CHK
$4.10
Chesapeake Energy
$.05
1.23%
Earnings Details
2nd Quarter June 2017
Thursday, August 03, 2017 7:00:00 AM
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Summary

Chesapeake Energy Beats

Chesapeake Energy (CHK) reported 2nd Quarter June 2017 earnings of $0.18 per share on revenue of $2.3 billion. The consensus earnings estimate was $0.14 per share on revenue of $1.1 billion. The Earnings Whisper number was $0.16 per share. Revenue grew 40.6% on a year-over-year basis.

Chesapeake Energy Corp is a natural gas and oil exploration and production company. It explores, develops and acquires properties for the production of natural gas and crude oil from underground reservoirs and also provides marketing & midstream services.

Results
Reported Earnings
$0.18
Earnings Whisper
$0.16
Consensus Estimate
$0.14
Reported Revenue
$2.28 Bil
Revenue Estimate
$1.08 Bil
Growth
Earnings Growth
Revenue Growth
Power Rating
Grade
Earnings Release

Chesapeake Energy Corporation Reports 2017 Second Quarter Financial And Operational Results

Chesapeake Energy Corporation (CHK) today reported financial and operational results for the 2017 second quarter plus other recent developments. Highlights include:

-- Average 2017 second quarter production of 527,600 boe per day, flat sequentially

-- Average 2017 second quarter oil production of 88,400 barrels per day, up 6% sequentially

Total production averaged approximately 548,300 boe per day, including a peak rate of 90,400 barrels of oil, in July; goal of reaching 100,000 barrels of oil per day by year-end on track

Actively managing capital expenditures program for remainder of 2017, dropping to 14 rigs by year-end 2017 from 18 rigs today

Approximately $360 million of expected asset sales closed or under signed purchase and sale agreements year to date

-- Marcellus Shale well achieves record rate of more than 61,000 mcf per day

Doug Lawler, Chesapeake’s Chief Executive Officer, commented, "Our assets continue to deliver improving well results due to longer laterals and enhanced completion techniques, with a new record operated well in the Marcellus being a prime example of this. We expect our total production to move higher throughout the year, driven by large turn-in-line projects underway in the Eagle Ford, Utica and Powder River Basin operating areas. This has already started, as we averaged approximately 548,300 barrels of oil equivalent per day, including a peak rate of 90,400 barrels of oil production, for the month of July.

"Despite our anticipated growth, we are actively managing our 2017 capital program to the highest-return investments in our portfolio or reducing spending in certain areas altogether. Our planned activity levels result in a reduction of our rig count and wells placed on production during the last six months of the year, as our 2017 capital program has been focused on restoring our cash flow generating capability, improving our margins and growing value. Improving our balance sheet is our number one priority at Chesapeake, and we will remain flexible in our capital spending program, both for the remainder of 2017 and in 2018, as we continue to drive toward cash flow neutrality."

2017 Second Quarter Results

For the 2017 second quarter, Chesapeake’s revenues increased by 41% year over year primarily due to an increase in the average realized commodity prices for the company’s production and unrealized hedging gains, partially offset by a decrease in production volumes sold. Chesapeake’s revenues decreased 17% quarter over quarter due to a decrease in the average realized commodity prices for the company’s production, primarily the seasonal decrease in natural gas prices and lower unrealized hedging gains. Average daily production for the 2017 second quarter of approximately 527,600 barrels of oil equivalent (boe) increased by 2% sequentially, adjusted for asset sales, and consisted of approximately 88,400 barrels (bbls) of oil, 2.294 billion cubic feet (bcf) of natural gas and 56,900 bbls of natural gas liquids (NGL).

Average production expenses during the 2017 second quarter were $2.92 per boe, while G&A expenses (including stock-based compensation) during the 2017 second quarter were $1.45 per boe. Combined production and G&A expenses (including stock-based compensation) during the 2017 second quarter were $4.37 per boe, an increase of 7% year over year and an increase of 4% quarter over quarter driven by a decrease in producing well count due to divestitures resulting in reduced cost recovery in G&A. Gathering, processing and transportation expenses during the 2017 second quarter were $7.44 per boe, a decrease of 7% year over year and a nominal decrease quarter over quarter.

Chesapeake reported net income available to common stockholders of $470 million, or $0.47 per diluted share, while the company’s EBITDA for the 2017 second quarter was $812 million. Adjusting for unrealized gains on commodity derivatives, impairments related to the reduction of transportation commitments on the Gulf Crossing pipeline, the gain on repurchase of debt and other items that are typically excluded by securities analysts, the 2017 second quarter adjusted net income attributable to Chesapeake was $146 million, or $0.18 per diluted share, while the company’s adjusted EBITDA was $461 million. Reconciliations of financial measures calculated in accordance with GAAP to non-GAAP measures are provided on pages 12 - 18 of this release.

