Scotia Howard Weil Energy Conference · and other announcements the Company makes from time to...
Transcript of Scotia Howard Weil Energy Conference · and other announcements the Company makes from time to...
Scotia Howard Weil Energy Conference March 2017
Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995 This presentation includes “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. All statements included in this presentation other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company’s business and statements or information concerning the Company’s future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows, are forward-looking statements. When used in this presentation, the words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget,” “plan,” “continue,” “potential,” “guidance,” “strategy,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Forward-looking statements are based on the Company’s current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company’s control. No assurance can be given that such expectations will be correct or achieved or the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial, market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas exploration, drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other revenue-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A Risk Factors and elsewhere in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this presentation occur, or should underlying assumptions prove incorrect, the Company’s actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as expressly stated above or otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this presentation, or otherwise. Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates. We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Forward-Looking Information
2
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
~1.78 Million Net Reservoir Acres
NORTH
SOUTH
Continental Resources Celebrating 50 Years of Organic Growth
3
MT Bakken
ND Bakken
Arkoma Woodford
Anadarko Woodford
SCOOP Woodford
SCOOP Springer
STACK Meramec
Cedar Hills
Boe
pd
BAKKEN
SCOOP
STACK
Play Net Acres
Bakken: ~848,000
STACK:
Meramec ~200,000
Woodford ~185,000
SCOOP:
Springer ~200,000
Woodford ~346,000
250,000
225,000
200,000
175,000
150,000
125,000
100,000
75,000
50,000
25,000
2017
Performance Taken to New Level Last 2 Years Structural Improvements Benefiting 2017 and Beyond
$5.49 $5.69 $5.58 $4.30 $3.65
$2.38 $2.07 $2.06 $1.70
$1.53
$7.87 $7.76 $7.64
$6.00 $5.18
$0
$2
$4
$6
$8
$10
2012 2013 2014 2015 2016
$/B
oe
Production and Cash G&A Costs
Cash G&A
1. See “Cash G&A Reconciliation to GAAP“ on slide 23 for a reconciliation of GAAP Total G&A per Boe to Cash G&A per Boe, which is a non-GAAP measure 2. Capital efficiency based on reserves developed per dollar invested; average net revenue interest of 82% assumed for net capital efficiency
Production Expense
470 506 711
1,110
1,416
41 47 54
104
149
0
40
80
120
160
0200400600800
1,0001,2001,4001,600
2012 2013 2014 2015 2016
Net
Boe
/$1,
000(2
)
EUR Per Operated Well
• Capital efficiency(2) UP ~175% • EUR/operated well UP ~100% • Production expense & cash
G&A(1) DOWN ~32%
Boe/$1k Boe/$1k Boe/$1k
Boe/$1k
Boe/$1k
(1)
2016 vs 2014
Key Drivers
MB
oe
(1)
4
• Added STACK • Moved to Bakken core • Enhanced completions • Operating efficiencies
Boe/$1k
2017: Disciplined Growth Targeting 20%+ Increase in Production by Year End
5
$1.95 billion capital budget (~90% D&C)
• 20 rigs vs. 19 rigs in 2016 • ~11 stim crews vs. ~4 stim crews in 2016 • Over 2X more operated completions than 2016
Oil-weighted production growth
• Targeting 250,000 to 260,000 Boepd 2017 exit rate • 82% of D&C capex allocated to Bakken & STACK (75% oil)
No new debt • Capital budget cash flow neutral at $55 WTI and $3.14 gas • Targeting over $600 million of additional non-strategic
asset sales in 2017
Momentum carries into 2018
• ~72 Bakken stimulated wells waiting on first production at year-end 2017
• Targeting 290,000 to 310,000 Boepd 2018 exit rate
