EX-99.1 2 qepr-q4yeearningsrelease20.htm EXHIBIT QEPR - Q4 YE Earnings Release 2014


QEP RESOURCES REPORTS FOURTH QUARTER AND FULL YEAR 2014 FINANCIAL AND OPERATIONAL RESULTS

Full Year 2014 Highlights

▪
Delivered record annual Adjusted EBITDA
▪
Reported 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 an aggregate purchase price of $942 million
▪
Divested non-core upstream properties for $788 million
▪
Closed the sale of QEP Field Services, including QEP Resources' ownership in QEP Midstream Partners, LP, for approximately $2.5 billion in cash, resulting in a pre-tax gain on sale of approximately $1.8 billion

DENVER — February 24, 2015 — QEP Resources, Inc. (NYSE: QEP) (QEP or the Company) today reported fourth quarter and full year 2014 financial and operating results. The Company reported net income of $665.9 million for the fourth quarter 2014, or $3.72 per diluted share, compared with a net loss of $52.0 million, or $0.29 per diluted share, in the fourth quarter 2013. For the year ended December 31, 2014, QEP Resources reported net income of $784.4 million, or $4.36 per diluted share, compared with $159.4 million, or $0.89 per diluted share, for the comparable 2013 period.

Net income or loss includes non-cash gains and losses associated with the change in the fair value of derivative instruments, gains and losses from asset sales, costs associated with the early extinguishment of debt and impairment charges. Excluding these items, the Company's fourth quarter 2014 Adjusted Net Income (a non-GAAP measure) was $38.6 million, or $0.22 per diluted share, compared with $52.3 million, or $0.29 per diluted share, in the fourth quarter 2013. Similarly, for the year ended December 31, 2014, the Company’s Adjusted Net Income was $239.1 million, or $1.33 per diluted share, compared with $196.1 million, or $1.09 per diluted share, for 2013.

Adjusted EBITDA (a non-GAAP measure) for the fourth quarter 2014 was $386.3 million, compared with $377.1 million in the fourth quarter 2013. Adjusted EBITDA from continuing operations in the fourth quarter 2014 was $366.1 million, a 14% increase from the comparable 2013 period. For the year ended December 31, 2014, the Company reported Adjusted EBITDA of $1,582.7 million compared with $1,536.7 million for 2013. The definition and reconciliations of Adjusted EBITDA and Adjusted Net Income to net income are provided within the financial tables of this release.

“Record fourth quarter operating results demonstrate our successful transformation into a more focused, independent exploration and production company,” commented Chuck Stanley, Chairman, President and CEO of QEP Resources. “Our high quality E&P asset portfolio, combined with year-end 2014 net debt of approximately $1.1 billion and an undrawn $1.8 billion revolving credit facility positions us well in the current commodity price environment. While we have ample liquidity, given current commodity price uncertainty, we are substantially reducing our forecasted 2015 capital expenditures by greater than 40% compared with 2014 as we focus on driving down completed well costs and improving operating efficiency across the company," concluded Stanley.

Slides for the fourth quarter 2014 with maps and other supporting materials referred to in this release are posted on the Company’s website at www.qepres.com.


1

QEP Financial Results Summary

Adjusted EBITDA by Segment
 
Three Months Ended
 
Year Ended
 
December 31,
 
December 31,
 
2014
 
2013
 
Change
 
2014
 
2013
 
Change
 
(in millions)
QEP Energy
$
358.5

 
$
302.0

 
18.7
 %
 
$
1,437.0

 
$
1,301.8

 
10.4
 %
QEP Marketing and Other
7.6

 
18.0

 
(57.8
)%
 
1.3

 
14.2

 
(90.8
)%
Discontinued Operations
20.2

 
57.1

 
(64.6
)%
 
144.4

 
220.7

 
(34.6
)%
Adjusted EBITDA(1)
$
386.3

 
$
377.1

 
2.4
 %
 
$
1,582.7

 
$
1,536.7

 
3.0
 %
 
 
 
 
 
 
 
 
 
 
 
 
(1) See attached financial tables of this release for a reconciliation of Adjusted EBITDA to net income attributable to QEP.

