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3. natural gas

INVESTOR
PRESENTATION
JANUARY 2015
FORWARD-LOOKING STATEMENTS & NON-GAAP FINANCIAL MEASURES
This presentation includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. Forward-looking statements can be identified by words such as “anticipates”, “believes”, “forecasts”,
“plans”, “estimates”, “expects”, “should”, “will”, or other similar expressions. Such statements are based on management’s current expectations, estimates
and projections, which are subject to a wide range of uncertainties and business risks. These forward-looking statements include statements regarding:
proposed sale of Midcontinent assets; forecasted production and compounded annual growth rate; forecasted 2014 capital expenditures and related
assumptions; allocation of 2014 capital expenditures; well costs and average estimated ultimate recoveries; estimated reserves; and locations for wells.
Actual results may differ materially from those included in the forward-looking statements due to a number of factors, including, but not limited to: the
availability and cost of capital; changes in local, regional, national and global demand for natural gas, oil and NGL; natural gas, NGL and oil prices; effect of
existing and future laws and government regulations, including regulations on the flaring of natural gas and potential legislative or regulatory changes
regarding the use of hydraulic fracture stimulation; elimination of federal income tax deductions for oil and gas exploration and development; drilling
results; shortages of oilfield equipment, services and personnel; operating risks such as unexpected drilling conditions; weather conditions; changes in
maintenance and construction costs and possible inflationary pressures; permitting delays; estimates of contingency losses and outcome of pending
litigation and other legal proceedings; actions taken by third-party operators, processors and transporters; demand for oil and natural gas storage and
transportation services; competition from the same and alternative sources of energy; natural disasters; large customer defaults; QEP’s success in selling or
spinning off QEP Field Services or its assets and selling additional non-core assets in the Midcontinent area; operating in ethane recovery; and the other
risks discussed in the Company’s periodic filings with the Securities and Exchange Commission, including the Risk Factors section of QEP’s Annual Report on
Form 10-K for the year ended December 31, 2013 (the 2013 Form 10-K”). QEP undertakes no obligation to publicly correct or update the forward-looking
statements in this news release, in other documents, or on its website to reflect future events or circumstances. All such statements are expressly qualified
by this cautionary statement.
The Securities and Exchange Commission (SEC) requires oil and gas companies, in their filings with the SEC, to disclose proved reserves that a company has
demonstrated by actual production or through reliable technology to be economically and legally producible at specific prices and existing economic and
operating conditions. The SEC permits optional disclosure of probable and possible reserves calculated in accordance with SEC guidelines; however, QEP
has made no such disclosures in its filings with the SEC. QEP also uses the term “EUR” or “estimated ultimate recovery,” and SEC guidelines strictly prohibit
QEP from including such estimates in its SEC filings. EUR, as well as estimates of probable reserves, are by their nature more speculative than estimates of
proved reserves and, accordingly, are subject to substantially more risks of actually being realized. Actual quantities that may be ultimately recovered from
QEP’s interests may differ substantially from the estimates contained in this presentation. Investors are urged to consider carefully the disclosures and risk
factors in the 2013 Form 10-K and other reports on file with the SEC.
QEP refers to Adjusted EBITDA, Enterprise Value (EV), EV/EBITDA multiple, Net Debt, PV-10, NYMEX Price 10% Before Tax Rate of Return, Before Tax Rate of
Return, and Finding Costs, each of which is a non-GAAP financial measure that management believes is a good tool to assess QEP’s operating results. For
definitions of these terms and reconciliations of the most directly comparable GAAP measures see the recent earnings press releases and SEC filings at the
Company’s website at www.qepres.com under “Investor Relations.”