Capital Spending Overview

Chesapeake’s total capital investments were approximately $667 million during the 2017 second quarter, compared to approximately $576 million in the 2017 first quarter and $456 million in the 2016 second quarter. A summary of the company’s guidance for 2017 is provided under "Management’s Outlook as of August 3, 2017," beginning on page 20.

2017
2017
2016
Operated activity comparison
Q2
Q1
Q2
Average rig count
19
16
9
Gross wells spud
102
87
49
Gross wells completed
107
99
131
Gross wells connected
94
76
141
Type of cost ($ in millions)
Drilling and completion costs
$ 596
$ 506
$ 337
Exploration costs, leasehold and additions to other PP&E 24
19
56
Subtotal capital expenditures
$ 620
$ 525
$ 393
Capitalized interest
47
51
63
Total capital expenditures
$ 667
$ 576
$ 456

Balance Sheet and Liquidity

As of June 30, 2017, Chesapeake’s principal debt balance was approximately $9.7 billion with $13 million in cash on hand, compared to $10.0 billion with $882 million in cash on hand as of December 31, 2016. The company’s total liquidity as of June 30, 2017 was approximately $3.1 billion, which included cash on hand and a borrowing capacity of approximately $3.1 billion under the company’s senior secured revolving credit facility. At June 30, 2017, the company had $575 million of outstanding borrowings under the revolving credit facility and had used $100 million of the revolving credit facility for various letters of credit. The company’s borrowing base under the senior secured revolving credit facility was reaffirmed by the lenders at $3.785 billion on June 15, 2017.

Asset Divestitures Update

Year to date, Chesapeake has sold or agreed to sell multiple producing properties for approximately $360 million to various private buyers, excluding the proceeds from the company’s Haynesville Shale divestitures announced in December 2016 that closed in 2017. As of June 30, 2017, Chesapeake has closed $95 million in asset sales with approximately $265 million pending and expected to close by the end of the 2017 third quarter, subject to certain customary post-closing adjustments.

Operations Update

Chesapeake’s average daily production for the 2017 second quarter was approximately 527,600 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 year and may be adjusted based on prevailing market conditions.

2017 2017 2016
Operating area net production (mboe/day) Q2
Q1
Q2
Eagle Ford
100
96
92
Haynesville
121
121
126
Marcellus
135
146
134
Utica
97
96
137
Mid-Continent
59
57
78
Powder River Basin
16
12
16
Barnett
--
--
65
Other
--
--
9
Total production
528
528
657

Chesapeake is currently utilizing 18 drilling rigs (below the 2017 second quarter average of 19) across its operating areas, seven of which are located in the Eagle Ford Shale, four in the Mid-Continent area, three in the Haynesville Shale, two in the Powder River Basin (PRB) and two in Northeast Appalachia. Chesapeake plans to exit 2017 utilizing 14 rigs and intends to place on production approximately 20 fewer gross operated wells in 2017.

In the Eagle Ford Shale, Chesapeake placed its first Upper Eagle Ford Shale well, the Blakeway 3D DIM 2H, on production in June 2017 at a peak rate of 1,759 boe per day (86% oil). Chesapeake expects to place on production up to 100 wells in South Texas in the second half of 2017, compared to 61 wells in the first half of 2017.

In the PRB, Chesapeake’s first well targeting the Mowry formation, the Combs 17-33-70 USA B MW 40H, was drilled with a 4,200-foot lateral and placed on production in July 2017. This well was drilled in the gas window to test productivity, permeability and pressure and near current pipe infrastructure to minimize cycle time. This well has reached a peak rate of 6,629 thousand cubic feet (mcf) of natural gas per day and is expected to climb as it unloads fracture stimulation fluid. Chesapeake’s next Mowry tests are planned to be drilled in 2018 in the wet gas window with longer laterals.

The company’s second Turner well, the Rankin 5-33-68 A TR 1H, was placed on production in May 2017 and reached a peak rate of 2,886 boe per day (51% oil). Chesapeake plans to place on production up to four additional wells in the Turner formation by year-end 2017. The company also expects to place up to 14 new wells targeting the Sussex formation by year-end 2017. Currently, Chesapeake plans to add a third rig in the PRB operating area in October 2017 and expects to place on production up to 19 wells in the second half of 2017, compared to nine wells in the first half of 2017.

In the Marcellus Shale, the company placed the McGavin E WYO 6H well on production with a 10,429-foot lateral and enhanced completion. This well has reached a peak rate of 61,759 mcf of gas per day after six days of production, making it the highest-rate operated well in the Marcellus Shale in the company’s history. Chesapeake has approximately 2.2 bcf of gas per day of gross productive capacity and expects to maintain its gross production at or around its total capacity through the remainder of 2017, depending on gas prices. Chesapeake expects to place on production up to 40 wells in the Marcellus Shale in the second half of 2017, compared to 11 wells in the first half of 2017.