QEP Energy

▪
Adjusted EBITDA increased 19% to $386.3 million compared with $377.1 in the fourth quarter 2013. The increase was due to increased oil production, partially offset by decreased natural gas production and increased expenses.
▪
Net equivalent production increased by 14% to 85.9 Bcfe in the fourth quarter 2014 compared to 75.1 Bcfe in the fourth quarter 2013. This increase was due primarily to increased crude oil and NGL production in the Williston Basin and the addition of Permian Basin acquisition production, partially offset by decreased production in Haynesville and the divestiture of certain Midcontinent assets during the second quarter 2014.
▪
Crude oil and NGL production increased 70% and 22%, respectively, while natural gas production decreased 8%, in the fourth quarter 2014, compared with the fourth quarter 2013.
▪
Crude oil and NGL revenues increased 21% compared to the fourth quarter 2013 and represented 69% of field-level revenues.
▪
In December 2014, QEP completed the sale of its interests in certain non-core properties in southern Oklahoma for an aggregate sale price of $94.9 million, subject to post-closing purchase price adjustments.
▪
In the fourth quarter 2014, QEP recorded an impairment of proven and unproven properties of $1.1 billion primarily in Haynesville and in the Permian Basin due to lower commodity prices.
▪
QEP Energy's capital investment (on an accrual basis) for the year ended December 31, 2014, was $1,728.7 million, excluding $941.8 million related to the Permian Basin acquisition, which closed in the first quarter of 2014.

QEP Marketing & Other

▪
On December 2, 2014, QEP closed the sale of substantially all of its midstream business (excluding the Haynesville Gathering System), including the Company's ownership interest in QEP Midstream Partners, LP (QEP Midstream), to Tesoro Logistics LP (Tesoro) for total cash proceeds of $2.5 billion, including $230.0 million to refinance debt at QEP Midstream (the Midstream Sale), and recorded a pre-tax gain of $1.8 billion on its Consolidated Statements of Operations. As a result of the Midstream Sale, the QEP Field Services reporting segment, excluding the retained ownership of the Haynesville Gathering System, has been reclassified as discontinued operations in the financial tables contained within this release. For reporting purposes, the retained Haynesville Gathering System has been combined with QEP Marketing and Other.


2

QEP 2015 Guidance

In response to the current commodity price environment QEP is significantly reducing its forecasted 2015 capital budget compared with 2014. The Company intends to reduce its operated rig count in 2015 by greater than 50% compared with 2014 and as such, expects to see slower oil production growth in 2015.

QEP Resources full year 2015 guidance and related assumptions are shown below. The Company’s guidance assumes no asset acquisitions or divestitures, and that QEP will not recover ethane from its produced gas for the entire year.
Guidance and Assumptions
 
2015
 
Current Forecast
QEP Energy oil production (MMBbl)
16.5 - 18.5
QEP Energy NGL production (MMBbl)
4.0 - 4.5
QEP Energy natural gas production (Bcf)
155 - 175
   QEP Energy total equivalent production (Bcfe)
278 - 313
 
 
Lease operating and transportation expense (per Mcfe)
$1.70 - $1.85
QEP Energy Depletion, Depreciation and Amortization (per Mcfe)
$3.00 - $3.30
Production and property taxes, % of field-level revenue
8.5% - 9.0%
 
 
Figures below in millions
QEP Resources General and Administrative Expense
$165 - $185
 
 
QEP Resources Capital Investment
$900 - $1,050

Proved Reserves Summary

QEP Energy's estimated proved reserves totaled 3.9 Tcfe at December 31, 2014, down 3% from year-end 2013, due primarily to the net impact of acquisition and divestiture activity in 2014. Approximately 41% of total proved reserves at year-end 2014 were crude oil and NGL compared to 37% at year-end 2013. Total proved developed reserves comprised 2.2 Tcfe, or 56%, of the total reserves. Extensions and discoveries were 0.3 Tcfe resulting from additions in the Williston Basin and Pinedale. Purchases of reserves in place were 0.4 Tcfe due primarily to the Permian Basin acquisition offset by the sale of reserves in place of 0.5 Tcfe due primarily to the Midcontinent asset sales. A reconciliation of reported quantities of proved reserves is summarized in the table below:

 
 
Natural Gas
 
Oil
 
NGL
 
Natural Gas Equivalents
 
 
(Bcf)
 
(MMBbl)
 
(MMBbl)
 
(Bcfe)(1)
Balance at December 31, 2013
 
2,554.9

 
148.6

 
102.6

 
4,061.9

    Revisions of previous estimates
 
27.1

 
(4.0
)
 
