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Form 8-K

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 8-K

 

 

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

Date of report (Date of earliest event reported): February 5, 2013

 

 

DIAMONDBACK ENERGY, INC.

(Exact Name of Registrant as Specified in Charter)

 

 

 

Delaware   001-35700   45-4502447

(State or other jurisdiction

of incorporation)

  

(Commission

File Number)

  

(I.R.S. Employer

Identification Number)

500 West Texas Suite 1225

Midland, Texas

   79701
(Address of principal executive offices)   (Zip code)

(432) 221-7400

(Registrant’s telephone number, including area code)

Not Applicable

(Former name or former address, if changed since last report)

 

 

Check the appropriate box below if the Form 8-K is intended to simultaneously satisfy the filing obligation of the Registrant under any of the following provisions:

 

¨ Written communications pursuant to Rule 425 under the Securities Act

 

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act

 

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act

 

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act

 

 

 

Item 7.01. Regulation FD Disclosure

Attached as Exhibit 99.1 is a presentation to be given by senior officers of Diamondback Energy, Inc. on February 6, 2012 at the Credit Suisse Energy Summit.

 

Item 9.01. Financial Statements and Exhibits

(d) Exhibits.

 

Number

   

Exhibit

99.1    Investor Presentation Materials.

Note: The information contained in this report (including Exhibit 99.1) shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such a filing.

 

2

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

    DIAMONDBACK ENERGY, INC.
Date: February 5, 2013     By:   /s/ Teresa L. Dick
      Teresa L. Dick
      Senior Vice President and Chief Financial Officer

 

3

Exhibit Index

 

Number

   

Exhibit

99.1    Investor Presentation Materials.

 

4

Investor Presentation Materials
Energy Summit
Energy Summit
February 2013
February 2013
Exhibit 99.1

2
This presentation contains 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, other than statements of historical fact, included in this presentation that address activities, events or developments
that Diamondback Energy, Inc. (the “Company”) expects, believes or anticipates will or may occur in the future are forward-looking statements. The words
“believe,”
“expect,”
“may,”
“estimates,”
“will,”
“anticipate,”
“plan,”
“intend,”
“foresee,”
“should,”
“would,”
“could,”
or other similar expressions are intended
to identify forward-looking statements, which are generally not historical in nature. However, the absence of these words does not mean that the statements
are not forward-looking. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include the
expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including as to the Company’s drilling program,
production, hedging activities, capital expenditure levels and other guidance included in this presentation. These statements are based on certain
assumptions made by the Company based on management’s expectations and perception of historical trends, current conditions, anticipated future
developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which
are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking
statements.
These
include
the
factors
discussed
or
referenced
in
the
Company’s
filings
with
the
Securities
and
Exchange
Commission
(“SEC”),
including
its
Forms
10-Q
and
8-K
and
its
Registration
Statement
on
Form
S-1,
as
amended,
and
related
prospectus
dated
October
11,
2012,
risks
relating
to
financial
performance and results, current economic conditions and resulting capital restraints, prices and demand for oil and natural gas, availability of drilling
equipment and personnel, availability of sufficient capital to execute the Company’s business plan, impact of compliance with legislation and regulations,
successful results from the Company’s identified drilling locations, the Company’s ability to replace reserves and efficiently develop and exploit its current
reserves and other important factors that could cause actual results to differ materially from those projected.
Any
forward-looking
statement
speaks
only
as
of
the
date
on
which
such
statement
is
made
and
the
Company
undertakes
no
obligation
to
correct
or
update
any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.
The
SEC
generally
permits
oil
and
gas
companies,
in
filings
made
with
the
SEC,
to
disclose
proved
reserves,
which
are
reserve
estimates
that
geological
and
engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating
conditions
and
certain
probable
and
possible
reserves
that
meet
the
SEC’s
definitions
for
such
terms.
In
this
communication,
the
Company
may
use
the
term
“unproved reserves”
which the SEC guidelines restrict from being included in filings with the SEC without strict compliance with SEC definitions. “Unproved
reserves”
refers to the Company’s internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered
with
additional
drilling
or
recovery
techniques.
Unproved
reserves
may
not
constitute
reserves
within
the
meaning
of
the
Society
of
Petroleum
Engineer’s
Petroleum Resource Management System or SEC rules and do not include any proved reserves. Actual quantities that may be ultimately recovered from the
Company’s
interests
may
differ
substantially.
Factors
affecting
ultimate
recovery
include
the
scope
of
the
Company’s
ongoing
drilling
program,
which
will
be
directly affected by the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations,
transportation constraints, regulatory approvals and other factors; and actual drilling results, including geological and mechanical factors affecting recovery
rates. Estimates of unproved reserves may change significantly as development of the Company’s core assets provide additional data. In addition, the
Company’s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates
from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost
increases.
Forward Looking Statements