2017 Capital Focused on High ROR Oil Plays
Play Capital ($ in MM)
% of D&C Budget ROR % Oil
Est. Total % Liquids
Bakken DUCs $550 32% 100%+ 80% 90% Bakken Drilling $490 28% ~40% 80% 90% STACK $375 22% 100%+ 60% 70% SCOOP $245 14% ~55% 20% 55% NW Cana $60 4% 100%+ 2% 20% Total D&C Program (weighted avg) $1,720 100% - 58% 73%
Non-D&C Capital (land, facilities, other) $230 - - -
Total 2017 Capital $1,950 - - -
1. Inclusive of capital for outside operated activity, except for Bakken DUCs 2.At $55 WTI and $3.50 gas, see footnote 1 on slide 11 3.Based upon 2-stream oil volumes at the wellhead 4.Based upon theoretical NGL recoveries after processing
5.ROR is on the incremental cost forward cost of completion 6.STACK ROR is based on STACK over-pressured oil wells 7.SCOOP ROR is based on SCOOP Woodford condensate wells 8.NW Cana as part of the JDA with SK E&S
(1) (2) (3) (4)
(5)
(6)
(7)
(8)
6
82% of D&C capex allocated to Bakken and STACK (75% oil)
2017 Sets Up Multi-Year Double-Digit Growth
7
0
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
450,000
2012 2013 2014 2015 2016 2017E 2018E 2019E 2020E
STACKSCOOPBakkenLegacy
9%
~225,000 (Midpoint)
Production guidance:
• 2017 exit rate: 250,000 to 260,000 Boe per day
• 2018 exit rate: 290,000 to 310,000 Boe per day
• Oil production growing to 60%-65% of total production
Annual Production Chart
0
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
450,000
500,000
4Q 2016 4Q 2017E 4Q 2018E 4Q 2019E 4Q 2020E
STACKSCOOPBakkenLegacy
~210,000
~255,000 (Exit rate)
Fourth Quarter Production Chart
Boe
per
day
Boe p
er da
y
Completion Technology Continues to Increase Well Performance in all Plays
8
0
40,000
80,000
120,000
0 50 100 150 200
Cum
Boe
Days
Bakken
90 days 35% higher than
type curve
0
50,000
100,000
150,000
200,000
0 50 100 150 200
Cum
Boe
Days
SCOOP Woodford Oil
SCOOP Enhanced completions SCOOP Offsets SCOOP Enhanced Type Curve (1,340 MBoe)
0
150,000
300,000
450,000
0 50 100 150 200
Cum
Boe
Days
SCOOP Woodford Condensate SCOOP Enhanced CompletionsSCOOP OffsetsSCOOP Enhanced Type Curve (2,300 MBOE)
180 days 45% Uplift
180 days 30% Uplift
Bakken Enhanced completions average Bakken Enhanced Type Curve (980 MBoe)
• Higher proppant loads
• Increased fluid volumes
• Shorter stage lengths
• More aggressive flowbacks and lift
200,000 net acres • ~98% in over-pressured window
• ~40% oil, ~30% liquids-rich, ~30% gas
~1,500 potential net unrisked drilling locations
7 completions announced 4Q16 • 1,600–2,500 Boepd 24-hr IPs
• 55%-73% oil
As of late February, 35 operated wells in progress 12 rigs drilling (7 Meramec, 5 Woodford)
Wells Drilling / Completing
CLR Leasehold CLR Rigs Industry Rigs Industry Meramec well CLR Meramec producing wells CLR Meramec wells drilling / completing
Over-Pressured
Normally-Pressured Intermediate pipe required
STACK Expansion Continues with Excellent Results
9
STACK 2017 Drilling Program Focused on Density Development and Play Expansion ~47,000 net acres under development in oil window
• ~55 operated units
• ~60% operated working interest
6 units scheduled for 2017
• 5 units in oil window
• 1 unit in condensate window
• Testing 4 to 6 wells per zone
Unit efficiencies further uplift economics
Density Activity
De-risked portion of over-pressured oil
window
6 units scheduled
for 2017
CLR Leasehold CLR Rigs Industry Rigs Industry Meramec well CLR Meramec producing wells CLR Meramec wells drilling / completing
10
0%
20%
40%
60%
80%
100%
$30 $40 $50 $60 $70
RO
R
WTI Oil Price, $/BBL
STACK Over-Pressured Oil $9.0MM Budget 2017$7.8MM Budget
$9.0MM standalone CWC $7.8MM density CWC
Target EUR: 1,700 MBOE Avg. Lateral: 9,800’
1.Pre-tax rate of return (ROR) is based on projected cash flow and time value of money; costs include completed well cost, production expense, severance tax and variable operating costs. $3.50 gas is used for oil price sensitivities and $55 WTI is used for gas price sensitivities. The description of the ROR calculation applies to any ROR reference appearing in this presentation.