1.4

 
11.3

    Extensions and discoveries
 
141.4

 
16.8

 
8.6

 
294.1

    Purchase of reserves in place
 
72.5

 
35.7

 
12.3

 
360.7

    Sale of reserves in place
 
(299.4
)
 
(7.5
)
 
(21.5
)
 
(473.4
)
    Production
 
(179.3
)
 
(17.1
)
 
(6.8
)
 
(322.7
)
Balance at December 31, 2014
 
2,317.2

 
172.5

 
96.6

 
3,931.9


(1) Oil and NGL are converted to natural gas equivalents at the ratio of one barrel of crude oil, condensate or NGL to six Mcf of equivalent natural gas.

3

Details on year-end 2014 and 2013 proved reserves by QEP Energy region/operating area, proved reserve category and percentage of total proved reserves comprised of crude oil and NGL (liquids) are as follows:

 
 
Total (in Bcfe)
 
% of total
 
PUD %
 
% liquids
For the year ended December 31, 2014
 
 
 
 
 
 
Northern Region
 
 
 
 
 
 
 
 
Pinedale
 
1,450.1

 
37
%
 
41
%
 
24
%
Williston Basin
 
858.9

 
22
%
 
40
%
 
88
%
Uinta Basin
 
623.0

 
16
%
 
48
%
 
32
%
Other Northern
 
94.0

 
2
%
 
—
%
 
11
%
Southern Region
 
 
 

 
 
 
 
Haynesville/Cotton Valley
 
493.9

 
13
%
 
57
%
 
—
%
Permian Basin
 
375.7

 
10
%
 
58
%
 
78
%
Midcontinent
 
36.3

 
—
%
 
—
%
 
19
%
Total QEP Energy
 
3,931.9

 
100
%
 
44
%
 
41
%
 
 
 
 
 
 
 
 
 
For the year ended December 31, 2013
 
 
 
 
 
 
Northern Region
 
 
 
 
 
 
 
 
Pinedale
 
1,563.2

 
39
%
 
43
%
 
24
%
Williston Basin
 
797.5

 
20
%
 
59
%
 
94
%
Uinta Basin
 
586.4

 
14
%
 
53
%
 
35
%
Other Northern
 
92.6

 
2
%
 
—
%
 
8
%
Southern Region
 
 
 
 
 
 
 
 
Haynesville/Cotton Valley
 
502.8

 
12
%
 
55
%
 
—
%
Permian Basin
 
—

 
—
%
 
—
%
 
—
%
Midcontinent
 
519.4

 
13
%
 
34
%
 
35
%
Total QEP Energy
 
4,061.9

 
100
%
 
47
%
 
37
%


4

Operations Summary


 
Operated Completions
 
Non-operated Completions
 
Three Months Ended December 31, 2014
 
Year Ended December 31, 2014
 
Three Months Ended December 31, 2014
 
Year Ended December 31, 2014
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Northern Region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pinedale
21

 
8.8

 
116

 
82.4

 
—

 
—

 
—

 
—

Williston Basin
15

 
12.4

 
88

 
72.9

 
56

 
3.4

 
111

 
7.7

Uinta Basin
2

 
1.0

 
7

 
6.0

 
27

 
0.1

 
189

 
0.5

Other Northern
4

 
4.0

 
4

 
4.0

 
—

 
—

 
—

 
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Southern Region
 
 
 
 
 

 
 

 
 
 
 
 
 

 
 

Haynesville/Cotton Valley
—

 
—

 
—

 
—

 
15

 
1.9

 
41

 
3.5

Permian Basin
26

 
22.8

 
70

 
62.9

 
—

 
—

 
1

 
0.3

Midcontinent
—

 
—

 
1

 
0.9

 
3

 
0.2

 
31

 
1.4


Williston Basin

Williston Basin net production averaged approximately 54 Mboed (90% liquids) during the fourth quarter 2014, an 18% increase over the third quarter 2014, and a 95% increase over the fourth quarter 2013. The Company completed and turned to sales 15 gross operated wells during the quarter (average working interest 83%), all in South Antelope. In the second half of 2014 the Company transitioned to larger fracture stimulations (average 1,000 pounds of proppant per lateral foot) and increased the number of stages per completion with very encouraging early results. On average, the wells completed with the enhanced design are exhibiting an uplift in cumulative production volumes after 90 days online of more than 30% compared to offset wells completed with the older stimulation design. QEP also participated in 56 gross outside-operated Bakken/Three Forks wells that were completed and turned to sales during the quarter (average working interest 6%). In the fourth quarter, the Company completed three operated wells utilizing cemented liners with "plug and perf" completion technology to further evaluate optimum stimulation design; production results are still being evaluated.