3
3
Source:
Bloomberg,
Ryder
Scott,
Company   Filings,
Management
Data
and
Estimates.
Financial
data
and
management
estimates
as
of
December
31,
2012.
Market
data 
as
of
January
31,
2013.
Reserve 
data
as
of
December
31,
2011.
Independent E&P focused on Permian Basin
headquartered in Midland, Texas
Completed IPO on October 17, 2012 at $17.50 / share
$235 mm of growth capital raised to drive production
Deep vertical well inventory with strong returns
5 Wolfcamp B horizontal well results in next 60 days
Diamondback Overview
NASDAQ Ticker: FANG
Key Highlights
Market Cap: $829 mm @ $22.42 / share
$135 mm undrawn borrowing base at 12/31/12
51,709 net acres; 99% operated
Proved Reserves: 26 MMbbl, 39.5 MMBOE
66% Oil, 20% NGL, 14% gas
24% Proved developed producing
YE11 SEC Pre-tax PV-10: $567 mm

4
4
Pure Play Exposure to
the Permian Basin
Exposure to one of the most concentrated high quality acreage positions in the
Permian Basin
51,709 net acres primarily in Wolfberry trend of Midland Basin
Deep Vertical
Drilling Inventory
849
net
locations
with
40
acre
spacing;
1,027
net
locations
with
20
acre
spacing
Increasing
IPs
and
EURs
continue
to
improve
vertical
well
economics
2013
production
targeted
to
grow
94%
to
7,200
–
7,500
BOEPD
from
3,786
BOEPD in 2012
Strong Horizontal
Upside
5
Horizontal
Wolfcamp
B
well
results
expected
over
the
next
60
days
-
2
Hz
WCB
wells completed in 2012 with impressive results
67% of 2013 capital expenditures focused on horizontal development
Expect Margins
to Head Higher
Access to LLS Pricing in Q2 2013 via Magellan Longhorn pipeline
Plan
to
decrease
LOE
by
$2.00
-
$4.00
/
BOE
from
infrastructure
improvements
Efficient
capital
spend
through
improved
drilling
and
completion
techniques
Financial Strength &
Strong Management
No debt -
$135 mm undrawn borrowing capacity at year end 2012
2013
capital
plan
of
$270
-
$300
mm
–
New
hedges
put
in
place
Investment Highlights
Source: Company Filings, Management Data and Estimates. 
Financial data and management estimates as of December 31, 2012.

5
5
Deep Vertical
Drilling Inventory
Strong Horizontal
Upside
Expect Margins
to Head Higher
Financial Strength &
Strong Management
849
net
locations
with
40
acre
spacing;
1,027
net
locations
with
20
acre
spacing
Increasing IPs and EURs continue to improve vertical well economics
2013
production
targeted
to
grow
94%
to
7,200
–
7,500
BOEPD
from
3,786
BOEPD in 2012
Access to LLS Pricing in Q2 2013 via Magellan Longhorn pipeline
Plan
to
decrease
LOE
by
$2.00
-
$4.00
/
BOE
from
infrastructure
improvements
Efficient
capital
spend
through
improved
drilling
and
completion
techniques
No
debt
-
$135
mm
undrawn
borrowing
capacity
at
year
end
2012
2013
capital
plan
of
$270
-
$300
mm
–
New
hedges
put
in
place
5
Horizontal
Wolfcamp
B
well
results
expected
over
the
next
60
days
-
2
Hz
WCB
wells completed in 2012 with impressive results
67% of 2013 capital expenditures focused on horizontal development
Investment Highlights
Source: Company Filings, Management Data and Estimates. 
Financial data and management estimates as of December 31, 2012.
Pure Play Exposure to the Permian Basin

