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INVESTOR
PRESENTATION
MAY 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 are anything other than historical facts that describe current expectations of QEP
Resources Inc. (QEP) about future financial and operational performance of QEP’s business and assets and can be identified by words such as “anticipates”,
“believes”, “forecasts”, “plans”, “estimates”, “expects”, “should”, “projects”, “will”, or other similar expressions. Forward-looking statements include statements
regarding estimated production and compounded annual growth rate for 2015; estimated original oil in-place; estimated ultimate recoveries; estimated reserves;
potential targets; strength of QEP’s balance sheet; liquidity; reduction of completed well costs; development plans; estimated lease operating expense,
transportation expense, taxes, and general and administrative expenses; and estimates and allocation of capital expenditures. QEP believes that the forecasts,
projections and expectations reflected in the forward-looking statements are reasonable at the time they are made; however such statements should not be
construed as guarantees of future performance. Factors that could cause QEP’s actual results to differ materially from expected results include, but are not limited
to: natural gas, NGL and oil prices; the availability and cost of capital; changes in local, regional, national and global demand for natural gas, oil and NGL;
competition from the same and alternative sources of energy; 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, underground injection, and produced water disposal;
elimination of federal income tax deductions for oil and gas exploration and development; actual drilling results; shortages of oilfield equipment, services and
personnel; operating risks such as unexpected drilling conditions; weather conditions; changes in maintenance and construction costs; permitting and other
regulatory delays; presence of threatened or endangered species on or near current or future areas of development; estimates of contingency losses and outcome
of pending legal proceedings; actions taken by third‐party operators, processors and transporters; demand for oil, natural gas and NGL gathering, transportation
and storage services; natural disasters; large customer defaults; the decision by QEP or third parties to operate in ethane recovery or rejection mode; and the other
risks discussed in QEP’s periodic filings with the Securities and Exchange Commission (SEC), including the Risk Factors section of QEP’s Annual Report on Form
10‐K/A for the year ended December 31, 2014 (the “2014 Form 10‐K/A”).
The SEC requires oil and gas companies, in their filings with the SEC, to disclose estimates of proved oil and gas reserves. 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. Outside of SEC
filings, QEP uses in this and other presentations terms including “estimated ultimate recovery”, “EUR”, “average per-well EUR”, “probable reserves”, “possible
reserves”, “resource potential”, “total estimated resource”, “unproved reserves”, “estimated original oil-in-place”, “estimated original gas-in-place”, “type curves”,
“potential well locations”, and “future development locations” to describe aspects of its portfolio of oil and gas properties beyond estimated proved reserves. QEP
believes such estimates are reasonable, but they are by their nature more speculative than estimates of proved reserves and accordingly are subject to
substantially more risks of actually being realized by QEP. QEP makes no commitment to drill all of the locations to which it has attributed quantities of potentially
recoverable hydrocarbons, and, therefore, the actual volumes of oil and natural gas ultimately recovered and the number of locations ultimately drilled could differ
substantially from QEP’s estimates.
You should not place undue reliance on QEP’s forward-looking statements, which are made as of the date of this presentation. QEP undertakes no obligation to
update any of the information provided in this presentation except as required by applicable law. Investors are urged to carefully consider the disclosures and
discussion of risk factors contained in the 2014 Form 10‐K/A and QEP’s other reports on file with the SEC. All such statements are expressly qualified by this
cautionary statement.