1
QEP AT A GLANCE
•
Balanced upstream portfolio
– Proved reserves of 4.1 Tcfe at YE 2013 in multiple US basins
– Product diversity
• In 3Q14, crude oil represented 64% of QEP Energy field-level revenues and
35% of natural gas equivalent production volumes
•
Focused investment in:
– Williston Basin crude oil play
– Permian Basin crude oil play
– Pinedale liquids-rich gas play
– Uinta Basin (Lower Mesaverde) liquids-rich gas play
2
2014 HIGHLIGHTS
• The Permian Basin acquisition closed on February 25, 2014 for total consideration
of approximately $942 million
• Completed sale of QEP Field Services, including QEP’s ownership interest in QEPM
(GP and LP) on December 2, 2014, to Tesoro Logistics LP for $2.5 billion in cash
• Focused upstream portfolio
– High-graded asset portfolio with over $700 million in asset sales (Woodford
Cana, Granite Wash and “Fat Cat” in the Williston Basin)
– Entered into purchase and sale agreements to divest non-core properties in
Southern Oklahoma for $108 million in cash
– Investment focused in core areas
• Strong operating results from core assets
– Third quarter 2014 sequential production growth of 29% and 18% in the
Williston and Permian basins, respectively
3
EXECUTING ON TRANSITION TO OIL
180
5.0
Bcfe 20:1 (left axis)
Natural Gas (left axis)
Gas/Total production (Bcf/Bcfe)
Bcfe 6:1 (left axis)
140
NGL (right axis)
Oil (right axis)
120
4.5
4.0
3.5
3.0
100
2.5
80
2.0
60
1.5
40
1.0
20
0.5
-
1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14
20:1 and 6:1 refer to Mcf:Bbl conversion ratio for oil and NGL
4
Oil/NGL production (MMBbl)
160
EXECUTING ON TRANSITION TO OIL
18
16
Oil production (MMBbl)
14
12
10
8
6
4
2
2010
2011
(1)
2012
2013
2014F represents midpoint of guidance as of November 5, 2014
2014F
5
ASSET OVERVIEW
Oil plays
Liquids-rich plays
QEP Energy 3Q 2014
Production Revenues
Dry-gas play
28%
64%
WY
8%
Uinta
Basin
Oil
NGL
ND
Pinedale
Anticline
UT
Natural Gas
Williston Basin
CO
QEP Resources
2013YE Proved Reserves
OK
22%
63%
15%
Proposed asset sales
Permian
Basin
Midcontinent/
SCOOP
TX
LA
Haynesville
Oil
NGL
Natural Gas
6
AREAS OF OPERATIONS – E&P
WILLISTON BASIN – 109,000 NET ACRES
50,000
45,000
40,000
35,000
30,000
25,000
20,000
15,000
10,000
5,000
0
Approx. Eastern
field boundary
QEP net production
(Boepd)
Fort Berthold
South Antelope
• 109,000 net acres
• Changed to high volume
completion design
• 7 rigs as of 9/30/2014 – all
on pad drilling
– 5 at South Antelope
– 2 at Fort Berthold
• 3Q14 avg. net production
– 49.7 Mboed
20 Miles
Bakken Formation well
Three Forks Formation wells
Operated focus area
QEP leasehold
As of September 30, 2014
8
WILLISTON BASIN – SOUTH ANTELOPE
• Acquisition closed on 9/27/2012 for $1.4 billion
• Pre-tax PV-10 proved reserves of over $2.2 billion as of 12/31/2013
• Total net capital spend (including acquisition costs) less EBITDA of
$1.5 billion through 2013
• Reduced drilling, completion and equipment costs by over
$1.0 million since acquisition
• 5,000 to 12,500-ft laterals
• Proved reserves of 86 MMBoe
QEP Q3 Completions
CURRENT ACTIVITY
QEP Drilling
Number of rigs (as of 9/30/2014)
QEP WOC
Avg. gross EUR
Bakken wells
Three Forks wells
3 Miles
As of September 30, 2014
(1)
QEP leasehold
Bakken (1) (MBoe)
1,070
Three Forks (1) (MBoe)
1,025
Gross locations remaining (1)
(1)
5
250
As of December 31, 2013
9
WILLISTON BASIN – FORT BERTHOLD RESERVATION
• Strong well performance
• Substantial inventory for future development
• 5,000 to 12,500-ft laterals
• Proved reserves of 46 MMBoe
