1Q14 Earnings Supplement

1Q14
Earnings Supplement
May 7, 2014
Forward-Looking Information
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,
statements or information concerning the Company’s future operations, performance, financial condition, production and reserves, schedules,
plans, timing of development, returns, budgets, costs, business strategy, objectives, and cash flow, 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 the expectations
reflected in the forward-looking statements are reasonable and based on reasonable assumptions, no assurance can be given that such expectations
will be correct or achieved or that the assumptions are accurate. When considering forward-looking statements, readers should keep in mind the
risk factors and other cautionary statements described under Part I, Item 1A. Risk Factors included in the Company’s Annual Report on Form 10-K for
the year ended December 31, 2013, registration statements and other reports filed from time to time with the Securities and Exchange Commission
(“SEC”), and other announcements the Company makes from time to time.
The Company cautions readers these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to
predict and many of which are beyond the Company’s control, incident to the exploration for, and development, production, and sale of, crude oil
and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling, completion and
production equipment and services and transportation infrastructure, environmental risks, drilling and other operating risks, lack of availability and
security of computer-based systems, regulatory changes, the uncertainty inherent in estimating crude oil and natural gas reserves and in projecting
future rates of production, cash flows and access to capital, the timing of development expenditures, and the other risks described under Part I,
Item 1A. Risk Factors in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013, 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 hereof. 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. This cautionary statement should also be considered in connection with any subsequent written or oral
forward-looking statements that the Company, or persons acting on its behalf, may make.
Except as otherwise required by applicable law, the Company disclaims any duty to update any forward-looking statements to reflect events or
circumstances after the date of this presentation.
2
Organic Growth through Exploration, Development
and Advances in Technology
• NYSE listed: CLR
•
Enterprise Value: ~$30B⁽¹⁾
• Market Cap: ~$25B
• Total Debt: ~$5B
• Straight forward strategy
•
•
Disciplined growth: 5-Year plan to triple
production and proved reserves⁽²⁾
Investment grade, pure play E&P company⁽³⁾
~1.2 Million Net
Acres Leased
~425,000 Net
Acres Leased
• 2014 CAPEX budget: $4.05 billion⁽⁴⁾
•
•
384 net wells (1,060 gross)
2014 production growth estimate: 26% – 32%
• #1 oil producer in the Rockies
• Focused in two premier, oil-weighted plays with decades of organic
growth
•
•
•
Largest leaseholder, driller and producer in the Bakken
Largest independent leaseholder, driller and producer in the SCOOP
Repeatable, low-risk inventory
(1) Market cap as of 5/7/14 and total debt as of 3/31/2014 (2) 5-year plan announced Oct. 2012 at CLR Investor Day
(3) Rated investment grade by Moody’s and Standard & Poors (4) CLR capex guidance excludes acquisition capital
3
1Q14 Operational & Financial Highlights
•
1Q14 production: 152,500 Boe per day, up 25%
since 1Q13 (70% oil)
•
•
•
Bakken: 97,500 Boe per day, up 27% over 1Q13
SCOOP: 29,400 Boe per day, up 106% over 1Q13
EBITDAX⁽¹⁾ ($MM)
$3,000
$2,840
YE13 proved reserves: 1.08 billion Boe, up 38% YOY
1Q EBITDAX⁽¹⁾
•
•
1Q14 EBITDAX⁽¹⁾ of $775 million, up 25% since 1Q13
Marketing strategy and opex focus drive strong
cash margin⁽²⁾
•
•
75% cash margin ($56.27 per Boe) in 1Q14
74% cash margin ($53.52 per Boe) for FY13
$2,500
FY EBITDAX⁽¹⁾
$1,963
$2,000
$1,500
$1,304
$1,000
•
$811
Capital discipline driving value
•
•
Capex outspend narrowing ⁽³⁾
Top tier performance:
•
Leveraged recycle ratio: 4.25x
$500
$451
$622
$0
2009
(1) See “EBITDAX Reconciliation to GAAP” in the Appendix for a reconciliation of GAAP net income and operating cash
flows to EBITDAX. (2) See “Cost Discipline Driving Excellent Margins” in the Appendix for the method of calculating cash
margin. (3) CLR capex guidance excludes acquisition capital
$775
2010
2011
2012
2013 1Q14
4
There’s Only One Bakken: Getting Bigger & Better
•
Leading basin-wide efforts to optimize oil recovery
•
2014 plan: 287 net wells (870 gross)
• Operating ~21 average rigs in 2014
• Initiated industry’s first full-field development in
Tangsrud*
1,320’
LTF
660’
Lawrence**
LTF
prolific Antelope area (MB, TF1, TF2 and TF3)
7 density projects testing spacing to optimize
recovery
• Production from 660’ density projects expected in
2H14.