1
QEP AT A GLANCE
•
Balanced upstream portfolio
– Proved reserves of 3.9 Tcfe at YE 2014 in multiple US basins
– Product diversity
• Crude oil
• Natural gas
• Natural gas liquids
•
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
•
Strong balance sheet and ample liquidity providing financial flexibility
2
2014 HIGHLIGHTS & 2015 OUTLOOK
2014 Highlights
• Record crude oil production of 17.1 MMBbl, up 68% from 2013
• Increased crude oil production to 32% of total natural gas equivalent production, up
from 20% in 2013
• Acquired Permian Basin oil and gas properties for $942 million
• Divested non-core upstream properties for $788 million
• Completed the sale of QEP Field Services, including QEP Resources' ownership in
QEP Midstream Partners, LP, for approximately $2.5 billion in cash
2015 Outlook
• Focusing on driving down completed well costs and improving operating efficiency
• Reducing capital expenditures by more than 40% compared with 2014
• Decreasing company operated rig count from a high of 21 in 2014 to less than 10 for
the balance of 2015
3
EXECUTING ON TRANSITION TO OIL
20
18
Oil production (MMBbl)
16
14
12
10
8
6
4
2
2010
2011
(1)
2012
2013
2014
2015E represents midpoint of guidance as of April 29, 2015
2015E
4
ASSET OVERVIEW
QEP Energy 1Q 2015
Production Revenues
QEP Resources
2014YE Proved Reserves
ND
Pinedale
Anticline
26%
56%
38%
WY
59%
15%
Uinta
Basin
6%
Oil
NGL
Natural Gas
Oil
NGL
UT
Natural Gas
AS OF AND FOR THE YEAR ENDED 12/31/14
Total production
Williston Basin
Oil plays
Liquids-rich plays
CO
Dry-gas play
OK
323 Bcfe
% crude oil
32%
Total reserves
3,932 Bcfe
Total approximate net acreage
1,380,000
Permian
Basin
TX
LA
Haynesville
5
AREAS OF OPERATIONS – E&P
WILLISTON BASIN
60,000
Eastern edge
being defined
by drilling
QEP net production
(Boed)
50,000
40,000
30,000
Fort Berthold
20,000
10,000
-
South
Antelope
 Proved reserves of 143 MMBoe (1)
(1) As of December 31, 2014
20 Miles
Bakken Formation wells
Three Forks Formation wells
Operated focus area
QEP acreage
7
WILLISTON BASIN – SOUTH ANTELOPE
5,000 to 10,500-ft laterals
Recent change to large proppant
volume fracs - approx. 50 stages
Evaluating down-spacing
opportunities
Q1 Completions
CURRENT ACTIVITY
3-well pad (2 Bakken /
1 Three Forks)
3
Number of rigs (1)
Average PDP gross EUR
Bakken
(2)
(MBoe)
1,100
Three Forks (2) (MBoe)
1,060
Q1 Completions
4-well pad (2 Bakken/
2 Three Forks)
QEP Q1 Completions (9 wells)
Q1 Completions
QEP Drilling (1)
QEP Waiting on Completion (WOC, 38 wells)
Q1 Infill Pilot
Program
2-well pad (2 Three
Forks)
(1)
Bakken wells
Three Forks wells
QEP acreage
(1) As of March 31, 2015
(2) 2014 2nd Half Completions
3 Miles
8
WILLISTON BASIN – SOUTH ANTELOPE – ENHANCED
COMPLETIONS RESULTS
200
100
180
Original Completions - 30-35 Stgs; 3-4 MMlbs -60 WELLS
160
Mid-Size Completions - 31-34 Stgs; 7.5-9 MMlbs-17 WELLS
75 MBoe uplift
Most Recent Completions - 48-51 Stgs; 9.5-10 MMlbs-10 WELLS
120
60
Original well count
100
80
40
Well Count – dotted lines
Cumulative Production (MBoe)
140
80
60
Mid-size well count
40
20
20
Most recent well count
0
0
0
30
60
90
Days on Production
Enhanced completion infill wells are out-performing parent wells on average
120
9
HIGH DENSITY DOWN-SPACING TESTS
QEP Thompson Unit
Bakken Formation wells
Three Forks Formation wells
QEP planned wells
QEP acreage
Existing Wells
Phase 1 – Producing
QEP Drilling
10
WILLISTON BASIN – FORT BERTHOLD
Strong well performance
5,000 to 12,500-ft laterals
Utilizing larger proppant volume
fracs - approx. 50 stages
Evaluating down spacing
opportunities
Q1 Completions
3-well pad (1 Bakken /
2 Three Forks)
CURRENT ACTIVITY
Number of rigs (1)
Eastern edge
being defined
by drilling
1
Average PDP EUR 300 to 900 MBoe/Well
Bakken (2) (MBoe)
550
Three Forks (2) (MBoe)
550
QEP Q1 Completions (7 wells)
QEP Drilling (1)
QEP Waiting on Completion (WOC, 2 wells) (1)
Q1 Completions
Bakken wells
4-well pad (2 Bakken /
2 Three Forks)
Three Forks wells
QEP acreage
(1) As of March 31, 2015
(2) As of December 31, 2014
6 Miles
11
 Proved reserves of 63 MMBoe (1)
 Net acres - 26,761
 16 horizontal and 336 vertical operated
producing wells
 Testing multiple horizontal benches
 15 horizontal wells completed since start
of program
 Average perforated lateral length 7,742 ft.