At the end of the fourth quarter, QEP had 35 gross operated wells waiting on completion (average working interest 78%) and six operated rigs running, all in South Antelope. In addition, the Company had interests in 11 gross outside-operated wells being drilled (average working interest 15%) and 25 gross outside-operated wells waiting on completion (average working interest 3%) at the end of the fourth quarter.

Slides 6-8 depict QEP Energy's acreage and activity in the Williston Basin.

Permian Basin

Daily production during the fourth quarter 2014 averaged 9.7 Mboed (80% liquids). In the fourth quarter, QEP completed and turned to sales 20 vertical and six horizontal wells. The six horizontal operated wells, comprised of four Wolfcamp B, one Spraberry Shale, and one Middle Spraberry, had an average maximum daily production rate of 1,025 Boed and a maximum average 30-day production rate of 758 Boed. The horizontal Sprayberry Shale well had a maximum daily rate of 1,556 Boed.

At the end of the fourth quarter, QEP had six operated rigs in the Permian Basin; two drilling vertical Atokaberry wells and four drilling horizontal targets in the Wolfcamp B and Wolfcamp D sections. The Company had six gross operated wells waiting on completion (average working interest of 87%) at end of the fourth quarter comprised of three horizontal and three vertical wells.

Slide 9 depicts QEP Energy's acreage and activity in the Permian Basin.


5

Pinedale Anticline

During the fourth quarter 2014, QEP's Pinedale net production averaged 285 MMcfed (24% liquids). QEP recovered ethane from Pinedale production throughout 2014 and plans to reject ethane in 2015. While ethane rejection results in 7-8% less natural gas equivalent sales volumes, it has a negligible impact on gross revenues at current ethane prices. 

At the end of the fourth quarter, the Company had four rigs operating in Pinedale. In the fourth quarter, drill times from spud to total depth averaged 10.7 days, compared with an average of 12.0 days in 2013. The Company completed and turned to sales 21 gross Pinedale wells during the fourth quarter 2014, including six wells which QEP operates but owns only a small overriding royalty interest. At the end of the fourth quarter, the Company had 45 gross Pinedale wells with QEP working interests drilled, cased and waiting on completion (average working interest 64%).

A new completion design tested on 16 wells has resulted in an average 1.5 MMcfed initial production increase and a 60-day cumulative production increase of over 40% from the older design.

The Company completed 116 gross wells during 2014, including approximately 10 wells for which QEP is the designated operator but owns only a small overriding royalty interest.

Slides 10-11 depict QEP Energy's acreage and activity in the Pinedale field.

Uinta Basin

During the fourth quarter 2014, Uinta Basin net production averaged 81 MMcfed (34% liquids) of which 28 MMcfed (30% liquids) was from the Lower Mesaverde play. QEP recovered ethane from Uinta Basin gas production throughout 2014 and plans to reject ethane in 2015. While ethane rejection results in 7-8% less natural gas equivalent sales volumes, it has a negligible impact on gross revenues at current ethane prices. 

At the end of the fourth quarter, QEP had one rig active in the Uinta Basin drilling it’s sixth horizontal Lower Mesaverde well.

Slide 12 depicts QEP Energy's activity in the Red Wash Lower Mesaverde play in the Uinta Basin.

Fourth Quarter 2014 and Full Year Results Conference Call

QEP Resources' management will discuss fourth quarter and full year 2014 results in a conference call on Wednesday, February 25, 2015, beginning at 9:00 a.m. EST. The conference call can be accessed at www.qepres.com. You may also participate in the conference call by dialing (877) 869-3847 in the U.S. or Canada and (201) 689-8261 for international calls. A replay of the teleconference will be available on the website at www.qepres.com immediately after the call through March 25, 2015, or by dialing (877) 660-6853 in the U.S. or Canada and (201) 612-7415 for international calls, and then entering the conference ID #13599608. In addition, QEP’s slides for the fourth quarter 2014, with updated maps showing QEP’s leasehold and current activity for key operating areas discussed in this release, can be found on the Company’s website at www.qepres.com.

