to participating
securities - (3) - (15)
--- --- --- ---
NET INCOME (LOSS) AVAILABLE TO COMMON
STOCKHOLDERS $(4,695) $169 $(12,628) $687
======= ==== ======== ====
EARNINGS (LOSS) PER COMMON SHARE:
Basic $(7.08) $0.26 $(19.07) $1.04
====== ===== ======= =====
Diluted $(7.08) $0.26 $(19.07) $1.04
====== ===== ======= =====
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in
millions):
Basic 663 660 662 659
=== === === ===
Diluted 663 660 662 659
=== === === ===
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
($ in millions)
(unaudited)
September 30, December 31,
2015 2014
-------------- -------------
Cash and
cash
equivalents $1,759 $4,108
Other
current
assets 1,820 3,360
Total
Current
Assets 3,579 7,468
----- -----
Property
and
equipment,
(net) 16,959 32,515
Other
assets 748 768
--- ---
Total
Assets $21,286 $40,751
======= =======
Current
liabilities $4,557 $5,863
Long-term
debt, net
of
discounts 10,674 11,154
Other
long-
term
liabilities 935 1,344
Deferred
income
tax
liabilities 574 4,185
--- -----
Total
Liabilities 16,740 22,546
------ ------
Preferred
stock 3,062 3,062
Noncontrolling
interests 264 1,302
Common
stock and
other
stockholders'
equity 1,220 13,841
----- ------
Total
Equity 4,546 18,205
----- ------
Total
Liabilities
and
Equity $21,286 $40,751
======= =======
Common
Shares
Outstanding
(in
millions) 663 663
=== ===
CHESAPEAKE ENERGY CORPORATION
CAPITALIZATION
($ in millions)
(unaudited)
September 30, December 31,
2015 2014
-------------- -------------
Total debt, net of
unrestricted cash $9,808 $7,427
Preferred stock 3,062 3,062
Noncontrolling interests(a) 264 1,302
Common stock and other
stockholders' equity 1,220 13,841
Total $14,354 $25,632
======= =======
Total net debt to
capitalization ratio 68% 29%
(a) Includes third-party
ownership as follows:
Chesapeake Granite Wash
Trust $264 $287
CHK Cleveland Tonkawa,
L.L.C. (1) - 1,015
--- -----
Total $264 $1,302
==== ======
(1) Repurchase of noncontrolling interest of CHK Cleveland Tonkawa occurred in August 2015.
CHESAPEAKE ENERGY CORPORATION
SUPPLEMENTAL DATA - OIL, NATURAL GAS AND NGL PRODUCTION, SALES AND INTEREST EXPENSE
(unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
------------- -------------
2015 2014 2015 2014
---- ---- ---- ----
Net Production:
Oil (mmbbl) 10.5 10.9 32.3 31.1
Natural gas (bcf) 263.0 282.0 802.2 813.4
NGL (mmbbl) 7.0 8.8 21.0 24.1
Oil equivalent (mmboe) 61.3 66.8 187.0 190.7
Oil, natural gas and NGL Sales
($ in millions):
Oil sales $434 $1,005 $1,442 $2,933
Oil derivatives - realized
gains (losses)(a) 224 (77) 641 (288)
Oil derivatives - unrealized
gains (losses)(a) (100) 456 (444) 354
Total Oil Sales 558 1,384 1,639 2,999
--- ----- ----- -----
Natural gas sales 228 569 859 2,324
Natural gas derivatives -
realized gains (losses)(a) 70 19 341 (221)
Natural gas derivatives -
unrealized gains (losses)(a) 33 166 (198) 125
--- --- ---- ---
Total Natural Gas Sales 331 754 1,002 2,228
--- --- ----- -----
NGL sales (9) 203 52 585
Total NGL Sales (9) 203 52 585
--- ---
Total Oil, Natural Gas and NGL
Sales $880 $2,341 $2,693 $5,812
==== ====== ====== ======
Average Sales Price -
excluding gains (losses) on
derivatives:
Oil ($ per bbl) $41.25 $91.87 $44.57 $94.28
Natural gas ($ per mcf) $0.87 $2.02 $1.07 $2.86
NGL ($ per bbl) $(1.38) $22.95 $2.46 $24.31
Oil equivalent ($ per boe) $10.63 $26.62 $12.57 $30.63
Average Sales Price -
including realized gains
(losses) on derivatives:
Oil ($ per bbl) $62.68 $84.81 $64.40 $85.04
Natural gas ($ per mcf) $1.14 $2.09 $1.50 $2.59
NGL ($ per bbl) $(1.38) $22.95 $2.46 $24.31
Oil equivalent ($ per boe) $15.45 $25.74 $17.83 $27.96
Interest Expense ($ in
millions):
Interest(b) $88 $15 $222 $132
Derivatives - realized (gains)
losses(c) (2) (4) (4) (9)
Derivatives - unrealized
(gains) losses(c) 2 6 (8) (41)
Total Interest Expense $88 $17 $210 $82
=== === ==== ===
(a) Realized gains and losses include
the following items: (i)
settlements of nondesignated
derivatives related to current
period production revenues, (ii)
prior period settlements for option
premiums and for early-terminated
derivatives originally scheduled to
settle against current period
production revenues, and (iii)
gains and losses related to de-
designated cash flow hedges
originally designated to settle
against current period production
revenues. Unrealized gains and
losses include the change in fair
value of open derivatives scheduled
to settle against future period
production revenues offset by
amounts reclassified as realized
gains and losses during the period.