PERMIAN BASIN
Atokaberry Drilling
WC D 7,461’
24hr IP: 882 boepd
WC D Drilling
CURRENT ACTIVITY
Number of vertical rigs (2)
1
Number of horizontal rigs (2)
2
Avg. gross vertical EUR
(Atokaberry) (MBoe) (3)
3 Well Stack WOC
1 SS, 1 WC B, 1 WC D
WC D 8,524’
24hr IP: 1200 boepd
Existing vertical PDP well
Q1 2015 vertical completion
Q1 2015 horizontal completion
QEP vertical rig
QEP horizontal rig
QEP acreage
Spraberry Shale
2 Wells Drilling
WC B 7,441’
24hr IP: 980 boepd
Middle Spraberry
Spraberry Shale
Wolfcamp B
Wolfcamp D
Well in Progress
WC B 7,466’
24hr IP: 395 boepd
WC B 3 Wells WOC
253
As of December 31, 2014
As of March 31, 2015
(3) Post-processing volumes
(1)
(2)
12
MIDLAND BASIN TYPE LOG
Target interval for vertical completions
N. Midland Basin Type log
Estimated Original Oil in Place
U. Spraberry
40 MMbo/Sq. Mile
M. Spraberry
60 MMbo/Sq. Mile
L. Spraberry
Jo Mill Sand
7 MMbo/Sq. Mile
L. Spraberry
Shale
40 MMbo/Sq. Mile
Dean
Wolfcamp “A”
22 MMbo/Sq. Mile
Wolfcamp “B”
25 MMbo/Sq. Mile
Wolfcamp “C”
45 MMbo/Sq. Mile
Wolfcamp “D”
(Cline)
35 MMbo/Sq. Mile
Strawn
Atoka
Barnett
Shale
Carbonate
27 MMbo/Sq. Mile
 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 de-risking many
zones
Potential horizontal targets
13
GREEN RIVER BASIN – PINEDALE ANTICLINE
 Proved reserves 1.45 Tcfe (1)
QEP Drilled Well
Other operators
(No QEP interest)
 Strong early results from new completion
design
QEP Drilling (2)
QEP acreage
CURRENT ACTIVITY
Number of rigs
3
(2)
4.6
Avg. gross EUR (Bcfe) (2)
1 Mile
Pinedale
Field
Current
economic limit
(1)
(2)
As of December 31, 2014
As of March 31, 2015
14
PINEDALE ENHANCED COMPLETIONS RESULTS
350
New Completion: 35 wells
115 MMcfe
uplift
Old Completion (Direct Offsets): 88 wells
Gross Cumulative Production (Mmcfe)
300
250
200
150
100
50
0
0
30
Days on Production
60
90
15
UINTA BASIN – RED WASH LOWER MESAVERDE
Proved reserves of 623 Bcfe(1)
Approximately 232,000 net acres in the Uinta Basin
Over 48,000 net acres in the Red Wash Unit (100% WI, 86.5%
NRI)
Most recent horizontal well cumulative production of >1.0
Bcfe in 80 days
Additional potential in shallower and deeper zones
UTAH
Uinta
Basin
Red Wash
Mesaverde Play
Producing Mesaverde wells
Mesaverde horizontal wells
8 Directional wells drilling
•
5 wells waiting on completion (2)
•
3 wells with intermediate casing (2)
QEP acreage
Most Recent
Horizontal Well
(1) As of December 31, 2014 total Uinta Basin
(2) As of March 31, 2015