About QEP Resources, Inc.

QEP Resources, Inc. (NYSE:QEP) is a leading independent natural gas and crude oil exploration and production company focused in two major regions: the Northern Region (primarily the Rockies and the Williston Basin) and the Southern Region (primarily Texas and Louisiana) of the United States. For more information, visit QEP Resources' website at: www.qepres.com.


6

Forward-Looking Statements

This release includes forward-looking statements within the meaning of Section 27(a) of the Securities Act of 1933, as amended, and Section 21(e) 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: our liquidity; plans to substantially reduce 2015 capital expenditures; plans to reduce well costs and improve operating efficiency; forecasted production, lease operating and transportation expense, DD&A expense, general and administrative expense, property taxes and capital investment for 2015 and related assumptions for such guidance; plans to reject ethane in 2015; proved reserves; drilling times and completion designs in the Pinedale Anticline; and importance of non-GAAP financial measures. Actual results may differ materially from those included in the forward-looking statements due to a number of factors, including, but not limited to: changes in natural gas, NGL and oil prices; the availability of capital; global geopolitical and macroeconomic factors; general economic conditions, including interest rates; changes in local, regional, national and global demand for natural gas, oil and NGL; impact of new laws and regulations, including regulations regarding the flaring of natural gas, the use of hydraulic fracture stimulation and the implementation of the Dodd-Frank Act; impact of U.S. dollar exchange rates on oil, NGL and natural gas prices; 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; transportation constraints; weather conditions; changes in maintenance and construction costs; permitting delays; the availability and cost of credit; outcome of contingencies such as legal proceedings; inadequate supplies of water and/or lack of water disposal sources; and the other risks discussed in the Company’s periodic filings with the Securities and Exchange Commission, including the Risk Factors section of the Company’s Annual Report on Form 10-K for the year ended December 31, 2013. QEP Resources undertakes no obligation to publicly correct or update the forward-looking statements in this news release, in other documents, or on the website to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.

Disclosures regarding Estimated Ultimate Recovery (EUR)

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; however, QEP has made no such disclosures in its filings with the SEC. QEP uses certain terms in its periodic news releases and other presentation materials such as “estimated ultimate recovery” or “EUR”, “resource potential”, and “net resource potential”. These estimates are by their nature more speculative than estimates of proved, probable or possible reserves and accordingly are subject to substantially more risks of actually being realized. The SEC guidelines strictly prohibit QEP from including such estimates in filings with the SEC. Investors are urged to closely consider the disclosures about the Company’s reserves in its Annual Report on Form 10-K for the year ended December 31, 2013, and in other reports on file with the SEC.

Contact

Investors:                    Media:
William I. Kent                    Brent Rockwood
Director, Investor Relations            Director, Communications
303-405-6665                    303-672-6999


7

QEP RESOURCES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
 
Three Months Ended
 
Year Ended
 
December 31,
 
December 31,
 
2014

2013
 
2014
 
2013
REVENUES
(in millions, except per share amounts)
Gas sales
$
167.2

 
$
168.5

 
$
776.4

 
$
779.0

Oil sales
327.5

 
260.3

 
1,368.5

 
916.6

NGL sales
44.0

 
47.8

 
223.3

 
192.2

Gathering, processing and other
6.0

 
13.7

 
11.1

 
22.4

Purchased gas, oil and NGL sales
254.9

 
130.0

 
1,035.0

 
774.9

Total Revenues
799.6

 
620.3

 
3,414.3

 
2,685.1

OPERATING EXPENSES
 

 
 

 
 

 
 

Purchased gas, oil and NGL expense
255.7

 
133.2

 
1,031.2

 
783.5

Lease operating expense
63.1

 
51.1

 
240.1

 
181.3

Gas, oil and NGL transport & other handling costs
79.1

 
63.5

 
277.6

 
222.0

Gathering and other expenses
1.9

 
2.0

 
6.7

 
8.4

General and administrative
57.4

 
43.6

 
204.4

 
160.4

Production and property taxes
44.4

 
47.6

 
205.2

 
161.3

Depreciation, depletion and amortization
282.2

 
244.5

 
994.7

 
963.8

Exploration expenses
5.2

 
2.4

 
9.9

 
11.9

Impairment
1,139.6

 
89.0

 
1,143.2

 
93.0

Total Operating Expenses
1,928.6

 
676.9

 
4,113.0

 
2,585.6

Net gain (loss) from asset sales
61.7

 
(9.9
)
 