6
6
Resurgent Texas Oil Production
100% Leverage to the Permian
Source: US Energy Information Administration, Company Filings, Management Data and Estimates. 
Financial data and management estimates as of December 31, 2012.
1,000
1,400
1,800
2,200
2,600
3,000
1981
1986
1991
1996
2001
2006
2011
Over 800,000 Barrel
per day growth
since 2009
(Thousand Barrels per Day)
Diamondback Acreage Position
100% of acreage located in the Midland Basin
51,709 net acres, operate ~99% of acreage
217 gross producing wells, 4 rigs running (2 Vert, 2 Hz)
Q4 2012 production average ~4,300 BOEPD
Actively pursuing additional acreage in the Basin
Over 1,000 40 acre vertical gross locations supporting
reserve growth
Concentrated Permian Position –
Solid Inventory

7
WTI Breakeven Price for a 15% Rate of Return
Permian Basin Economics Remain Some of the Strongest in the US
High liquids content, large areal extent of resource combined with improving technology likely to
support substantial growth potential of the basin
Near
term
erosion
to
economics
from
weakened
price
differentials
addressed
Costs going down steadily as drilling times decline and horizontal development expands
Diamondback uniquely positioned to capture both higher realizations and lower costs
Source:  Management data and estimates. ISI Group LLC. 
Management data as of December 31, 2012.  ISI data as of June 15, 2012.

8
8
Source: Company Filings, Management Data and Estimates., ISI Group LLC.   Financial  data and Management estimates as of December 31, 2012.
(1)  CAGR does not include forward estimates.
Strong Production Growth Outlook Built on Existing Inventory
Proved Developed Reserve Growth (MMBOE)
Average Daily Net Production (BOEPD)
Drilling program shifting from vertical to horizontal development
Ended 2012 with 6 rigs (4 vertical, 2 horizontal)
Currently operating 4 rigs (2 horizontal, 2 vertical)
Additional rig planned in 2H 2013 to focus on horizontal development
2013
production
target
estimated
at
7,200
–
7,500
BOEPD
based
on
capex
of
$270
-
$300
mm

9
PDP, 22%
PUD, 76%
PDNP, 2%
Oil, 66%
NGL, 20%
Natural
Gas, 14%
PDP, 42%
PUD, 53%
PDNP, 5%
9
1P –
PV-10%
1P –
By Commodity
1P –
By Category
Substantial Reserve Upside from Horizontal Potential
Current reserves based only on ~30% of 40-acre vertical development
Ryder
Scott
estimated
PUD
EURs
average
135
MBOE
per
vertical
well
-
86%
liquids
(66%
crude
oil)
Reserve assumptions currently exclude value uplift expected from:
Horizontal wells
20-acre downspacing
Higher realizations from shift to LLS pricing
Pro Forma Pre-tax
Net Oil (Mbbls)
Net NGL (Mbbls)
Net Gas (MMcf)
Total (MMcf)
Proved PV-10% ($MM)
PDP
5,456
1,826
7,728
8,570
$237
PDNP
589
143
608
833
27
PUD
20,140
5,871
24,262
30,055
303
Total Net Proved Reserves
26,185
7,840
32,598
39,458
$567
Source: Ryder Scott.
Data as of December 31, 2011.

No
debt
-
$135
mm
undrawn
borrowing
capacity
at
year
end
2012
2013
capital
plan
of
$270
-
$300
mm
–
New
hedges
put
in
place
10
Exposure to one of the most concentrated high quality acreage positions in the
Permian Basin
51,709 net acres primarily in Wolfberry trend of Midland Basin
Investment Highlights
Expect Margins
to Head Higher
Financial Strength &
Strong Management
Deep Vertical
Drilling Inventory
Pure Play Exposure to
the Permian
Basin
Access to LLS Pricing in Q2 2013 via Magellan Longhorn pipeline
Plan
to
decrease
LOE
by
$2.00
-
$4.00
/
BOE
from
infrastructure
improvements
Efficient
capital
spend
through
improved
drilling
and
completion
techniques
849
net
locations
with
40
acre
spacing;
1,027
net
locations
with
20
acre
spacing
Increasing IPs and EURs continue to improve vertical well economics
2013
production
targeted
to
grow
94%
to
7,200
–
7,500
BOEPD
from
3,786
BOEPD in 2012
Source: Company Filings, Management Data and Estimates. 
Financial data and management estimates as of December 31, 2012.
Strong Horizontal Upside