In the Haynesville Shale, the Hunter 20&17-12-12 1H ALT well located in DeSoto Parish was placed on production in July 2017 with a 7,495-foot lateral. This well reached a peak rate of 38,840 mcf of gas per day, resulting in one of the highest rates per lateral foot in the company’s history from the area. Chesapeake expects to place on production up to 23 wells in the Haynesville Shale in the second half of 2017, compared to 17 wells in the first half of 2017.

Chesapeake re-completed its first Haynesville well utilizing a new production liner in July 2017. After installing the new liner, Chesapeake re-stimulated the well and returned it to production at a peak rate of approximately 9,043 mcf of gas per day, compared to producing 65 mcf of gas per day before the re-stimulation treatment. This recompletion was performed on one of the first wells Chesapeake drilled in the Haynesville. Drilled in 2008, the well had an initial peak production of 4,705 mcf of gas per day producing from a 2,990-foot lateral in 2008.

Key Financial and Operational Results
The table below summarizes Chesapeake’s key financial and operational results during the 2017 second quarter compared to results in prior periods.
Three Months Ended
06/30/17
03/31/17
06/30/16
Oil equivalent production (in mmboe)
48
48
60
Oil production (in mmbbls)
8
8
8
Average realized oil price ($/bbl)(a)
51.65
51.72
44.31
Natural gas production (in bcf)
209
211
269
Average realized natural gas price ($/mcf)(a)
2.71
3.02
1.97
NGL production (in mmbbls)
5
5
7
Average realized NGL price ($/bbl)(a)
18.51
24.04
12.88
Production expenses ($/boe)
(2.92)
(2.84)
(3.05)
Gathering, processing and transportation expenses ($/boe)
(7.44)
(7.47)
(8.04)
Oil - ($/bbl)
(3.70)
(3.85)
(3.64)
Natural Gas - ($/mcf)
(1.37)
(1.35)
(1.48)
NGL - ($/bbl)
(7.87)
(8.47)
(7.61)
Production taxes ($/boe)
(0.42)
(0.47)
(0.32)
General and administrative expenses ($/boe)(b)
(1.20)
(1.18)
(0.86)
Stock-based compensation ($/boe)
(0.25)
(0.17)
(0.16)
DD&A of oil and natural gas properties ($/boe)
(4.21)
(4.15)
(4.64)
DD&A of other assets ($/boe)
(0.43)
(0.44)
(0.48)
Interest expense ($/boe)(a)
(1.92)
(1.97)
(1.00)
Marketing, gathering and compression net margin ($ in millions)(c)
(25)
(44)
(25)
Net cash provided by (used in) operating activities ($ in millions)
(157)
99
95
Net cash provided by (used in) operating activities ($/boe)
(3.27)
2.06
1.58
Operating cash flow ($ in millions)(d)
303
(14)
176
Operating cash flow ($/boe)
6.31
(0.29)
2.94
Adjusted ebitda ($ in millions)(e)
461
525
252
Adjusted ebitda ($/boe)
9.60
11.05
4.21
Net income (loss) available to common stockholders ($ in millions)
470
75
(1,818)
Income (loss) per share - diluted ($)
0.47
0.08
(2.51)
Adjusted net income (loss) attributable to Chesapeake ($ in millions)(f)
146
212
(115)
Adjusted income (loss) per share - diluted ($)(g)
0.18
0.23
(0.16)
(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 June 30, 2016, unrealized gains (losses) on supply contract derivatives, but excludes depreciation and amortization of other assets. For the three months ended June 30, 2016, unrealized losses on supply contract derivatives were $37 million. No other period had such gains (losses).
(d) Defined as cash flow provided by operating activities before changes in assets and liabilities. Operating cash flow for the three months ended June 30, 2017 includes $23 million paid to terminate future natural gas transportation commitments.
(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 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 Second Quarter Financial and Operational Results Conference Call Information