100
1000
10000
0 30 60 90 120
Boe
pd
Days on Production
710’
MICROSEISMIC SURVEY
1 Mile
Outstanding First STACK Density Test in Meramec Over-Pressured Oil Window
660’ 175’
1,320’
New Well Parent Well
Hunton
Upper Meramec
Middle Meramec
Osage Woodford
Lower Meramec
21,354 Boe per day (70% oil) from 8 Meramec wells (combined peak 24-hour rates)
Efficiency gains: • 30% reduction in CWC ($7.8 million)
• 36% reduction in drill time (25 days)
CLR: Ludwig Density
Ludwig Daily Production(1)
1. Normalized to 9,800’ lateral
Parent well 7 New wells 1,700 MBoe type curve
11
SCOOP Woodford Condensate Enhanced Stimulations Uplift EURs Another 15%
12
EUR 2,300 MBoe per well (7,500’ lateral) • Up from 2,000 MBoe EUR 80% ROR(1) for $10.3 million CWC Two completions announced 4Q 2016: • 3,547 and 3,463 Boepd 24-hr IPs • 26% and 29% oil • 3,220 and 3,160 psi flowing casing pressure
1. Assumes $55 oil and $3.50 gas. Pre-tax rate of return (ROR) is based on projected cash flow and time value of money; costs include completed well cost, production expense, severance tax and variable operating costs. $3.50 gas is used for oil price sensitivities and $55 WTI is used for gas price sensitivities. The description of the ROR calculation applies to any ROR reference appearing in this presentation.
Peppered Ranch
Boatright
12 Miles CLR Leasehold
Woodford HZ Producing Well
CLR Enhanced Completion
Gas Condensate Oil
0%
20%
40%
60%
80%
100%
$2 $3 $4
RO
R
Gas Price, $/MCF
SCOOP Woodford Condensate
$10.3MM Budget 2017 (2,300 MBOE)
~80% ROR
Target EUR: 2,300 MBOE Avg. Lateral: 7,500’
MB, TF1, TF2, TF3
MB, TF1, TF2
MB & TF1
MB & TF1
MB or TF1
MB or TF1
Charolais North 1-31H1
IP: 2,761 Boe
Brangus North 1-2H2
IP: 2,493 Boe
Rath Federal 5-22H
IP: 2,395 Boe
Corsican Federal 1-15H
IP: 1,836 Boe
Holstein Federal 13-25H
IP: 2,718 Boe Maryland 2-16H
IP: 1,264 Boe
Nashville 2-21H IP: 1,417 Boe
CLR Leasehold
CLR Larger Enhanced Completion
50 Miles
Three Record CLR Bakken Wells in Last Two Quarters
13
Note: Larger enhanced completions defined by 7 initial unit wells with greater than 720 lb/ft proppant 1. Normalized to 9,800’ lateral
Larger stimulations and more aggressive flowback resulted in record 30-day rates: • Brangus North, Holstein Federal & Rath Federal
Wells performing above 980 MBoe type curve(1)
(initial wells on unit)
Larger enhanced completions well locations
0
20,000
40,000
60,000
80,000
100,000
120,000
0 20 40 60 80 100
Cum
Boe
Normalized Days
90 days 35% higher than type
curve
14
~148 Bakken wells to be completed in 2017 (90% drilled but uncompleted) Average 7 operated stimulation crews ~72 additional wells stimulated at year-end 2017 with first sales in 2018
Harvesting Uncompleted Bakken Wells Underway
0%
20%
40%
60%
80%
100%
$40 $50 $60 $70
RO
R
WTI Oil Price, $/BBL
Bakken
$4.9MM DUC Budget 2017(980 MBOE)
$7MM Drilling Budget 2017(920 MBOE)
~40% ROR
Drilling Target EUR: 920 MBOE DUC EUR: 980 MBOE Avg. Lateral: 9,800’
Note: Pre-tax rate of return (ROR) is based on projected cash flow and time value of money; costs include completed well cost, production expense, severance tax and variable operating costs. $3.50 gas is used for oil price sensitivities and $55 WTI is used for gas price sensitivities. The description of the ROR calculation applies to any ROR reference appearing in this presentation. 1.$4.9 MM gross cost forward incremental completion cost
~100% ROR
(1)
CLR Leasehold
CLR YE 2016 uncompleted well
50 Miles
Uncompleted well locations
North Dakota Pipeline Authority and CLR estimates
-
500
1,000
1,500
2,000
2,500
3,000
3,500
2009 2010 2011 2012 2013 2014 2015 2016 2017EST
Local Refining Pipeline Rail Bakken Production
Thou
sand
Bop
d
Bakken Takeaway Capacity
Bakken Differentials Improving with Added Pipeline Takeaway Capacity
15
More than 90% of CLR Bakken barrels on pipe