Although we no longer designate
our derivatives as cash flow hedges
for accounting purposes, we believe
these definitions are useful to
management and investors in
determining the effectiveness of
our price risk management program.
(b) Net of amounts capitalized.
(c) Realized (gains) losses include
settlements related to the current
period interest accrual and the
effect of (gains) losses on early
termination trades. Unrealized
(gains) losses include changes in
the fair value of open interest
rate derivatives offset by amounts
reclassified to realized (gains)
losses during the period.
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
($ in millions)
(unaudited)
THREE MONTHS ENDED: September 30, September 30,
2015 2014
--- ---- ----
Beginning cash $2,051 $1,462
------ ------
Net cash provided by operating
activities 318 1,184
---
Cash flows from investing activities:
Drilling and completion costs(a) (528) (1,189)
Acquisitions of proved and unproved
properties(b) (141) (667)
Proceeds from divestitures of proved
and unproved properties 174 475
Additions to other property and
equipment (21) (25)
Cash paid to purchase leased rigs and
compressors - (52)
Proceeds from sales of other property
and equipment 73 251
Additions to investments (2) (9)
Decrease in restricted cash 52 37
Other - (2)
--- ---
Net cash used in investing activities (393) (1,181)
---- ------
Net cash used in financing activities (217) (1,375)
---- ------
Change in cash and cash equivalents (292) (1,372)
---- ------
Ending cash $1,759 $90
====== ===
(a) Includes capitalized interest of $3
million and $11 million for the
three months ended September 30,
2015 and 2014, respectively.
(b) Includes capitalized interest of
$93 million and $135 million for
the three months ended September
30, 2015 and 2014, respectively.
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
($ in millions)
(unaudited)
NINE MONTHS ENDED: September 30, September 30,
2015 2014
--- ---- ----
Beginning cash $4,108 $837
------ ----
Net cash provided by operating
activities 1,055 3,805
-----
Cash flows from investing activities:
Drilling and completion costs(a) (2,696) (3,185)
Acquisitions of proved and unproved
properties(b) (407) (1,023)
Proceeds from divestitures of proved
and unproved properties 188 723
Additions to other property and
equipment (114) (201)
Cash paid to purchase leased rigs and
compressors - (474)
Proceeds from sales of other property
and equipment 80 964
Additions to investments (8) (14)
Proceeds from sales of investments - 239
Decrease in restricted cash 52 37
Other - (4)
--- ---
Net cash used in investing activities (2,905) (2,938)
------ ------
Net cash used in financing activities (499) (1,614)
---- ------
Change in cash and cash equivalents (2,349) (747)
------ ----
Ending cash $1,759 $90
====== ===
(a) Includes capitalized interest of
$21 million and $40 million for
the nine months ended September
30, 2015 and 2014, respectively.