A conference call to discuss this release has been scheduled on Thursday, August 3, 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 (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
June 30,
2017
2016
REVENUES:
Oil, natural gas and NGL
$
1,279
$
440
Marketing, gathering and compression
1,002
1,182
Total Revenues
2,281
1,622
OPERATING EXPENSES:
Oil, natural gas and NGL production
140
182
Oil, natural gas and NGL gathering, processing and transportation
357
481
Production taxes
21
19
Marketing, gathering and compression
1,027
1,207
General and administrative
70
61
Restructuring and other termination costs
--
3
Provision for legal contingencies
17
71
Oil, natural gas and NGL depreciation, depletion and amortization
202
277
Depreciation and amortization of other assets
21
29
Impairment of oil and natural gas properties
--
1,070
Impairments of fixed assets and other
26
6
Net (gains) losses on sales of fixed assets
1
(1)
Total Operating Expenses
1,882
3,405
INCOME (LOSS) FROM OPERATIONS
399
(1,783)
OTHER INCOME (EXPENSE):
Interest expense
(93)
(62)
Losses on investments
--
(2)
Gains on purchases or exchanges of debt
191
68
Other income (expense)
(1)
3
Total Other Income
97
7
INCOME (LOSS) BEFORE INCOME TAXES
496
(1,776)
Income Tax Expense
1
--
NET INCOME (LOSS)
495
(1,776)
Net income attributable to noncontrolling interests
(1)
--
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE
494
(1,776)
Preferred stock dividends
(16)
(42)
Earnings allocated to participating securities
(8)
--
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS
$
470
$
(1,818)
EARNINGS (LOSS) PER COMMON SHARE:
Basic
$
0.52
$
(2.51)
Diluted
$
0.47
$
(2.51)
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions):
Basic
908
724
Diluted
1,114
724
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ in millions except per share data)
(unaudited)
Six Months Ended
June 30,
2017
2016
REVENUES:
Oil, natural gas and NGL
$
2,748
$
1,433
Marketing, gathering and compression
2,286
2,142
Total Revenues
5,034
3,575
OPERATING EXPENSES:
Oil, natural gas and NGL production
275
388
Oil, natural gas and NGL gathering, processing and transportation
712
963
Production taxes
43
37
Marketing, gathering and compression
2,355
2,149
General and administrative
135
109
Restructuring and other termination costs
--
3
Provision for legal contingencies
15
104
Oil, natural gas and NGL depreciation, depletion and amortization
399
540
Depreciation and amortization of other assets
42
58
Impairment of oil and natural gas properties
--
2,067
Impairments of fixed assets and other
417
44
Net (gains) losses on sales of fixed assets
1
(5)
Total Operating Expenses
4,394
6,457
INCOME (LOSS) FROM OPERATIONS
640
(2,882)
OTHER INCOME (EXPENSE):
Interest expense
(188)
(124)
Losses on investments
--
(2)
Loss on sale of investment
--
(10)
Gains on purchases or exchanges of debt
184
168
Other income
2
6
Total Other Income (Expense)
(2)
38
INCOME (LOSS) BEFORE INCOME TAXES
638
(2,844)
Income Tax Expense
2
--
NET INCOME (LOSS)
636
(2,844)
Net income attributable to noncontrolling interests
(2)
--
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE
634
(2,844)
Preferred stock dividends
(39)
(85)
Loss on exchange of preferred stock
(41)
--
Earnings allocated to participating securities
(7)
--
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS
$
547
$
(2,929)
EARNINGS (LOSS) PER COMMON SHARE:
Basic
$
0.60
$
(4.21)
Diluted
$
0.59
$
(4.21)
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions):
Basic
907
695
Diluted
1,053
695
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
($ in millions)
(unaudited)
June 30, 2017 December 31, 2016
Cash and cash equivalents
$
13
$
882
Other current assets
1,234
1,260
Total Current Assets
1,247
2,142
Property and equipment, net
10,418
10,609
Other assets
255
277
Total Assets
$
11,920
$
13,028
Current liabilities
$
2,158
$
3,648
Long-term debt, net
9,850
9,938
Other long-term liabilities
596
645
Total Liabilities
12,604
14,231
Preferred stock
1,671
1,771
Noncontrolling interests
254
257
Common stock and other stockholders’ equity (deficit)
(2,609)
(3,231)
Total Equity (Deficit)
(684)
(1,203)
Total Liabilities and Equity
$
11,920
$
13,028
Common shares outstanding (in millions)
908
896
Principal amount of debt outstanding
$
9,710
$
9,989
CHESAPEAKE ENERGY CORPORATION
SUPPLEMENTAL DATA - OIL, NATURAL GAS AND NGL PRODUCTION, SALES AND INTEREST EXPENSE
(unaudited)
Three Months Ended
Six Months Ended
June 30,
June 30,
2017
2016
2017
2016
Net Production:
Oil (mmbbl)
8
8
16
17
Natural gas (bcf)
209
269
420
546
NGL (mmbbl)
5
7
10
13
Oil equivalent (mmboe)
48
60
96
121
Oil, natural gas and NGL Sales ($ in millions):
Oil sales
$
383
$
355
$
761
$
610
Oil derivatives - realized gains (losses)(a)
33
11
44
84
Oil derivatives - unrealized gains (losses)(a)
47
(168)
141
(240)
Total oil sales
463
198
946
454
Natural gas sales
601
440
1,254
923
Natural gas derivatives - realized gains (losses)(a)
(36)
92
(52)
242
Natural gas derivatives - unrealized gains (losses)(a)
156
(365)
387
(335)
Total natural gas sales
721
167
1,589
830
NGL sales
95
89
211
163
NGL derivatives - realized gains (losses)(a)
1
(3)
2
(3)
NGL derivatives - unrealized gains (losses)(a)
(1)
(11)
--
(11)
Total NGL sales
95
75
213
149
Total oil, natural gas and NGL sales
$
1,279
$
440
$
2,748
$
1,433
Average Sales Price
(excluding gains (losses) on derivatives):
Oil ($ per bbl)
$
47.51
$
43.00
$
48.83
$
35.98
Natural gas ($ per mcf)