•
•
WLL
LTF LTF
LTF
WLL
LTF
LTF
KOG x3
LTF
COP x6
Wahpeton**
660’
WLL
LTF
LTF
LTF
660’
Mack**
1,320’
Rollefstad*
LTF
LTF
OAS
Large systematic program (20% of wells) testing
enhanced stimulation and completion designs
with encouraging early results.
Expanding both storage and takeaway capacity &
flexibility
• Transporting ~70% of crude by rail
• Additional committed pipeline capacity available in
•
2H14
Adding 240,000 working barrels of storage capacity
*1,320’ interwell spacing within zone = 320 acre spacing on 2 mile lateral
**660’ interwell spacing within zone = 160 acre spacing on 2 mile lateral
WLL
KOG
LTF
LTF
LTF
Productive
Footprint
Montana
North Dakota
•
1,320’
Hawkinson*
660’
Hartman**
25 Miles
WLL
2013 CLR Density Project
Industry Density Project
CLR LTF Producer
2014 CLR Density Project
Industry LTF Producer
5
Continued Robust Hawkinson Performance
• Continued strong production after
150+ days
• 13 of 14 wells trending on average 50%
above 603 MBoe model EUR
•
Hawkinson Unit
1,320’ Pilot
Completed using standard design with
~100,000 pounds of proppant per stage
(30 total stages)
• To date the original existing 3 wells
continue to produce on average at or
better than prior to drilling and
completing the additional 11 wells
• Validates full-field development &
demonstrates vast resource potential
6
Rollefstad: Promising Preliminary Results
• Outstanding initial results:
• New well average IP rates:
•
•
MB and TF1:
TF2 and TF3:
2,960 Boe per day
2,650 Boe per day
• Existing well average IP rates:
•
MB and TF1:
1,330 Boe per day
• Combined IP for 11 wells:
•
Unit total:
26,460 Boe per day*
• 7 wells completed with ~200,000 pounds
of proppant for each of the 30 stages
•
Avg. IPs of 2,675 Boe per day
• 1 well completed with ~300,000 pounds
of proppant for each of the 30 stages
•
IP of 3,720 Boe per day in MB
*Due to the larger enhanced completion techniques used and the temporary limitation of the existing
infrastructure at the unit, a larger test vessel was used to help measure these significant initial rates.
7
Tangsrud: Pushing the Limits
•
Designed to extend LTF productive footprint and
test 1,320 foot density
•
Average initial rates:
•
New wells:
•
•
MB and TF1: 670 Boe per day
TF2 and TF3: 285 Boe per day
•
All new wells producing on pump and completed
with standard CLR design of ~100,000 pounds of
proppant per stage (~30 total)
•
Wells are being monitored closely to assess if
economics using current completion designs will
justify including TF2 and TF3 in future
development in this particular area
8
Return Driven Completion Testing
Cumulative Production vs Producing Days
(Boe)
140,000
Madison 2-28H
120,000
603 MBoe Type Curve
603
100,000
155N-98W
Average of & 155NNeighboring
Wells
97W
MB AVG
Madison 2-28H: 180 Days
• 37% higher than 603 MBoe
• 59% higher than average of
neighboring wells
Sacramento 2-10H
Madison 2-28H
80,000
120 Miles
Cumulative Production
Sacramento 2-10H
60,000
De-Risked
40,000
Sacramento 2-10H: 120 Days
• 26% higher than 603 MBoe
• 47% higher than average of
neighboring wells
20,000
Expansion Mode
0
0
•
60
180
240
Producing Days
300
360
Continental Acreage
25
Miles
Madison 2-28H and Sacramento 2-10H;
MB Slickwater
Encouraging preliminary results from enhanced completion designs
•
In 1Q14, ~60% of operated wells (43 total) utilized new designs including:
•
•
120
Slickwater, hybrid stimulations and increased proppant (up to double and triple the standard CLR
design of 100,000 pounds per stage)
Incremental cost of enhanced completion designs estimated at $1.5MM to $2MM