With completion of DAPL, pipeline takeaway capacity should exceed production in 2017 Basin differentials may drop by $2 or more
Pi
pe
Rai
l
Low Costs(1) Competitively Positions CLR in Any Environment
16
1. Margin presented on this slide represents the Company’s average sales price for a period expressed in barrels of oil equivalent (Boe) less production expenses, production taxes, G&A expenses (exclusive of non-cash equity compensation expenses), and interest expense, all expressed on a per-Boe basis. Margin does not reflect all activities of the Company that give rise to cash inflows and outflows and specifically excludes income and costs associated with derivative settlements, service operations, exploration activities, asset dispositions, and various non-operating activities. These items are excluded from the computation of Margin because they can vary significantly from period to period in a manner that does not correlate with changes in the Company’s production and sales volumes. Therefore, these items are not typically utilized by management on a per-Boe basis in assessing the performance of the Company’s E&P operations from period to period. See “Continuing to Deliver Strong Margins” on slide 19 for additional details on the method for calculating margin.
2. See “Cash G&A Reconciliation to GAAP“ on slide 23 for a reconciliation of GAAP Total G&A per Boe to Cash G&A per Boe, which is a non-GAAP measure. 3. Based on average oil equivalent price (excluding derivatives and including natural gas.)
$6.89 $5.87 $6.13 $5.49 $5.69 $5.58 $4.30 $3.65
$2.19 $2.35 $2.36 $2.38 $2.07 $2.06 $1.70 $1.53
$2.95 $4.47 $5.82 $5.58 $6.02 $5.54 $2.47 $1.79
$1.72 $3.34 $3.40 $3.95 $4.74 $4.49
$3.86 $4.04
$30.93
$43.32
$54.74
$48.59
$53.52 $48.86
$19.15
$14.54
$44.68
$59.35
$72.45 $65.99
$72.04 $66.53
$31.48 $25.55
$0
$10
$20
$30
$40
$50
$60
$70
$80
2009 2010 2011 2012 2013 2014 2015 2016
69% 73%
76% 74% 74%
73% $11.01 per Boe
Production Expense Cash G&A(2) Production/Severance Tax & Other Interest Margin(1)
61% 57% Avg.
Rea
lized
$/B
oe(3
)
• Depth and quality of inventory has never been better
• Capital efficiencies at all-time high
• Production expense and cash G&A among the lowest in the E&P space
• Debt reduced by ~$600 million in 2016
• ~20% projected production growth (exit-rate 2017 over 4Q 2016)
• 82% of 2017 D&C capex focused on oil-weighted Bakken and STACK
• Targeting debt reduction by another ~$600 million in 2017 through non-
strategic asset sales
Continental Resources - In Closing
17
APPENDIX
18
1. Margin represents the Company’s average sales price for a period expressed in barrels of oil equivalent (Boe) less production expenses, production taxes, G&A expenses (exclusive of non-cash equity compensation expenses), and interest expense, all expressed on a per-Boe basis. Margin does not reflect all activities of the Company that give rise to cash inflows and outflows and specifically excludes income and costs associated with derivative settlements, service operations, exploration activities, asset dispositions, and various non-operating activities. These items are excluded from the computation of Margin because they can vary significantly from period to period in a manner that does not correlate with changes in the Company’s production and sales volumes. Therefore, these items are not typically utilized by management on a per-Boe basis in assessing the performance of the Company’s E&P operations from period to period.
2. See “EBITDAX reconciliation to GAAP” on slide 35 for a reconciliation of GAAP net income and net cash provided by operating activities to EBITDAX, which is a non-GAAP measure. 3. Average costs per Boe have been computed using sales volumes and exclude any effect of derivative transactions. 4. See “Cash G&A Reconciliation to GAAP“ on slide 37 for a reconciliation of GAAP Total G&A per Boe to Cash G&A per Boe, which is a non-GAAP measure.