$
2.88
$
1.63
$
2.99
$
1.69
NGL ($ per bbl)
$
18.36
$
13.37
$
20.99
$
12.43
Oil equivalent ($ per boe)
$
22.46
$
14.76
$
23.29
$
14.01
Average Sales Price
(including realized gains (losses) on derivatives):
Oil ($ per bbl)
$
51.65
$
44.31
$
51.68
$
40.93
Natural gas ($ per mcf)
$
2.71
$
1.97
$
2.87
$
2.14
NGL ($ per bbl)
$
18.51
$
12.88
$
21.19
$
12.17
Oil equivalent ($ per boe)
$
22.42
$
16.43
$
23.23
$
16.68
Interest Expense ($ in millions):
Interest expense(b)
$
93
$
63
$
187
$
125
Interest rate derivatives - realized (gains) losses(c)
(1)
(3)
(2)
(6)
Interest rate derivatives - unrealized (gains) losses(c)
1
2
3
5
Total Interest Expense
$
93
$
62
$
188
$
124
(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:
June 30,
June 30,
2017
2016
Beginning cash
$
249
$
16
Net cash provided by (used in) operating activities
(157)
95
Cash flows from investing activities:
Drilling and completion costs(a)
(598)
(344)
Acquisitions of proved and unproved properties(b)
(67)
(359)
Proceeds from divestitures of proved and unproved properties
59
833
Additions to other property and equipment(c)
(4)
(15)
Proceeds from sales of other property and equipment
7
61
Other
--
(2)
Net cash provided by (used in) investing activities
(603)
174
Net cash provided by (used in) financing activities
524
(281)
Change in cash and cash equivalents
(236)
(12)
Ending cash
$
13
$
4
(a) Includes capitalized interest of $3 million and $1 million for the three months ended June 30, 2017 and 2016, respectively.
(b) Includes capitalized interest of $44 million and $60 million for the three months ended June 30, 2017 and 2016, respectively.
(c) Includes capitalized interest of a nominal amount for the three months ended June 30, 2017 and 2016, respectively.
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
($ in millions)
(unaudited)
SIX MONTHS ENDED:
June 30,
June 30,
2017
2016
Beginning cash
$
882
$
825
Net cash used in operating activities
(58)
(326)
Cash flows from investing activities:
Drilling and completion costs(a)
(1,031)
(609)
Acquisitions of proved and unproved properties(b)
(162)
(426)
Proceeds from divestitures of proved and unproved properties
951
964
Additions to other property and equipment(c)
(7)
(25)
Proceeds from sales of other property and equipment
26
70
Cash paid for title defects
--
(69)
Other
--
(4)
Net cash used in investing activities
(223)
(99)
Net cash used in financing activities
(588)
(396)
Change in cash and cash equivalents
(869)
(821)
Ending cash
$
13
$
4
(a) Includes capitalized interest of $5 million and $3 million for the six months ended June 30, 2017 and 2016, respectively.
(b) Includes capitalized interest of $93 million and $124 million for the six months ended June 30, 2017 and 2016, respectively.
(c) Includes capitalized interest of a nominal amount and $1 million for the six months ended June 30, 2017 and 2016, respectively.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS
($ in millions except per share data)
(unaudited)
THREE MONTHS ENDED:
June 30, 2017
$
$/Diluted
Share(b)(c)
Net income available to common stockholders (GAAP)
$
470
$
0.47
Adjustments:
Unrealized gains on commodity derivatives
(202)
(0.18)
Provision for legal contingencies
17
0.02
Impairments of fixed assets and other
26
0.02
Net loss on sales of fixed assets
1
--
Gains on purchases or exchanges of debt
(191)
(0.17)
Income tax expense (benefit)(a)
--
--
Other
1
--
Adjusted net income available to common stockholders(b)
122
0.16
(Non-GAAP)
Preferred stock dividends
16
0.01
Earnings allocated to participating securities
8
0.01
Total adjusted net income attributable to Chesapeake(b) (c) $
146
$
0.18
(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 available to common stockholders and total adjusted net income 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 available to common stockholders or earnings per share.
Adjusted net income available to common stockholders and adjusted earnings 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 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.
(c) Our presentation of diluted adjusted net income (loss) per share excludes 1 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:
June 30, 2016
$
$/Diluted
Share(b)(c)
Net loss available to common stockholders (GAAP)
$
(1,818)
$
(2.51)
Adjustments:
Unrealized losses on commodity derivatives
544
0.75
Unrealized losses on supply contract derivatives
37
0.05
Restructuring and other termination costs
3
--
Provision for legal contingencies
71
0.10
Impairment of natural gas properties
1,070
1.48
Impairments of fixed assets and other
6
0.01
Net gains on sales of fixed assets
(1)
--
Gains on purchases or exchanges of debt
(68)
(0.09)
Income tax expense (benefit)(a)
--
--
Other
(1)
--
Adjusted net loss available to common stockholders(b)
(157)
(0.22)
(Non-GAAP)
Preferred stock dividends
42
0.06
Total adjusted net loss attributable to Chesapeake(b) (c) $
(115)
$
(0.16)
(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 loss available to common stockholders and total adjusted net 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 available to common stockholders or earnings per share.
Adjusted net income available to common stockholders and adjusted earnings 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 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.
(c) Our presentation of diluted adjusted net income (loss) per share excludes 114 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)