11
11
Horizontal Wolfcamp B Drilling Shifting North
Source: Company Filings, Global Hunter Securities, Smith STATS, Pioneer Natural Resources.
Financial
data
and
management
estimates
as
of
December31,
2012.
Rig
count
data
as
of
January25,
2013.
Permian Basin Rig Count
Horizontal drilling becoming a primary rather than secondary
use of capital in Wolfberry trend
Results are trending upward (longer laterals, frac designs)
Original majority of horizontal activity focused on southern
Midland Basin
Pioneer southern Midland Basin JV with Sinochem for
$21,000 / acre
Northern Midland Basin Wolfcamp B Horizontal Results:
Horizontal rig count has more than doubled since Q1 2011
Lateral
Length
Number of
Stages
Peak IP
(BOE/d)
Cumulative
Production
Production
Time
Kemmer
3,733’
15
892
56,000 BOE
4 months
PXD Giddings
2041H
5,800’
30
897
135,000 BOE
12 months
PXD Giddings
2073H
5,800’
30
792
105,000 BOE
10 months

12
12
Horizontal Focus: Midland County
Kemmer has produced 56 MBOE since initial production in
September 2012
ST 25-1H first operated Midland County horizontal Wolfcamp B
Horizontal Focus: Upton County
Janey has produced 58 MBOE since initial production in June 2012
Neal 8-1H completed mid January; flowback operations underway
Horizontal Drilling Program –
Development Progress
Producing
Frac Completed
Drilled
Upton County
Producing
Drilled
To Be Drilled
Non-operated Acreage
Non-operated Acreage
Midland County
Source: Company Filings, Management Data and Estimates. 
Financial data and management estimates as of December 31, 2012.
Lateral
Length
IP / Stage
(BOE)
Number
of Stages
30-day IP
(BOE/d)
Per Stage
EUR
(MBOE)
Peak IP
(BOE/d)
Kemmer
3,733’
29
15
428
30
892
ST 25-1H
4,617’
Drilled; 16 stage frac scheduled early March
ST 25-2H
4,800’
Drilling; 20 stage frac scheduled early March
Sarah Ann
4,000’
Non operated; Drilled; 15 stage frac scheduled Feb 11th
Lateral
Length
IP / Stage
(BOE)
Number
of Stages
30-day IP
(BOE/d)
Per Stage
EUR
(MBOE)
Peak IP
(BOE/d)
Janey 16-1H
3,842’
30
16
486
30
618
Neal 8-1H
7,652’
Drilled; 32 stage frac completed late January
Neal 8-2H
6,685’
Drilled; 28 stage frac scheduled late February
Janey 16-3H
4,629’
Drilled (TD’d in 13 days); 18 stage frac scheduled in late March

13
13
Investment Highlights
No
debt
-
$135
mm
undrawn
borrowing
capacity
at
year
end
2012
2013
capital
plan
of
$270
-
$300
mm
–
New
hedges
put
in
place
5
Horizontal
Wolfcamp
B
well
results
expected
over
the
next
60
days
-
2
Hz
WCB
wells completed in 2012 with impressive results
67% of 2013 capital expenditures focused on horizontal development
Exposure to one of the most concentrated high quality acreage positions in the
Permian Basin
51,709 net acres primarily in Wolfberry trend of Midland Basin
Strong Horizontal
Upside
Expect Margins
to Head Higher
Financial Strength &
Strong Management
Pure Play Exposure to
the Permian
Basin
Access to LLS Pricing in Q2 2013 via Magellan Longhorn pipeline
Plan
to
decrease
LOE
by
$2.00
-
$4.00
/
BOE
from
infrastructure
improvements
Efficient
capital
spend
through
improved
drilling
and
completion
techniques
Source: Company Filings, Management Data and Estimates. 
Financial data and management estimates as of December 31, 2012.
Deep Vertical Drilling Inventory