(1)
CURRENT ACTIVITY
Number of rigs (as of 9/30/2014)
2
Avg. gross EUR
6 Miles
Bakken (1) (MBoe)
550
Three Forks (1) (MBoe)
550
Gross locations remaining (1)
400
(1)
As of December 31, 2013
As of September 30, 2014
QEP Drilling
Bakken wells
QEP leasehold
Three Forks wells
10
PERMIAN BASIN – ACREAGE LOCATION
Vertical Rigs
Horizontal Rigs
Deepest part of the Midland Basin
Andrews, TX
Best Midland Basin
horizontal well
24 hr. IP: 3,605 Boed
Midland, TX
10 Miles
Deepest part of the basin = better charge, better pressure, better well performance
11
PERMIAN BASIN
• 5 horizontal and 306 vertical operated producing
wells (1)
• Completed 21 vertical wells in third quarter 2014,
7 WOC (1)
• Completed 5 horizontal wells in Q3 (1 non-op),
2 WOC (1), 2 drilling
• Testing multiple horizontal benches
CURRENT ACTIVITY
QEP Leasehold
Number of vertical rigs (9/30/2014)
5
Existing vertical PDP wells
Number of horizontal rigs (9/30/2014)
2
Q3 2014 vertical completion
Avg. gross vertical EUR
(Atokaberry) (MBoe) (2)
253
Vertical Rigs
Gross vertical locations remaining (3)
200
Horizontal Rigs
Gross horizontal locations remaining( 3)
775
Q3 2014 horizontal completion
As of September 30, 2014
Post-processing volumes
(3) As of December 31, 2013
(1)
(2)
2 Miles
As of September 30, 2014
12
PERMIAN BASIN – OFFSET HORIZONTAL ACTIVITY
2 Miles
Wolfcamp B
24 hr IP = 613 Boed
30-D Avg = 516 Boed
Wolfcamp B
24 hr IP = 1,029 Boed
30-D Avg = 788 Boed
Wolfcamp B
24 hr IP = 927 Boed
30-D Avg = 684 Boed
Wolfcamp D/ Cline
24 hr IP = 3,605 Boed
Lower Spraberry Sh
24 hr IP = 1,279 Boed
30-D Avg = 1,076 Boed
Lower Spraberry Sh
24 hr IP = 691 Boed
Lower Spraberry Sh
24 hr IP = 1,660 Boed
Wolfcamp B
24 hr IP = 756 Boepd
30-D Avg = 517 Boed
Wolfcamp D/ Cline
24 hr IP = 1,509 Boed
30-D Avg = 662 Boed
Wolfcamp B
24 hr IP = 1,606 Boed
30-D Avg = 955 Boed
Wolfcamp B
24 hr IP = 979 Boed
30-D Avg = 815 Boed
QEP Leasehold
Existing vertical PDP wells
Significant horizontal completion
Lower Spraberry Sh
24 hr IP = 795 Boed
Data from Texas Railroad Commission
13
STACKED HORIZONTAL DRILLING TARGETS
• Estimated 300+ MMBO per square mile
of original oil in place
• ~3,000 feet of oil-charged vertical
section
• Up to 775 future horizontal locations
• Martin/Andrews block alone holds an
estimated 7.7 billion barrels of original
oil in place
• Offset horizontal drilling activity derisking many zones
14
GREEN RIVER BASIN – PINEDALE
QEP PDP well
Other operators
(No QEP interest)
QEP leasehold
CURRENT ACTIVITY
Number of rigs (as of 9/30/2014)
4
Well cost ($MM)
$4.0
Avg. gross EUR (Bcfe)
4.6
up to 600
Gross locations remaining (1)
Current
Economic
Limit
As of December 31, 2013
Average drill time - spud to total depth
(1)
61
64
45
42
34
27
22
16
Record
8.5
days
14
13
12 10.7
1 Mile
15
UINTA BASIN – RED WASH LOWER MESAVERDE
GEOLOGIC AGE
• Proved reserves of 402 Bcfe (1)
• Approximately 250,000 net
acres in the Uinta Basin
UTAH
TERTIARY
Uinta
Basin
• Over 32,000 net acres in the
Red Wash fairway
(100% WI, 86.5% NRI)
• Vertical wells to average total
depth of 11,000’ with an
average EUR 2.0 Bcfe
Green River
Wasatch
Mesaverde
CRETACEOUS
Red Wash
Mesaverde Play
• Horizontal maximum daily
rate of 9 MMcfed (4 well
average)
(1)
FORMATION
Blackhawk
Mancos
Dakota/Cedar Mtn ss
2013 Multi-well
pads 1 & 2
As of December 31, 2013
Producing Mesaverde wells
Mesaverde Horizontal wells
2013 10 and 20-acre pilot wells
2013 Directional Drilling Pad
Drilling
QEP leasehold
Mesaverde productive fairway
1 Mile
16
WHY INVEST IN QEP?