2009 2010 2011 2012 2013 2014 2015 4Q 2016 2016
Realized oil price ($/Bbl) $54.44 $70.69 $88.51 $84.59 $89.93 $81.26 $40.50 $42.23 $35.51
Realized natural gas price ($/Mcf) $2.95 $4.26 $4.87 $3.73 $4.87 $5.40 $2.31 $2.70 $1.87 Oil production (Bopd) 27,459 32,385 45,121 68,497 95,859 121,999 146,622 116,486 128,005 Natural gas production (Mcfpd) 59,194 65,598 100,469 174,521 240,355 313,137 450,558 560,251 533,442 Total production (Boepd) 37,324 43,318 61,865 97,583 135,919 174,189 221,715 209,861 216,912
EBITDAX ($000's)(2) $450,648 $810,877 $1,303,959 $1,963,123 $2,839,510 $3,776,051 $1,978,896 $652,382 $1,881,889 Key Operational Statistics (per Boe)(3) Average oil equivalent price (excludes derivatives) $44.68 $59.35 $72.45 $65.99 $72.04 $66.53 $31.48 $30.64 $25.55
Production expense $6.89 $5.87 $6.13 $5.49 $5.69 $5.58 $4.30 $3.60 $3.65
Production tax and other $2.95 $4.47 $5.82 $5.58 $6.02 $5.54 $2.47 $1.98 $1.79
Cash G&A(4) $2.19 $2.35 $2.36 $2.38 $2.07 $2.06 $1.70 $2.21 $1.53 Interest $1.72 $3.34 $3.40 $3.95 $4.74 $4.49 $3.86 $3.92 $4.04
Total of selected costs $13.75 $16.03 $17.71 $17.40 $18.52 $17.67 $12.33 $11.71 $11.01 Margin(1) $30.93 $43.32 $54.74 $48.59 $53.52 $48.86 $19.15 $18.93 $14.54 Margin % 69% 73% 76% 74% 74% 73% 61% 62% 57%
Continuing to Deliver Strong Margins(1)
19
We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. We define EBITDAX as earnings (net income (loss)) before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and losses on extinguishment of debt. EBITDAX is not a measure of net income or net cash provided by operating activities as determined by GAAP. Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe that EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income (loss) and net cash provided by operating activities in arriving at EBITDAX because those amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) or net cash provided by operating activities as determined in accordance with GAAP or as an indicator of a company’s operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies. See the following page for reconciliations of our net income (loss) and net cash provided by operating activities to EBITDAX for the applicable periods.
EBITDAX Reconciliation to GAAP
20
The following tables provide reconciliations of our net income (loss) and net cash provided by operating activities to EBITDAX for the periods presented:
In thousands 2009 2010 2011 2012 2013 2014 2015 4Q 2016 2016
Net income (loss) $ 71,338 $ 168,255 $ 429,072 $ 739,385 $ 764,219 $ 977,341 $ (353,668) $ 27,670 $ (399,679) Interest expense 23,232 53,147 76,722 140,708 235,275 283,928 313,079 75,613 320,562
Provision (benefit) for income taxes 38,670 90,212 258,373 415,811 448,830 584,697 (181,417) 26,478 (232,775)
Depreciation, depletion, amortization and accretion 207,602 243,601 390,899 692,118 965,645 1,358,669 1,749,056 388,321 1,708,744
Property impairments 83,694 64,951 108,458 122,274 220,508 616,888 402,131 34,564 237,292
Exploration expenses 12,615 12,763 27,920 23,507 34,947 50,067 19,413 8,246 16,972
Impact from derivative instruments:
Total (gain) loss on derivatives, net 1,520 130,762 30,049 (154,016) 191,751 (559,759) (91,085) 45,331 67,099
Total cash received (paid), net 569 35,495 (34,106) (45,721) (61,555) 385,350 69,553 6,281 89,522
Non-cash (gain) loss on derivatives, net 2,089 166,257 (4,057) (199,737) 130,196 (174,409) (21,532) 51,612 156,621
Non-cash equity compensation 11,408 11,691 16,572 29,057 39,890 54,353 51,834 13,823 48,097
Loss on extinguishment of debt -- -- -- -- -- 24,517 -- 26,055 26,055
EBITDAX (non-GAAP) $ 450,648 $ 810,877 $ 1,303,959 $ 1,963,123 $ 2,839,510 $ 3,776,051 $ 1,978,896 $ 652,382 $ 1,881,889
In thousands 2009 2010 2011 2012 2013 2014 2015 4Q 2016 2016