14
$567
mm
of
year-end
2011
SEC
Pre-tax
PV-10
value
303 locations currently booked as PUDs out of 916
locations on 40-acre spacing
No
value
for
20-acre
spaced
wells
or
horizontal
locations
included
in
PV-10
value
Vertical Inventory (Years):
Increasing Initial Production Rates
Continue to refine drilling pattern and completion techniques
to increase EURs on 40-acre spaced wells
Selective development depths
Selective completion zones
Optimized stimulation design
Expected increase in reserves
Multi-Year Drilling Inventory
Well
Cost:
$2.0
-
$2.2
mm
EURs: 135,000 BOE
Vertical Well Economics
2 Rigs
4 Rigs
6 Rigs
40-Acre Spacing
22.9
11.5
7.6
20-Acre Spacing
28.1
14.0
9.4
Total
51.0
25.5
17.0
Source: Company Filings, Management Data and Estimates, Ryder Scott.   Financial data and management estimates as of December 31, 2012.
(1) Realized oil price equal to WTI less $3.50 / bbl. NGLs assumed 40% of WTI.  Natural gas assumed $3.50 / mcf.  Based on working interest of 100% with 75% NRI.
Low Risk Vertical Inventory
WTI
NPV - 10
($ / Bbl)
($ in millions)
(1)
IRR
(1)
$100
$1.3
33%
90
0.9
25
80
0.5
19

15
High Inventory Made Up of Strong ROR Projects
Identified Net Potential Drilling Locations
Potential Optimized Spacing
Reserve Potential Per Section
Source: Company Filings, Management Data and Estimates. 
Management estimates as of December 31, 2012.
Vertical
(40s)
Horizontal
Vertical
(20s)
Total
Wells / Section
16
9
16
41
EUR / Well
135 MBOE
400 MBOE
108 MBOE
--
Reserves /
Section
2.2
MMBOE
3.6
MMBOE
1.7
MMBOE
7.7 MMBOE
OOIP
150 -
250 MMBOE
% of OOIP
0.9 -
1.4%
1.4 -
2.4%
0.7 -
1.2%
3.0 -
5.0%

16
Investment Highlights
No
debt
-
$135
mm
undrawn
borrowing
capacity
at
year
end
2012
2013
capital
plan
of
$270
-
$300
mm
–
New
hedges
put
in
place
5
Horizontal
Wolfcamp
B
well
results
expected
over
the
next
60
days
-
2
Hz
WCB
wells completed in 2012 with impressive results
67% of 2013 capital expenditures focused on horizontal development
Exposure to one of the most concentrated high quality acreage positions in the
Permian Basin
51,709 net acres primarily in Wolfberry trend of Midland Basin
Strong Horizontal
Upside
Financial Strength &
Strong Management
Deep Vertical
Drilling Inventory
Pure Play Exposure to
the Permian
Basin
849
net
locations
with
40
acre
spacing;
1,027
net
locations
with
20
acre
spacing
Increasing IPs and EURs continue to improve vertical well economics
2013
production
targeted
to
grow
94%
to
7,200
–
7,500
BOEPD
from
3,786
BOEPD in 2012
Source: Company Filings, Management Data and Estimates. 
Financial data and management estimates as of December 31, 2012.
Expect Margins to Head Higher

17
Quarterly LOE (per BOE)
Spud to TD Time
(1)
Time Until Placed on Production
(1)
Well Failure Rate
Source: US Energy Information Administration, Company Filings, Management Data and Estimates. 
Financial
data
and
management
estimates
as
of
December31,
2012.
(1)
Vertical
Wells
only.
Operational Efficiency to Drive Expense Reduction

18
Source: Management estimates.
Management estimates as of December 31, 2012.
Moving flowback water by pipeline rather than truck
in Midland County (heaviest drilling area)
Reduces
LOE
by
$2.50
-
$3.00
/
BOE
Water Infrastructure
Conversion of WHL 4-2 to disposal well (10 kbpd)
Tying together tank batteries
Tying into MTN Disposal (2 kbpd)
Water Disposal: Midland County
Gathering and Processing
Water Handling
Accessing oil pipelines
Building infrastructure in Midland County to
connect to pipeline north of acreage
Improves
oil
realizations
by
$1.50
-
$2.00
/
barrel
Majority of gas and liquids under long term
gathering contracts
Released rental processing equipment in Ector
County
($0.50
-
$1.00
/
BOE)
Looping tank batteries in Midland County will allow
Diamondback to use recycled flowback water for
15%
-
25%
of
each
frac
Using recycled water reduces LOE for disposal by
$0.25
-
$0.50
/
BOE
Electrification
Majority of leasehold now electrified eliminating
rental
generators
($0.10
-$0.20
/
BOE)
Plan to Reduce Lifting Costs by $2.00-$4.00 / BOE in 2013