(b) Includes capitalized interest of
$305 million and $433 million for
the nine months ended September
30, 2015 and 2014, respectively.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS
($ in millions, except per share data)
(unaudited)
THREE MONTHS ENDED: September 30, June 30, September 30,
2015 2015 2014
--- ---- ---- ----
Net income (loss) available to common
stockholders $(4,695) $(4,151) $169
Adjustments, net of tax:
Unrealized (gains) losses on commodity
derivatives 58 220 (384)
Unrealized gains on supply contract
derivatives (58) (161) -
Restructuring and other termination costs 44 (3) (9)
Provision for legal contingencies - 244 62
Impairment of oil and natural gas properties 4,506 3,666 -
Impairments of fixed assets and other 66 61 9
Net (gains) losses on sales of fixed assets (1) 1 (54)
Repurchase of preferred shares of CHK Utica - - 447
Other (3) (3) 11
Adjusted net income (loss) available to
common stockholders(a) $(83) $(126) $251
---- ----- ----
Preferred stock dividends 43 43 43
Earnings allocated to participating
securities - - 3
--- --- ---
Total adjusted net income (loss)
attributable to Chesapeake $(40) $(83) $297
==== ==== ====
Weighted average fully diluted shares
outstanding 777 777 776
(in millions)(b)
Adjusted earnings (loss) per share assuming
dilution(a) $(0.05) $(0.11) $0.38
(a) Adjusted net
income and
adjusted earnings
per share
assuming dilution
are not measures
of financial
performance under
accounting
principles
generally
accepted in the
United States
(GAAP), and
should not be
considered as an
alternative to
net income
available to
common
stockholders or
diluted earnings
per share.
Adjusted net
income available
to common
stockholders and
adjusted earnings
per share
assuming dilution
exclude certain
items that
management
believes affect
the comparability
of operating
results. The
company believes
these adjusted
financial
measures are a
useful adjunct to
earnings
calculated in
accordance with
GAAP because:
(i) Management uses adjusted net
income available to common
stockholders to evaluate the
company's operational trends
and performance relative to
other oil and natural gas
producing companies.
(ii) Adjusted net income available to
common stockholders is more
comparable to earnings
estimates provided by
securities analysts.
(iii) Items excluded generally are
one-time items or items whose
timing or amount cannot be
reasonably estimated.
Accordingly, any guidance
provided by the company
generally excludes information
regarding these types of items.
(b) Weighted average
fully diluted
shares
outstanding
include shares
that were
considered
antidilutive for
calculating
earnings per
share in
accordance with
GAAP.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS
($ in millions, except per share data)
(unaudited)
NINE MONTHS ENDED: September 30, September 30,
2015 2014
--- ---- ----
Net income (loss) available to common
stockholders $(12,628) $687
Adjustments, net of tax:
Unrealized (gains) losses on commodity
derivatives 486 (324)
Unrealized gains on supply contract
derivatives (222) -
Restructuring and other termination costs 30 7
Provision for legal contingencies 275 62
Impairment of oil and natural gas properties 11,794 -
Impairments of fixed assets and other 128 46
Net (gains) losses on sales of fixed assets 2 (125)
Impairments of investments - 3
Net gain on sales of investments - (42)
Losses on purchases of debt - 121
Repurchase of preferred shares of CHK Utica - 447
Tax rate adjustment (17) -
Other (10) 5
Adjusted net income (loss) available to
common stockholders(a) $(162) $887
----- ----
Preferred stock dividends 128 128
Earnings allocated to participating
securities - 15
--- ---
Total adjusted net income (loss)
attributable to Chesapeake $(34) $1,030
==== ======
Weighted average fully diluted shares
outstanding (in millions)(b) 776 776
Adjusted earnings (loss) per share assuming
dilution(a) $(0.04) $1.33
(a) Adjusted net
income and
adjusted earnings
per share
assuming dilution
are not measures
of financial
performance under
accounting
principles
generally
accepted in the
United States
(GAAP), and
should not be
considered as an
alternative to
net income
available to
common
stockholders or
diluted earnings
per share.
Adjusted net
income available
to common
stockholders and
adjusted earnings
per share
assuming dilution
exclude certain
items that
management
believes affect
the comparability
of operating
results. The
company believes
these adjusted
financial
measures are a
useful adjunct to
earnings
calculated in
accordance with
GAAP because:
(i) Management uses adjusted net
income available to common
stockholders to evaluate the
company's operational trends
and performance relative to
other oil and natural gas
producing companies.
(ii) Adjusted net income available to
common stockholders is more
comparable to earnings
estimates provided by
securities analysts.