SIX MONTHS ENDED:
June 30, 2017
$
$/Diluted
Share(b)(c)
Net income available to common stockholders (GAAP)
$
547
$
0.59
Adjustments:
Unrealized gains on commodity derivatives
(528)
(0.51)
Provision for legal contingencies
15
0.01
Impairments of fixed assets and other
417
0.40
Net loss on sales of fixed assets
1
--
Gains on purchases or exchanges of debt
(184)
(0.17)
Loss on exchange of preferred stock
41
0.04
Income tax expense (benefit)(a)
--
--
Other
3
--
Adjusted net income available to common stockholders(b)
312
0.36
(Non-GAAP)
Preferred stock dividends
39
0.04
Earnings allocated to participating securities
7
0.01
Total adjusted net income attributable to Chesapeake(b) (c) $
358
$
0.41
(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 available to common stockholders and total adjusted net income 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 available to common stockholders or earnings per share.
Adjusted net income available to common stockholders and adjusted earnings 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 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.
(c) Our presentation of diluted adjusted net income (loss) per share excludes 62 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)
SIX MONTHS ENDED:
June 30, 2016
$
$/Diluted
Share(b)(c)
Net loss available to common stockholders (GAAP)
$
(2,929)
(4.21)
Adjustments:
Unrealized losses on commodity derivatives
586
0.84
Unrealized losses on supply contract derivatives
17
0.02
Restructuring and other termination costs
3
0.01
Provision for legal contingencies
104
0.15
Impairment of natural gas properties
2,067
2.97
Impairments of fixed assets and other
44
0.06
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
(168)
(0.24)
Income tax expense (benefit)(a)
--
--
Other
3
0.01
Adjusted net loss available to common stockholders(b)
(268)
(0.39)
(Non-GAAP)
Preferred stock dividends
85
0.13
Total adjusted net loss attributable to Chesapeake(b) (c) $
(183)
$
(0.26)
(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 loss available to common stockholders and total adjusted net 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 available to common stockholders or earnings per share.
Adjusted net income available to common stockholders and adjusted earnings 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 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.
(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:
June 30,
June 30,
2017
2016
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES
$
(157)
$
95
Changes in assets and liabilities
460
81
OPERATING CASH FLOW(a)
$
303
$
176
THREE MONTHS ENDED:
June 30,
June 30,
2017
2016
NET INCOME (LOSS)
$
495
$
(1,776)
Interest expense
93
62
Income tax expense
1
--
Depreciation and amortization of other assets
21
29
Oil, natural gas and NGL depreciation, depletion and amortization
202
277
EBITDA(b)
$
812
$
(1,408)
THREE MONTHS ENDED:
June 30,
June 30,
2017
2016
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES
$
(157)
$
95
Changes in assets and liabilities
460
81
Interest expense, net of unrealized gains (losses) on derivatives
92
60
Gains (losses) on commodity derivatives, net
200
(444)
Losses on supply contract derivatives, net
--
(37)
Cash (receipts) payments on commodity and supply contract derivative settlements, net
32
(119)
Stock-based compensation
(16)
(13)
Restructuring and other termination costs
--
(3)
Provision for legal contingencies
(17)
(71)
Impairment of oil and natural gas properties
--
(1,070)
Impairments of fixed assets and other
(4)
(1)
Net gains (losses) on sales of fixed assets
(1)
1
Investment activity
--
(2)
Gains on purchases or exchanges of debt
191
68
Other items
32
47
EBITDA(b)
$
812
$
(1,408)
(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 three months ended June 30, 2017 includes $23 million paid to terminate future natural gas transportation commitments.
(b) EBITDA represents net income before interest expense, income taxes, and depreciation, depletion and amortization expense. EBITDA is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies.
EBITDA is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our bank credit agreements and is used in the financial covenants in our bank credit agreements. EBITDA is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations or cash flows from operating activities prepared in accordance with GAAP.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
($ in millions)
(unaudited)
SIX MONTHS ENDED:
June 30,
June 30,
2017
2016
CASH USED IN OPERATING ACTIVITIES
$
(58)
$
(326)
Changes in assets and liabilities
347
765
OPERATING CASH FLOW(a)
$
289
$
439
SIX MONTHS ENDED:
June 30,
June 30,
2017
2016
NET INCOME (LOSS)
$
636
$
(2,844)
Interest expense
188
124
Income tax expense
2
--
Depreciation and amortization of other assets
42
58
Oil, natural gas and NGL depreciation, depletion and amortization
399
540
EBITDA(b)
$
1,267
$
(2,122)
SIX MONTHS ENDED:
June 30,
June 30,
2017
2016
CASH USED IN OPERATING ACTIVITIES
$
(58)
$
(326)
Changes in assets and liabilities
347
765
Interest expense, net of unrealized gains (losses) on derivatives
185
119
Gains (losses) on commodity derivatives, net
522
(263)
Losses on supply contract derivatives, net
--
(17)
Cash (receipts) payments on commodity and supply contract derivative settlements, net
66
(386)
Stock-based compensation
(27)
(25)
Restructuring and other termination costs
--
(3)