(148.6
)
 
103.5

OPERATING INCOME (LOSS)
(1,067.3
)
 
(66.5
)
 
(847.3
)
 
203.0

Realized and unrealized gains on derivative contracts
376.5

 
7.3

 
363.3

 
58.9

Interest and other income
5.0

 
(7.5
)
 
12.8

 
15.2

Income from unconsolidated affiliates
0.1

 
0.2

 
0.3

 
0.2

Loss from early extinguishment of debt
(2.0
)
 
—

 
(2.0
)
 
—

Interest expense
(40.7
)
 
(40.4
)
 
(169.1
)
 
(165.1
)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
(728.4
)
 
(106.9
)
 
(642.0
)
 
112.2

Income taxes (provision) benefit
258.6

 
22.4

 
232.5

 
(60.1
)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS
(469.8
)
 
(84.5
)
 
(409.5
)
 
52.1

Net income from discontinued operations, net of income tax
1,135.7

 
32.5

 
1,193.9

 
107.3

NET INCOME (LOSS) ATTRIBUTABLE TO QEP
$
665.9

 
$
(52.0
)
 
$
784.4

 
$
159.4

 
 
 
 
 
 
 
 
Earnings (Loss) Per Common Share Attributable to QEP
 

 
 

 
 

 
 

Basic from continuing operations
$
(2.62
)
 
$
(0.47
)
 
$
(2.28
)
 
$
0.29

Basic from discontinued operations
$
6.34

 
$
0.18

 
$
6.64

 
0.60

Basic total
$
3.72

 
$
(0.29
)
 
$
4.36

 
$
0.89

Diluted from continuing operations
$
(2.62
)
 
$
(0.47
)
 
$
(2.28
)
 
$
0.29

Diluted from discontinued operations
$
6.34

 
$
0.18

 
$
6.64

 
$
0.60

Diluted total
$
3.72

 
$
(0.29
)
 
$
4.36

 
$
0.89

 
 
 
 
 
 
 
 
Weighted-average common shares outstanding
 
 
 
 
 
 
 
Used in basic calculation
179.0

 
179.3

 
179.8

 
179.2

Used in diluted calculation
179.0

 
179.3

 
179.8

 
179.5

Dividends per common share
$
0.02


$
0.02

 
$
0.08


$
0.08

 
 
 
 
 
 
 
 


8

QEP RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
 
December 31,
2014
 
December 31,
2013
ASSETS
(in millions)
Current Assets
 
 
 
Cash and cash equivalents
$
1,160.1

 
$
11.9

Accounts receivable, net
441.9

 
330.3

Fair value of derivative contracts
339.0

 
0.2

Gas, oil and NGL inventories, at lower of average cost or market
13.7

 
13.4

Deferred income taxes - Current
—


27.9

Prepaid expenses and other
46.8

 
45.4

Current assets of discontinued operations
—


122.0

Total Current Assets
2,001.5

 
551.1

Property, Plant and Equipment (successful efforts method for gas and oil properties)
 
 

Proved properties
12,278.7

 
11,571.4

Unproved properties, net
825.2

 
665.1

Marketing and other
293.8

 
282.8

Materials and supplies
54.3

 
54.3

Total Property, Plant and Equipment
13,452.0

 
12,573.6

Less Accumulated Depreciation, Depletion and Amortization
 

 
 

Exploration and production
6,153.0

 
4,930.9

Marketing and other
67.8

 
50.2

Total Accumulated Depreciation, Depletion and Amortization
6,220.8

 
4,981.1

Net Property, Plant and Equipment
7,231.2

 
7,592.5

Restricted cash
—


50.0

Fair value of derivative contracts
9.9


1.0

Other noncurrent assets
44.2


46.6

Noncurrent assets of discontinued operations
—


1,167.7

TOTAL ASSETS
$
9,286.8

 
$
9,408.9

LIABILITIES AND EQUITY
 

 
 

Current Liabilities
 

 
 