(iii) Items excluded generally are
one-time items or items whose
timing or amount cannot be
reasonably estimated.
Accordingly, any guidance
provided by the company
generally excludes information
regarding these types of items.
(b) Weighted average
fully diluted
shares
outstanding
include shares
that were
considered
antidilutive for
calculating
earnings per
share in
accordance with
GAAP.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
($ in millions)
(unaudited)
THREE MONTHS ENDED: September 30, June 30, September 30,
2015 2015 2014
--- ---- ---- ----
CASH PROVIDED BY OPERATING
ACTIVITIES $318 $314 $1,184
Changes in assets and
liabilities 158 258 109
--- --- ---
OPERATING CASH FLOW(a) $476 $572 $1,293
==== ==== ======
THREE MONTHS ENDED: September 30, June 30, September 30,
2015 2015 2014
--- ---- ---- ----
NET INCOME (LOSS) $(4,639) $(4,090) $692
Interest expense 88 71 17
Income tax expense (benefit) (937) (1,506) 437
Depreciation and
amortization of other
assets 31 34 37
Oil, natural gas and NGL
depreciation, depletion and
amortization 488 601 688
--- --- ---
EBITDA(b) $(4,969) $(4,890) $1,871
======= ======= ======
THREE MONTHS ENDED: September 30, June 30, September 30,
2015 2015 2014
--- ---- ---- ----
CASH PROVIDED BY OPERATING
ACTIVITIES $318 $314 $1,184
Changes in assets and
liabilities 158 258 109
Interest expense, net of
unrealized gains (losses)
on derivatives 86 71 11
Gains (losses) on commodity
derivatives, net 227 (48) 564
Gains on supply contract
derivatives, net 70 220 -
Cash (receipts) payments on
oil, natural gas and NGL
derivative settlements, net (223) (223) 34
Stock-based compensation (18) (20) (19)
Restructuring and other
termination costs (53) 4 42
Provision for legal
contingencies - (334) (100)
Impairment of oil and
natural gas properties (5,416) (5,015) -
Impairments of fixed assets
and other (78) (79) (15)
Net gains (losses) on sales
of fixed assets 1 (1) 86
Losses on investments (33) (17) (27)
Other items (8) (20) 2
--- --- ---
EBITDA(b) $(4,969) $(4,890) $1,871
======= ======= ======
(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,
investing or financing 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 flow provided by
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,
2015 2014
--- ---- ----
CASH PROVIDED BY
OPERATING
ACTIVITIES $1,055 $3,805
Changes in assets
and liabilities 877 348
--- ---
OPERATING CASH
FLOW(a) $1,932 $4,153
====== ======
NINE MONTHS
ENDED: September 30, September 30,
2015 2014
--- ---- ----
NET INCOME (LOSS) $(12,450) $1,387
Interest expense 210 82
Income tax
expense
(benefit) (3,814) 859
Depreciation and
amortization of
other assets 100 194
Oil, natural gas
and NGL
depreciation,
depletion and
amortization 1,773 1,977
----- -----
EBITDA(b) $(14,181) $4,499
======== ======
NINE MONTHS
ENDED: September 30, September 30,
2015 2014
--- ---- ----
CASH PROVIDED BY
OPERATING
ACTIVITIES $1,055 $3,805
Changes in assets
and liabilities 877 348
Interest expense,
net of
unrealized gains
(losses) on
derivatives 218 123
Gains (losses) on
commodity
derivatives, net 340 (30)
Gains on supply
contract
derivatives, net 290 -
Cash (receipts)
payments on oil,
natural gas and
NGL derivative
settlements, net (859) 352
Stock-based
compensation (61) (59)
Restructuring and
other
termination
costs (39) 18
Provision for
legal
contingencies (359) (100)
Impairment of oil
and natural gas
properties (15,407) -
Impairments of
fixed assets and
other (159) (44)
Net gains
(losses) on
sales of fixed
assets (3) 201
Losses on
investments (57) (72)
Net gain on sales
of investments - 67
Losses on
purchases of
debt - (61)
Other items (17) (49)
--- ---
EBITDA(b) $(14,181) $4,499
======== ======
(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,
investing or financing 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 flow provided by
operating activities prepared in