9
SCOOP: Continued Exploration and Appraisal
•
1Q14 net production: 29,400 Boe per day
•
•
SCOOP Oil , Condensate and Gas Window Map
Gas
Up 24% sequentially, up 106% over 1Q13
Condensate
Plan to operate ~18 average rigs in 2014
•
~50% of activity to drill extended lateral wells
• 1Q14 Oil Window IP Rates
•
•
Oil
Green Acres
Green Acres 1-36H: 980 Boe per day, 78% oil, 97% WI
1Q14 Condensate Gas Window IP Rates
•
•
Claudine 1-29-32XH: 18.1 MMcfe per day, 245 barrels
of oil per day, gas stream of ~1,230 Btu/scf
Chalfant 1-7H: 16.2 MMcfe per day, 375 barrels of oil
per day, gas stream of ~1,190 Btu/scf
•
~425,000 net acres leased
•
Improving well costs
•
Chalfant
Claudine
1Q14 Actual: $9.0 million for standard 1-mile lateral
•
•
YE14 target of $8.7 million for standard 1-mile lateral
YE14 target of $13.5 million for extended 2-mile lateral
Delineation Tests
1Q14 Completions
Woodford Completions
35 Miles
10
Strong Liquidity and Financial Profile
Financial Ratios and Ratings
YE13
FY13
Agency
Credit Ratings
Net Debt/TTM EBITDAX
1.65x
Cash Margin
$53.52**
Moody’s
Baa3
Net Debt/Proved Reserves
$4.32
All-in F&D ($/Boe)
$11.01
S&P
BBB-
$11.52
3 Year All-in F&D ($/Boe)
$12.60
$32,494
Leveraged Recycle Ratio
Net Debt/ PD Reserves
Net Debt/4Q Daily Production
4.25x
Debt Maturities Summary
$2,500
5%
($MM)
$2,000
$1,500
$1,500
$1,000
Undrawn commitments
4.5%
$870
$2,000
$1,500
$500
Revolver Balance*
8.25%
$630
$300
$0
2013
2014
2015
2016
2017
2018
Credit
Facility
*As of 3/31/2014
** See “Cost Discipline Driving Excellent Margins” in the Appendix for the method of calculating cash margin.
7.125%
7.375%
$200
$400
2019
2020
2021
2022
Callable
10/1/2014
Callable
10/1/2015
Callable
4/1/2016
Callable
3/15/2017
2023
11
Appendix
2014 Operational and Financial Guidance
As of May 7, 2014*
2014
Production growth (YOY)
Capital expenditures (non-acquisition)
26% to 32%
$4.05B
Operating Expenses:
Production expense per Boe
Production tax (% of oil & gas revenue)
DD&A per Boe
G&A expense per Boe
Non-cash equity compensation per Boe
$5.60 to $6.10
8% to 9%
$17.50 to $19.50
$2.00 to $2.50
$0.70 to $0.90
Average Price Differentials:
NYMEX WTI crude oil (per barrel of oil)
Henry Hub natural gas (per Mcf)
($8.00) to ($11.00)
+$1.00 to $1.50
Income tax rate
Deferred taxes
37%
90% to 95%
* No change from previously announced 2014 Guidance Outlook on September 10, 2013
13
Cost Discipline Driving Excellent Margins
Realized oil price ($/Bbl)
Realized natural gas price ($/Mcf)
Oil production (Bopd)
Natural gas production (Mcfpd)
Total production (Boepd)
2009
$54.44
$2.95
27,459
59,194
37,324
2010
$70.69
$4.26
32,385
65,598
43,318
2011
$88.51
$4.87
45,121
100,469
61,865
2012
$84.59
$3.73
68,497
174,521
97,583
2013
$89.93
$4.87
95,859
240,355
135,919
1Q2014
$89.73
$7.06
106,398
276,439
152,471
EBITDAX ($000's) (1)
$450,648
$810,877
$1,303,959
$1,963,123
$2,839,510
$775,407
Average oil equivalent price (excludes
derivatives)
$44.68
$59.35
$72.45
$65.99
$72.04
$75.03
Production expense
Production tax and other
G&A (3)
Interest
Total cash costs
$6.89
$2.95
$2.19
$1.72
$13.75
$5.87
$4.47
$2.35
$3.34
$16.03
$6.13
$5.82
$2.36
$3.40
$17.71
$5.49
$5.58
$2.38
$3.95
$17.40
$5.69
$6.02
$2.07
$4.74
$18.52
$5.76
$5.86
$2.43
$4.71
$18.76
Cash margin
Cash margin %
$30.93
69%
$43.32
73%
$54.74
76%
$48.59
74%
$53.52
74%
$56.27
75%
Key Operational Statistics (per Boe) (2)
1)
2)
3)
See “EBITDAX Reconciliation to GAAP” in Appendix for a reconciliation of GAAP net income and operating cash flows to EBITDAX.