19
19
Source: Company Filings. 
Financial
data
and
management
estimates
as
of
December31,
2012.
Market
dataas
of
January
31,2013.
WTI LLS pricing less $7 / barrel through Magellan
Longhorn  pipeline
Line begins to fill as early as April 2013
$11.19 / barrel price improvement relative to
current levels
~$15 -
$20 mm annual cash flow enhancement
based on projected production expected to
commence 2H 2013
Oil: Magellan Pipeline
NGL
Natural Gas
Takeaway capacity on Lone Star and West Texas
pipelines
10 year contract
Mont Belvieu pricing
Heavy NGLs (only 32% ethane)
Takeaway capacity on ONEOK
10 year contract
Inside FERC First of Month Index
Above market percentage of production contract
(87% versus 82% for peers)
Takeaway Contracts Improve Realizations

20
20
Source: Company Filings, Management Data and Estimates.  Financial data and management estimates as of December 31, 2012.
(1)
CalculatedWTI-LLS
spread
less
$7.00
of
$11.00
multiplied
by
oil
production
(66%)
andpercent
of
oil
receiving
LLS
pricing
(65%
-
75%).
Diamondback has a path to an over $10.00 / BOE improvement in cash margins in 2013.
($ per BOE)
Improved Realizations and Lower Costs Increase Value

21
21
5
Horizontal
Wolfcamp
B
well
results
expected
over
the
next
60
days
-
2
Hz
WCB
wells completed in 2012 with impressive results
67% of 2013 capital expenditures focused on horizontal development
Exposure to one of the most concentrated high quality acreage positions in the
Permian Basin
51,709 net acres primarily in Wolfberry trend of Midland Basin
Strong Horizontal
Upside
Expect Margins
to Head Higher
Deep Vertical
Drilling Inventory
Investment Highlights
Pure Play Exposure to
the Permian
Basin
Access to LLS Pricing in Q2 2013 via Magellan Longhorn pipeline
Plan
to
decrease
LOE
by
$2.00
-
$4.00
/
BOE
from
infrastructure
improvements
Efficient
capital
spend
through
improved
drilling
and
completion
techniques
849
net
locations
with
40
acre
spacing;
1,027
net
locations
with
20
acre
spacing
Increasing IPs and EURs continue to improve vertical well economics
2013
production
targeted
to
grow
94%
to
7,200
–
7,500
BOEPD
from
3,786
BOEPD in 2012
Source: Company Filings, Management Data and Estimates. 
Financial data and management estimates as of December 31, 2012.
Financial Strength / Strong Management

22
22
$270 –
$300 mm capital expenditures:
Horizontal Drilling: 67%
Two horizontal rigs operating
Third horizontal rig to be added 2H 2013
25 gross wells to be drilled
Focus on Midland and Upton Counties
Vertical Drilling: 23%
Two vertical rigs operating
37 gross vertical wells to be drilled
Focus on Midland County
Maintaining leasehold
Acquiring data for horizontal development
Infrastructure: 6%
Focus on LOE reduction
Non-operated Drilling: 4%
Funding
2013 Capital Expenditures
Source: Company Filings, Management Data and Estimates. 
Financial data as of December 31, 2012.  Market data as of January 31, 2013.
Fully financed based on current liquidity, cash flow and
expected growth in borrowing base
Long-term leverage target of less than or equal to 2.0x
run rate EBITDA
$135 mm undrawn borrowing base at 12/31/12
2013 Capital Plan
Liquidity and Financial Flexibility –
2013 Capital Program

23
23
EBITDA Growth
Revenue Growth
($ in mms)
Source: Company Filings, Management Data and Estimates.  Financial data as of December 31, 2012.
(1) CAGR does not include forward estimates.  (2) Prices received excluding the effect of hedges.
Realizations
(2)
($ in mms)
Management’s
goal
is
to
hedge
40%
-
70%
of
production
2013 Hedges
1,000 barrels / day at $109.70 Brent
1,000 barrels / day at $80.55 WTI
Hedging
Consistent Cash Flow Growth