• Focused inventory of high-quality crude oil and natural gas assets
• Well positioned for future growth
– Williston Basin crude oil play
– Permian Basin crude oil play
– Pinedale liquids-rich gas play
– Uinta Basin (Lower Mesaverde) liquids-rich gas play
– Haynesville Shale dry gas play (optionality)
• Strong balance sheet and ample liquidity providing financial flexibility
17
APPENDIX
DEBT MATURITY SCHEDULE*
$2,000
$1,800 MM
Revolving Credit
~2.00%
$1,750
$1,500
$1,250
5.25%
6.875%
$1,000
5.375%
$750
650.0
625.0
500.0
$500
$176.8 MM
Senior Notes
6.05%
$250
6.80%
6.80%
134.0
136.0
$0
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
* As of December 2, 2014
19
COMMODITY DERIVATIVES
QEP Energy – Gas, oil and NGL derivatives (as of 10/31/2014)
(prices before deducts)
3.1 MMBbls Oil
$93.54 / Bbl - WTI
27.6 Bcf Gas
$4.12 / Mcf
8.1 MMBbls Oil
$90.78 / Bbl - WTI
36.6 Bcf Gas
$4.12 / Mcf
Gas Swaps
Oil Swaps
2014
Commodity Exposed
2015*
* 2015 derivative chart shown for illustration purposes only. No volume guidance has been provided for 2015.
Note: Charts do not include Brent or LLS Oil Basis Swaps
20
2014 GUIDANCE
2014 GUIDANCE (AS OF 11/05/2014)
LOW
HIGH
QEP Energy Oil production (MMBbl)
16.3
16.5
QEP Energy NGL production (MMBbl)
6.6
6.7
QEP Energy natural gas production (Bcf)
175
178
QEP Energy total equivalent production (Bcfe)
312
317
LOE and transportation expense (per Mcfe)
$1.55
$1.65
QEP Energy DD&A (per Mcfe)
$3.00
$3.10
Production taxes, % of field-level revenue
8.5%
9.0%
General and Administrative expense (in millions) (1)
$175
$180
$1,729
$1,759
QEP Energy capital investment (in millions)
Corporate and other capital investment (in millions)
Total QEP Resources capital investment (in millions)
(1)
$15
$1,744
$1,774
Excludes discontinued operations
21
(1)
QEP RESOURCES CAPITAL ALLOCATION
$2,000
$1,800
$1,600
Corporate
$ million
$1,400
Exploratory drilling
51%
$1,200
Williston
32%
$1,000
57%
Uinta
$800
10%
4%
$600
29%
17%
8%
$400
Pinedale
Permian
Midcontinent/SCOOP
18%
$200
22%
$0
6%
Haynesville
19%
14%
(2)
2012
2013
(3)
2014F
Excludes discontinued operations
2012 CAPEX excludes the approximate $1.4 billion North Dakota property acquisition
(3) 2014 CAPEX forecast as of November 5, 2014, excludes the approximate $942 million Permian property acquisition
(1)
(2)
22