Average costs per Boe have been computed using sales volumes and exclude any effect of derivative transactions.
Excludes G&A related to Equity based compensation and relocation expense.
14
EBITDAX Reconciliation to GAAP
We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. EBITDAX
represents earnings (net income) 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, and non-cash equity compensation expense. EBITDAX is not a measure of net income or operating cash flows 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. We exclude the items listed above from net income 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 or operating cash flows 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. 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. Our
revolving credit facility requires that we maintain a total funded debt to EBITDAX ratio of no greater than 4.0 to 1.0 on a rolling
four-quarter basis. This ratio represents the sum of outstanding borrowings and letters of credit under our revolving credit facility
plus our note payable and senior note obligations, divided by total EBITDAX for the most recent four quarters.
See the following page for reconciliations of our net income and operating cash flows to EBITDAX for the applicable periods.
15
EBITDAX Reconciliation to GAAP (cont’d)
The following tables provide reconciliations of our net income and operating cash flows to EBITDAX for the periods presented:
In thousands
Net income
2009
$
2010
71,338
$
168,255
2011
$
2012
429,072
$
739,385
2013
$
1Q2014
764,219
$ 226,234
Interest expense
23,232
53,147
76,722
140,708
235,275
62,975
Provision for income taxes
38,670
90,212
258,373
415,811
448,830
132,867
207,602
243,601
390,899
692,118
965,645
272,861
Property impairments
83,694
64,951
108,458
122,274
220,508
58,208
Exploration expenses
12,615
12,763
27,920
23,507
34,947
4,813
1,520
130,762
30,049
(154,016)
191,751
39,674
569
35,495
(34,106)
(45,721)
(61,555)
(33,264)
2,089
166,257
(4,057)
(199,737)
130,196
6,410
11,408
11,691
16,572
29,057
39,890
11,039
810,877
$ 1,303,959
$ 1,963,123
$ 2,839,510
Depreciation, depletion, amortization and accretion
Impact from derivative instruments:
Total (gain) loss on derivatives, net
Total cash received (paid), net
Non-cash (gain) loss on derivatives, net
Non-cash equity compensation
EBITDAX
$
In thousands
Net cash provided by operating activities
450,648
$
2009
$
Current income tax provision
Interest expense
Exploration expenses, excluding dry hole costs
Gain (loss) on sale of assets, net
2010
2011
2012
372,986
$ 653,167
$ 1,067,915
$ 1,632,065
2013
$
775,407
1Q2014
$ 2,563,295
$ 690,662
2,551
12,853
13,170
10,517
6,209
1,552
23,232
53,147
76,722
140,708
235,275
62,975
6,138
9,739
19,971
22,740
25,597
4,813
709
29,588
20,838
136,047
88
(8,498)
2,872
5,230
--
15,618
--
--
Other, net
(3,890)
(3,513)
(4,606)
(7,587)
(1,829)
(10,008)
Changes in assets and liabilities
46,050
50,666
109,949
13,015
10,875
33,911
810,877
$ 1,303,959
$ 1,963,123
$ 2,839,510
$ 775,407
Excess tax benefit from stock-based compensation
EBITDAX
$
450,648
$
16
Adjusted Earnings Reconciliation to GAAP
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 corporate relocation expenses. Management believes
these measures provide useful information to analysts and investors for analysis of our operating results on a recurring, comparable basis from period to
period. 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
nonrecurring transactions. 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 table reconciles 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.
In thousands, except per share data
Net income (GAAP)
Adjustments, net of tax:
Non-cash loss on derivatives, net
Property impairments
(Gain) loss on sale of assets, net
Corporate relocation expenses
Adjusted net income (Non-GAAP)
Weighted average diluted shares outstanding
Adjusted diluted net income per share (Non-GAAP)
1Q 2014
After-Tax $
Diluted EPS
$ 226,234
$
1.22
4Q 2013
After-Tax $
Diluted EPS
$ 132,824
$
0.72
1Q 2013
After-Tax $ Diluted EPS
$ 140,627
$
0.76
4,038
36,671
5,354
$ 272,297
185,028
$
1.47
58,312
36,885
15
96
$ 228,132
185,007
$
1.23
49,153
25,251
(86)
441
$ 215,386
184,656
$
1.17
$
0.02
0.20
0.03
1.47
$
0.31
0.20
1.23
$
0.27
0.14
1.17
17