24
24
Source: Company Filings, Management Data and Estimates. 
Management estimates as of December 31, 2012.
Diamondback Guidance
Full Year 2013
Production
7,200 –
7,500 BOEPD
Capital Expenditures
$270 -
$300 mm
Horizontal Well Costs
$7.5 -
$8.5 mm
Vertical Well Costs
$2.0 -
$2.2 mm
Operating Costs (per BOE)
Lease Operating Expense
$11.00 -
$13.00 / BOE
Tax
~6%
G&A
$3.00 -
$5.00 / BOE
DD&A
$22.00 -
$25.00 / BOE

25
25
Team
Prior Experience
Years
Experience
Travis Stice
Chief Executive Officer
Permian Basin Production Manager of Apache Corporation
Vice President of Permian Basin for Laredo Petroleum Holdings
Development Manager of Mid-Continent Business Unit for   
ConocoPhillips/Burlington Resources
General Manager of Engineering, Operations and Business Reporting of Mid-
Continent Division for Burlington Resources
28
Tracy Dick
Chief Financial Officer
Controller / Tax Director at Hiland Partners
Over
19
years
of
accounting
experience,
including
over
8
years
of
public
company experience in both audit and tax areas
20
Russell Pantermuehl
Vice President of Reservoir
Engineering
Wolfberry Reservoir Engineering Supervisor for Concho Resources Inc.
Reservoir Engineering Advisor for ConocoPhillips
Reservoir Engineering Advisor for Burlington Resources
32
Paul Molnar
Vice President of Geoscience
Senior District Geologist for Samson Investment Company
Asset Supervisor and Geosciences Supervisor for ConocoPhillips
Geologic Advisor for Burlington Resources
33
Michael Hollis
Vice President of Drilling
Drilling Manager at Chesapeake Energy Corporation
Senior Drilling Engineer for ConocoPhillips
Drilling and Production Engineer for Burlington Resources
15
William Franklin
Vice President of Land
Various land management roles with ConocoPhillips
37
Jeff White
Vice President of Operations
Completion Manager for Laredo Petroleum Holdings
Staff Engineer for ConocoPhillips
Various engineering and management positions with Anadarko Petroleum
31
Randy Holder
Vice President, Chief Counsel
General Counsel and Vice President for Great White Energy Services LLC
Mid-Continent Division Attorney for Tenneco Oil Company
32
Source: Company Filings.  Data as of December 31, 2012.
Management Team –
Over 225 Years Combined Experience

26
26
Pure
Play
Exposure
to
the
Permian
Basin
Deep Vertical Drilling Inventory
Strong Horizontal Upside
Expect Margins to Head Higher
Financial Strength / Strong
Management
In Conclusion…

27
27
Diamondback Energy, Inc
500 West Texas
Suite 1225
Midland, Texas 79701
(432) 221-7400
14301 Caliber Drive
Suite 300
Oklahoma City, Oklahoma 73134
(405) 463-6900
Auditor
Grant Thornton LLP
Oklahoma City, Oklahoma
Independent Petroleum Engineer
Ryder Scott Company, L.P.
Houston, Texas
Legal Counsel
Akin Gump Strauss Hauer & Feld LLP
Dallas, Texas
Investor Relations
KCSA Strategic Communications
Jeffrey Goldberger / Philip Carlson
(212) 896-1249 / (212) 896-1233
jgoldberger@kcsa.com / pcarlson@kcsa.com
Source: Company Filings.  Data as of December 31, 2012.
Corporate Contact Information

28
Appendix

29
29
Source: Company Filings. Financial data as of September 30, 2012.
EBITDA Reconciliation
($ in ‘000s)
Year ended December 31,
Quarter Ended
Nine Months Ended
2009
2010
2011
9/30/2012
9/30/2012
Reconciliation of Adjusted EBITDA to Net Income (Loss):
Net Income (Loss)
($2,706)
$8,216
($545)
$1,242
$16,182
Loss on Derivative Contracts
4,068
148
13,009
688
(4,477)
Interest Expense
11
836
2,528
3,148
5,202
Depreciation, Depletion and Amortization
3,216
8,145
15,905
1,130
11,366
Impairment on Oil and Gas Properties
0
0
0
8,853
8,853
Equity-Based Compensation Expense
0
0
544
291
873
Asset Retirement Obligation Accretion Expense
28
38
63
22
62
Adjusted EBITDA
$4,617
$17,383
$31,504
$15,374
$38,061