Checks outstanding in excess of cash balances
$
54.7

 
$
109.1

Accounts payable and accrued expenses
575.4

 
361.9

Income taxes payable
532.1

 
8.7

Production and property taxes
61.7

 
54.7

Interest payable
36.4

 
37.2

Fair value of derivative contracts
—

 
26.7

Deferred income taxes
84.5

 
—

Current liabilities of discontinued operations
—


75.3

Total Current Liabilities
1,344.8

 
673.6

Long-term debt
2,218.1

 
2,997.5

Deferred income taxes
1,362.7

 
1,364.9

Asset retirement obligations
193.8

 
163.3

Other long-term liabilities
92.1

 
94.5

Noncurrent liabilities of discontinued operations
—


238.3

Commitments and contingencies





EQUITY
 

 
 

Common stock - par value $0.01 per share; 500.0 million shares authorized; 176.2 million and 179.7 million shares issued, respectively
1.8

 
1.8

Treasury stock - 0.8 million and 0.4 million shares, respectively
(25.4
)
 
(14.9
)
Additional paid-in capital
535.3

 
498.4

Retained earnings
3,587.9

 
2,917.8

Accumulated other comprehensive income (loss)
(24.3
)
 
(26.5
)
Total Common Shareholders' Equity
4,075.3

 
3,376.6

Noncontrolling interest
—

 
500.2

Total Equity
4,075.3

 
3,876.8

TOTAL LIABILITIES AND EQUITY
$
9,286.8

 
$
9,408.9


9

QEP RESOURCES, INC.
CONSOLIDATED CASH FLOWS
 
Year Ended
 
December 31,
 
2014

2013
 
(in millions)
OPERATING ACTIVITIES
 

 
 

Net income attributable to QEP
$
784.4

 
$
159.4

Net income attributable to noncontrolling interest
21.6


12.0

Adjustments to reconcile net income to net cash provided by operating activities:
 
 

Depreciation, depletion and amortization
1,040.6

 
1,016.0

Deferred income taxes
(84.1
)
 
66.1

Impairment
1,143.2

 
93.0

Equity-based compensation
27.2

 
27.1

Amortization of debt issuance costs and discounts
6.7

 
6.4

Net gain from asset sales
(1,644.8
)
 
(103.0
)
Income from unconsolidated affiliates
(5.2
)
 
(5.8
)
Distributions from unconsolidated affiliates and other
9.4

 
7.9

Non-cash loss on early extinguishment of debt
4.4

 
—

Unrealized (gains) losses on derivative contracts
(374.4
)
 
88.7

Changes in operating assets and liabilities
613.5

 
(176.1
)
Net Cash Provided by Operating Activities
1,542.5

 
1,191.7

INVESTING ACTIVITIES
 

 
 

Property acquisitions
(960.5
)
 
(40.9
)
Property, plant and equipment, including dry hole exploratory well expense
(1,765.9
)
 
(1,561.7
)
Proceeds from disposition of assets
3,296.6

 
211.1

Acquisition deposit held in escrow
50.0

 
(50.0
)
Other investments
(42.0
)

—

Net Cash Provided by (Used in) Investing Activities
578.2

 
(1,441.5
)
FINANCING ACTIVITIES
 

 
 

Checks outstanding in excess of cash balances
(54.4
)
 
69.3

Long-term debt issued
300.0

 
—

Long-term debt issuance costs paid
(9.3
)
 
(3.2
)
Long-term debt repaid
(600.0
)
 
—

Proceeds from credit facility
5,455.0

 
3,085.0

Repayments of credit facility
(5,935.0
)
 
(3,295.0
)
Common stock repurchased and retired
(99.7
)
 
—

Treasury stock repurchased
(6.2
)
 
(9.3
)
Other capital contributions
6.0

 
7.0

Dividends paid
(14.6
)
 
(14.3
)
Excess tax benefit on equity-based compensation
(0.5
)
 
—

Net proceeds from the issuance of common units
—

 
449.6

Distribution to noncontrolling interest
(31.9
)
 
(9.3
)
Net Cash Provided by (Used in) Financing Activities
(990.6
)
 
279.8

Change in cash and cash equivalents
1,130.1

 
30.0

Beginning cash and cash equivalents
30.0

 
—

Ending cash and cash equivalents
$
1,160.1

 
$
30.0


10

QEP Energy - Production by Region
 
Three Months Ended December 31,
 
Year Ended December 31,
 
(in Bcfe)
 
2014
 
2013
 
Change
 
2014
 
2013
 
Change
Northern Region
 
 
 
 
 
 
 
 
 
 
 