accordance with GAAP.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED EBITDA
($ in millions)
(unaudited)
THREE MONTHS ENDED: September 30, June 30, September 30,
2015 2015 2014
--- ---- ---- ----
EBITDA $(4,969) $(4,890) $1,871
Adjustments:
Unrealized (gains) losses on oil,
natural gas and NGL derivatives 67 301 (622)
Unrealized gains on supply
contract derivatives (70) (220) -
Restructuring and other
termination costs 53 (4) (14)
Provision for legal contingencies - 334 100
Impairment of oil and natural gas
properties 5,416 5,015 -
Impairments of fixed assets and
other 79 84 15
Net (gains) losses on sales of
fixed assets (1) 1 (86)
Net income attributable to
noncontrolling interests (13) (18) (30)
Other (2) (3) 2
--- --- ---
Adjusted EBITDA(a) $560 $600 $1,236
==== ==== ======
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED EBITDA
($ in millions)
(unaudited)
NINE MONTHS ENDED: September 30, September 30,
2015 2014
--- ---- ----
EBITDA $(14,181) $4,499
Adjustments:
Unrealized (gains)
losses on oil,
natural gas and
NGL derivatives 642 (479)
Unrealized gains on
supply contract
derivatives (290) -
Restructuring and
other termination
costs 39 12
Provision for legal
contingencies 359 100
Impairment of oil
and natural gas
properties 15,407 -
Impairments of
fixed assets and
other 167 75
Net (gains) losses
on sales of fixed
assets 3 (201)
Impairments of
investments - 5
Net gains on sales
of investments - (67)
Losses on purchases
of debt - 195
Net income
attributable to
noncontrolling
interests (50) (110)
Other (9) -
--- ---
Adjusted EBITDA(a) $2,087 $4,029
====== ======
(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.
CHESAPEAKE ENERGY CORPORATION
MANAGEMENT'S OUTLOOK AS OF NOVEMBER 4, 2015
Chesapeake periodically provides management guidance on certain factors that affect the company's future financial performance. Changes from the company's August 5, 2015 Outlook are italicized bold below.
Year Ending
12/31/2015
----------
Adjusted Production Growth(a) 6% - 8%
Absolute Production
Liquids - mbbls 67.5 - 69.5
Oil - mbbls 41.5 - 42.5
NGL(b) - mbbls 26.0 - 27.0
Natural gas - bcf 1,060 - 1,070
Total absolute production - mmboe 244 - 249
Absolute daily rate - mboe 670 - 680
Estimated Realized Hedging Effects(c) (based on 10/31/15 strip prices):
Oil - $/bbl $20.80
Natural gas - $/mcf $0.41
Estimated Basis/Gathering/Marketing/Transportation Differentials to
NYMEX Prices:
Oil - $/bbl $6.00 - 8.00
Natural gas - $/mcf $1.65 - 1.85
NGL - $/bbl $48.00 - 50.00
Fourth quarter minimum volume commitment (MVC) estimate ($ in millions) ($160) - (180)
Operating Costs per Boe of Projected Production:
Production expense $4.25 - 4.50
Production taxes $0.45 - 0.55
General and administrative(d) $0.75 - 0.85
Stock-based compensation (noncash) $0.15 - 0.20
DD&A of natural gas and liquids assets $8.00 - 9.00
Depreciation of other assets $0.50 - 0.60
Interest expense(e) $1.20 - 1.30
Other ($ millions):
Marketing, gathering and compression net margin(f) ($40 - 60)
Net income attributable to noncontrolling interests and other(g) ($60 - 65)
Book Tax Rate 20% - 30%
Capital Expenditures ($ in millions)(h) $3,000 - 3,500
Capitalized Interest ($ in millions) $425
Total Capital Expenditures ($ in millions) $3,425 - 3,925
(a) Based on 2014 production of 618
mboe per day adjusted for 2014
sales and the sale of the
Cleveland Tonkawa asset in 2015.
(b) Assumes ethane recovery in the
Utica to fulfill Chesapeake's
pipeline commitments, no ethane
recovery in the Powder River Basin
and partial ethane recovery in the
Mid-Continent and Eagle Ford.
(c) Includes expected settlements for
commodity derivatives adjusted for
option premiums. For derivatives
closed early, settlements are
reflected in the period of
original contract expiration.
(d) Excludes expenses associated with
stock-based compensation.
(e) Excludes unrealized gains (losses)
on interest rate derivatives.