Net cash provided by operating activities $ 372,986 $ 653,167 $ 1,067,915 $ 1,632,065 $ 2,563,295 $ 3,355,715 $ 1,857,101 $ 262,031 $ 1,125,919 Current income tax provision (benefit) 2,551 12,853 13,170 10,517 6,209 20 24 (22,941) (22,939) Interest expense 23,232 53,147 76,722 140,708 235,275 283,928 313,079 75,613 320,562 Exploration expenses, excluding dry hole costs 6,138 9,739 19,971 22,740 25,597 26,388 11,032 3,613 12,106 Gain on sale of assets, net 709 29,588 20,838 136,047 88 600 23,149 201,315 304,489 Tax benefit (deficiency) from stock-based compensation 2,872 5,230 -- 15,618 -- -- 13,177 (368) (9,828) Other, net (3,890) (3,513) (4,606) (7,587) (1,829) (17,279) (10,044) (1,613) (10,636) Changes in assets and liabilities 46,050 50,666 109,949 13,015 10,875 126,679 (228,622) 134,732 162,216 EBITDAX (non-GAAP) $ 450,648 $ 810,877 $ 1,303,959 $ 1,963,123 $ 2,839,510 $ 3,776,051 $ 1,978,896 $ 652,382 $ 1,881,889
EBITDAX Reconciliation to GAAP
21
ADJUSTED Earnings Reconciliation to GAAP
22
Our presentation of adjusted earnings and adjusted earnings per share that exclude the effect of certain items are non-GAAP financial
measures. Adjusted earnings and adjusted earnings per share represent earnings and diluted earnings per share determined under
U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, gains and losses on asset
sales and losses on extinguishment of debt. Management believes these measures provide useful information to analysts and
investors for analysis of our operating results. In addition, management believes these measures are used by analysts and others in
valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to
an entity’s specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted earnings and adjusted earnings
per share should not be considered in isolation or as a substitute for earnings or diluted earnings per share as determined in
accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following tables
reconcile earnings and diluted earnings per share as determined under U.S. GAAP to adjusted earnings and adjusted diluted earnings
per share for the periods presented.
4Q 2016 4Q 2015 2016 2015
In thousands, except per share data $ Diluted EPS $ Diluted EPS $ Diluted EPS $ Diluted EPS
Net income (loss) (GAAP) $ 27,670 $ 0.07 $ (139,677) $ (0.38) $(399,679) $ (1.08) $(353,668) $ (0.96)
Adjustments:
Non-cash (gain) loss on derivatives 51,612 4,479 156,621 (21,532)
Property impairments 34,564 81,001 237,292 402,131
Gain on sale of assets (201,315) (218) (304,489) (23,149)
Loss on extinguishment of debt 26,055 - 26,055
Total tax effect of adjustments 33,998 (32,229) (42,448) (119,307)
Total adjustments, net of tax (55,086) (0.14) 53,033 0.15 73,031 0.20 238,143 0.65
Adjusted net income (loss) (Non-GAAP) $ (27,416) $ (0.07) $ (86,644) $ (0.23) $ (326,648) $ (0.88) $ (115,525) $ (0.31)
Weighted average diluted shares outstanding 370,539 369,662 370,380 369,540
Adjusted diluted net income (loss) per share (Non-GAAP) $ (0.07) $ (0.23) $ (0.88) $ (0.31)
Cash G&A Reconciliation to GAAP
23
Our presentation of cash general and administrative (“G&A”) expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses and corporate relocation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following table reconciles total G&A per Boe as determined under U.S. GAAP to cash G&A per Boe for the periods presented.
2009 2010 2011 2012 2013 2014 2015 4Q 2016 2016 2017 Guidance Total G&A per Boe (GAAP) $3.03 $3.09 $3.23 $3.42 $2.91 $2.92 $2.34 $2.93 $2.14 $2.10 - $2.70 Less: Non-cash equity compensation per Boe ($0.84) ($0.74) ($0.73) ($0.82) ($0.80) ($0.86) ($0.64) ($0.72) ($0.61) ($0.60) – ($0.70)
Less: Relocation expenses per Boe -
- ($0.14) ($0.22) ($0.04)
-
- -
- -
Cash G&A per Boe (non-GAAP) $2.19 $2.35 $2.36 $2.38 $2.07 $2.06 $1.70 $2.21 $1.53 $1.50 - $2.00