Red Wash Unit
16
2,350’ – Gas Saturated Sandstones & Siltstones
UINTA BASIN HORIZONTAL TARGETS
BRAIDED
UPPER NESLEN
LOWER NESLEN/
CASTLEGATE
BLACKHAWK
Shale
Sandstone
Braided
Vertical testing shows potential for two horizontal targets in
the western part of the Red Wash Unit
Upper Neslen
An estimated 60% of vertical Mesaverde production comes
from the Neslen interval. The upper Neslen interval could
potentially be developed horizontally
Lower Neslen
Current horizontal target
Blackhawk
When commingled with Mesaverde, the Blackhawk represents
an estimated 30% of total production from vertical wells and
could also be developed horizontally
17
WHY INVEST IN QEP
• Focused and balanced 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
18
APPENDIX
DEBT MATURITY SCHEDULE (1)
$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
(1) As of May 2015
20
COMMODITY DERIVATIVES
QEP ENERGY COMMODITY DERIVATIVE POSITIONS (as of 4/24/2015)
Year
Type of Contract
Index
Total
Volumes
Average price
per unit
(in millions)
Gas sales
(MMBtu)
2015
Swap
NYMEX HH
46.6 $
3.48
2015
Swap
IFNPCR
31.9 $
3.55
2016
Swap
NYMEX HH
18.3 $
3.24
2016
Swap
IFNPCR
14.6 $
2.91
Oil sales
(Bbl)
2015
Swap
NYMEX WTI
7.1 $
83.93
2015
Swap
ICE Brent
0.3 $
104.95
2016
Swap
NYMEX WTI
2.2 $
66.06
QEP ENERGY CRUDE OIL SALES COSTLESS COLLARS (as of 4/24/2015)
Year
2015
Index
NYMEX WTI
Total Volume Bbl
Average Price Floor
Average Price Ceiling
(in millions)
0.3 $
50.00 $
64.35
Note: Tables do not include Henry Hub Gas Basis Swaps
21
2015 GUIDANCE
2015 GUIDANCE (AS OF 4/29/2015)
LOW
HIGH
QEP Energy Oil production (MMBbl)
17.0
18.5
QEP Energy NGL production (MMBbl)
4.0
4.3
QEP Energy natural gas production (Bcf)
165
175
QEP Energy total equivalent production (Bcfe)
291
312
LOE and transportation expense (per Mcfe)
$1.70
$1.85
QEP Energy DD&A (per Mcfe)
$2.70
$3.00
Production taxes, % of field-level revenue
8.5%
9.0%
General and Administrative expense (in millions)
$170
$185
QEP Resources capital investment (in millions)
$900
$1,050
22
QEP RESOURCES CAPITAL ALLOCATION
(1)
$2,000
$1,800
$1,600
Corporate
$1,400
$1,200
$ million
Exploratory drilling
50%
Williston Basin
57%
$1,000
$800
Uinta Basin
8%
$600
8%
$400
18%
$200
Permian Basin
16%
22%
6%
$0
2014
Midcontinent/SCOOP
3%
19%
14%
2013
Pinedale Anticline
52%
(2)
Haynesville
21%
2015E
(3)
Excludes discontinued operations
Excludes the $942 million Permian property acquisition
(3) As of April 29, 2015
(1)
(2)
23