(f) Includes revenue and operating
expenses. Excludes depreciation
and amortization of other assets
and unrealized gains (losses) on
supply contract derivatives.
(g) Net income attributable to
noncontrolling interests of
Chesapeake Granite Wash Trust and,
prior to its repurchase in the
2015 third quarter, CHK Cleveland
Tonkawa, L.L.C.
(h) Includes capital expenditures for
drilling and completion,
leasehold, geological and
geophysical costs and other
property and plant and equipment.
Oil and Natural Gas Hedging Activities
Chesapeake enters into oil and natural gas 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 and natural gas derivatives.
As of October 31, 2015, the company had downside protection, through open swaps, on approximately 38% of its projected 2015 fourth quarter oil production at an average price of $86.89 per bbl. In addition, the company had downside price protection under three-way collar arrangements on approximately 11% of its projected 2015 fourth quarter oil production based on an average bought put NYMEX price of $90 per bbl and exposure below an average sold put NYMEX price of $80 per bbl. The company had downside price protection, through open swaps, on approximately 20% of the company's projected 2015 fourth quarter natural gas production at an average price of $3.94 per mcf. In addition, the company had downside price protection under three-way collar arrangements on approximately 14% of its projected 2015 fourth quarter natural gas production based on an average bought put NYMEX price of $4.17 per mcf and exposure below an average sold put NYMEX price of $3.38 per mcf. On three-way collars, if the actual price at settlement is below the sold put, the company's gain will be the difference between the bought put and the sold put.
The company's crude oil hedging positions as of October 31, 2015 were as follows:
Open Crude Oil Swaps; Gains from Closed
Crude Oil Trades and Call Option Premiums
Open Swaps Avg. NYMEX Total Gains from Closed
Trades
(mbbls) Price of and Premiums for
Open Swaps Call Options
($ in millions)
---------------
Q4 2015 3,634 $86.89 $63
2016 (a) 12,078 52.13 38
Total 2017 -
2022 - $ - $78
============ === === === ===
(a) Certain hedging arrangements
include a sold option to extend
at an average price of $53.67 per
bbl covering 2.9 mmbbls in 2016.
Crude Oil Three-Way Collars
Open Collars (mbbls) Avg. NYMEX Avg. NYMEX Avg. NYMEX
Sold Put Bought Put Sold Call
Price Price Price
------------------- ---------- ---------- ----------
Q4 2015 1,104 $80.00 $90.00 $98.94
Crude Oil Net Written Call Options
Call Options Avg. NYMEX
(mbbls) Strike
Price
------ -------
Q4 2015 1,868 $85.31
2016 10,951 96.23
2017 5,293 $83.50
==== ===== ======
Crude Oil Basis Protection Swaps
Volume Avg. NYMEX
plus
(mbbls)
------
Q4 2015 2,361 $3.14
======= ===== =====
The company's natural gas hedging positions as of October 31, 2015 were as follows:
Open Natural Gas Swaps; Gains (Losses) from Closed
Natural Gas Trades and Call Option Premiums
Open Swaps Avg. NYMEX Total
Losses
(bcf) Price of from
Closed
Trades
Open Swaps and
Premiums
for
Call
Options
($ in
millions)
---------
Q4 2015 52 $3.94 $(31)
2016 283 3.18 (109)
Total 2017 - 2022 - $ $(78)
-
=== ===
Natural Gas Three-Way Collars
Open Collars Avg. NYMEX Avg. NYMEX Avg. NYMEX
(bcf) Sold Bought Sold Call
Price
Put Price Put Price
--------- ---
Q4 2015 36 $3.38 $4.17 $4.37
======= === ===== ===== =====
Natural Gas Net Written Call Options
Call Options Avg. NYMEX
(bcf) Strike
Price
---- -------
2016 79 $8.48
Total 2017 -
2020 114 $10.92
============ === ======
Natural Gas Basis Protection Swaps
Volume Avg. NYMEX
plus/
(minus)
(bcf)
----
Q4 2015 18 $0.37
2016 33 0.17
Total 2017 - 2022 24 $(0.48)
================= === ======
To view the original version on PR Newswire, visit:http://www.prnewswire.com/news-releases/chesapeake-energy-corporation-reports-2015-third-quarter-financial-and-operational-results-300171746.html
SOURCE Chesapeake Energy Corporation