Provision for legal contingencies
(15)
(104)
Impairment of oil and natural gas properties
--
(2,067)
Impairments of fixed assets and other
(1)
(34)
Net gains (losses) on sales of fixed assets
(1)
5
Investment activity
--
(12)
Gains on purchases or exchanges of debt
185
168
Other items
64
58
EBITDA(b)
$
1,267
$
(2,122)
(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 six months ended June 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:
June 30,
June 30,
2017
2016
EBITDA
$
812
$
(1,408)
Adjustments:
Unrealized (gains) losses on commodity derivatives
(202)
544
Unrealized losses on supply contract derivatives
--
37
Restructuring and other termination costs
--
3
Provision for legal contingencies
17
71
Impairment of oil and natural gas properties
--
1,070
Impairments of fixed assets and other
26
6
Net (gains) losses on sales of fixed assets
1
(1)
Gains on purchases or exchanges of debt
(191)
(68)
Net income attributable to noncontrolling interests
(1)
--
Other
(1)
(2)
Adjusted EBITDA(a)
$
461
$
252
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED EBITDA
($ in millions)
(unaudited)
SIX MONTHS ENDED:
June 30,
June 30,
2017
2016
EBITDA
$
1,267
$
(2,122)
Adjustments:
Unrealized (gains) losses on commodity derivatives
(528)
586
Unrealized losses on supply contract derivatives
--
17
Restructuring and other termination costs
--
3
Provision for legal contingencies
15
104
Impairment of oil and natural gas properties
--
2,067
Impairments of fixed assets and other
417
44
Net (gains) losses on sales of fixed assets
1
(5)
Loss on sale of investment
--
10
Gains on purchases or exchanges of debt
(184)
(168)
Net income attributable to noncontrolling interests
(2)
--
Other
--
(2)
Adjusted EBITDA(a)
$
986
$
534
(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
RECONCILIATION OF PV-9 AND PV-10 TO STANDARDIZED MEASURE
($ in millions)
(unaudited)
PV-9 is a non-GAAP metric used in the determination of the value of collateral under Chesapeake’s credit facility. PV-10 is a non-GAAP metric used by the industry, investors and analysts to estimate the present value, discounted at 10% per annum, of estimated future cash flows of the company’s estimated proved reserves before income tax. The following table shows the reconciliation of PV-9 and PV-10 to the company’s standardized measure of discounted future net cash flows, the most directly comparable GAAP measure, for the year ended December 31, 2016 and for the interim period ended June 30, 2017. Management believes that PV-9 provides useful information to investors regarding the company’s collateral position and that PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, management believes the use of a pre-tax measure is valuable for evaluating the company. Neither PV-9 nor PV-10 should be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP. With respect to PV-9 and PV-10 calculated as of an interim date, it is not practical to calculate taxes for the related interim period because GAAP does not provide for disclosure of standardized measure on an interim basis.
PV-9 - June 30, 2017 @ NYMEX Strip
$
8,960
Less: Change in discount factor from 9 to 10
(512)
PV-10 - June 30, 2017 @ NYMEX Strip
8,448
Less: Change in pricing assumption from NYMEX Strip to SEC
(587)
PV-10 - June 30, 2017 @ SEC
7,861
Less: Change in PV-10 from 12/31/16 to 6/30/2017
(3,456)
PV-10 - December 31, 2016 @ SEC
4,405
Less: Present value of future income tax discounted at 10%
(26)
Standardized measure of discounted future cash flows - December 31, 2016
$
4,379
CHESAPEAKE ENERGY CORPORATION
MANAGEMENT’S OUTLOOK AS OF AUGUST 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 May 3, 2017 Outlook are italicized bold below.
Year Ending
12/31/2017
Adjusted Production Growth(a)
0% to 4%
Absolute Production
Liquids - mmbbls
52.5 - 55.0
Oil - mmbbls
33.5 - 35.0
NGL - mmbbls
19.0 - 20.0
Natural gas - bcf
870 - 900
Total absolute production - mmboe
197.5 - 205.0
Absolute daily rate - mboe
541 - 562
Estimated Realized Hedging Effects(b) (based on 7/31/17 strip prices):
Oil - $/bbl
$2.87
Natural gas - $/mcf
($0.01)
NGL - $/bbl
$0.04
Estimated Basis to NYMEX Prices:
Oil - $/bbl
$1.05 - $1.25
Natural gas - $/mcf
$0.30 - $0.40
NGL - $/bbl
$3.75 - $4.15
Operating Costs per Boe of Projected Production:
Production expense
$2.50 - $2.70
Gathering, processing and transportation expenses
$7.00 - $7.50
Oil - $/bbl
$4.00 - $4.20
Natural Gas - $/mcf
$1.25 - $1.35
NGL - $/bbl
$8.00 - $8.40
Production taxes
$0.40 - $0.50
General and administrative(c)
$1.20 - $1.30
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)
$2.00 - $2.10
Marketing, gathering and compression net margin(e)
($80) - ($60)
Book Tax Rate
0%
Capital Expenditures ($ in millions)(f)
$1,900 - $2,300
Capitalized Interest ($ in millions)
$200
Total Capital Expenditures ($ in millions)
$2,100 - $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 July 31, 2017, the company had downside protection, through open swaps, on a portion of its remaining 2017 oil production at an average price of $50.32 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 $3.09 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 $0.66 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 $3.09 per mcf. Chesapeake also had downside price protection through open swaps on a portion of its 2018 oil production at an average price of $51.78 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 July 31, 2017 were as follows:

Open Crude Oil Swaps
Gains (Losses) from Closed Crude Oil Trades
Open Swaps
Avg. NYMEX
Gains/Losses from
(mbbls)
Price of
Closed Trades
Open Swaps
($ in millions)
Q3 2017
5,612
$
50.27
$
23
Q4 2017
5,612
$
50.36
23
Total 2017
11,224
$
50.32
$
46
Q1 2018
900
$
51.96
$
(1)
Q2 2018
910
$
51.96
(1)
Q3 2018
460
$
51.43
(1)
Q4 2018
460
$
51.43
(1)
Total 2018
2,730
$
51.78
$
(4)
Total 2019 - 2022
$
(8)
Crude Oil Net Written Call Options
Call Options
Avg. NYMEX
(mbbls)
Strike Price
Q3 2017
1,334
$
83.50
Q4 2017
1,334
$
83.50
Total 2017
2,668
$
83.50
Q3 2018
460
$
52.49
Q4 2018
460
$
52.49
Total 2018
920
$
52.49
Crude Oil Three-Way Collars
Open Collars
(mmbbls)
Avg. NYMEX
Avg. NYMEX
Avg. NYMEX
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

The company’s natural gas hedging positions as of July 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
Open Swaps Trades
($ in millions)
Q3 2017
158
$
3.00
$
(1)
Q4 2017
164
$
3.16
(3)
Total 2017
322
$
3.08
$
(4)
Q1 2018
163
$
3.45
$
(6)
Q1 2018
107
$
2.89
(4)
Q3 2018
109
$
2.90
(4)
Q4 2018
109
$
2.98
(6)
Total 2018
488
$
3.10
$
(20)
Total 2019 - 2022
$
(49)
Natural Gas Two-Way Collars
Open Collars
(bcf)
Avg. NYMEX Avg. NYMEX
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
Q3 2017
12
$
9.43
Q4 2017
12
$
9.43
Total 2017
24
$
9.43
Total 2018 - 2020
66
$
12.00
Natural Gas Basis Protection Swaps
Volume
Avg. NYMEX
(bcf)
plus/(minus)
Q3 2017
6
$
(0.46)
Q4 2017
6
$
(0.46)
Total 2017
12
$
(0.46)
Total 2018 - 2022
1
$
(1.03)

The company’s natural gas liquids hedging positions as of July 31, 2017 were as follows:

Open Propane Swaps
Volume
Avg. NYMEX
(mmgal)
Price of Open
Swaps
Q3 2017
17
$
0.66
Total 2017
17
$
0.66

View original content:http://www.prnewswire.com/news-releases/chesapeake-energy-corporation-reports-2017-second-quarter-fi

SOURCE Chesapeake Energy Corporation

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