Pinedale
26.3

 
24.6

 
7
 %
 
98.9

 
94.7

 
4
 %
Williston Basin
29.8

 
15.3

 
95
 %
 
91.4

 
47.2

 
94
 %
Uinta Basin
7.5

 
6.8

 
10
 %
 
27.3

 
26.9

 
1
 %
Other Northern
2.7

 
2.3

 
17
 %
 
10.6

 
11.9

 
(11
)%
Total Northern Region
66.3

 
49.0

 
35
 %
 
228.2

 
180.7

 
26
 %
Southern Region
 
 
 
 
 
 
 
 
 
 
 
Haynesville/Cotton Valley
11.0

 
14.9

 
(26
)%
 
49.9

 
72.2

 
(31
)%
Permian
5.4

 
—

 
—
 %
 
15.8

 
—

 
—
 %
Midcontinent
3.2

 
11.2

 
(71
)%
 
28.8

 
56.1

 
(49
)%
Total Southern Region
19.6

 
26.1

 
(25
)%
 
94.5

 
128.3

 
(26
)%
Total production
85.9

 
75.1

 
14
 %
 
322.7

 
309.0

 
4
 %


QEP Energy - Total Production
 
Three Months Ended December 31,
 
Year Ended December 31,
 
2014
 
2013
 
Change
 
2014
 
2013
 
Change
QEP Energy Production Volumes
 
 
 
 
 
 
 
 
 
 
 
Gas (Bcf)
44.4

 
48.3

 
(8
)%
 
179.3

 
218.9

 
(18
)%
Oil (Mbbl)
5,181.5

 
3,040.9

 
70
 %
 
17,146.5

 
10,209.7

 
68
 %
NGL (Mbbl)
1,751.3

 
1,433.9

 
22
 %
 
6,769.1

 
4,811.3

 
41
 %
Total production (Bcfe)
85.9

 
75.1

 
14
 %
 
322.7

 
309.0

 
4
 %
Average daily production (MMcfe)
933.2

 
815.8

 
14
 %
 
884.0

 
846.5

 
4
 %


11

QEP Energy - Prices
 
Three Months Ended December 31,
 
Year Ended December 31,
 
2014
 
2013
 
Change
 
2014
 
2013
 
Change
Gas (per Mcf)
 
 
 
 
 
 
 
 
 
 
 
Average field-level price
$
3.78

 
$
3.50

 
 
 
$
4.33

 
$
3.56

 
 
Commodity derivative impact
0.15

 
0.83

 
 
 
(0.09
)
 
0.69

 
 
Net realized price
$
3.93

 
$
4.33

 
(9
)%
 
$
4.24

 
$
4.25

 
—
 %
Oil (per bbl)

 

 
 
 

 
 
 
 
Average field-level price
$
63.21

 
$
85.60

 
 
 
$
79.79

 
$
89.78

 
 
Commodity derivative impact
12.71

 
0.50

 
 
 
0.92

 
(0.22
)
 
 
Net realized price
$
75.92

 
$
86.10

 
(12
)%
 
$
80.71

 
$
89.56

 
(10
)%
NGL (per bbl)

 

 
 
 

 
 
 
 
Average field-level price
$
25.15

 
$
33.34

 
 
 
$
32.95

 
$
39.95

 
 
Commodity derivative impact
—

 
—

 
 
 
—

 
—

 
 
Net realized price
$
25.15

 
$
33.34

 
(25
)%
 
$
32.95

 
$
39.95

 
(18
)%
Average net equivalent price (per Mcfe)

 

 
 
 

 

 
 
Average field-level price
$
6.28

 
$
6.35

 
 
 
$
7.34

 
$
6.11

 
 
Commodity derivative impact
0.84

 
0.55

 
 
 
(0.01
)
 
0.48

 
 
Net realized price
$
7.12

 
$
6.90

 
3
 %
 
$
7.33

 
$
6.59

 
11
 %
 
 
 
 
 
 
 
 
 
 
 
 

 
Three Months Ended December 31,
 
Year Ended December 31,
 
(per Mcfe)
 
2014
 
2013
 
Change
 
2014
 
2013
 
Change
 
 
Depreciation, depletion and amortization
$
3.26

 
$
3.23

 
1
 %
 
$
3.05

 
$
3.09

 
(1
)%
Lease operating expense
0.74

 
0.68

 
9
 %
 
0.74

 
0.59

 
25
 %
Gas, oil and NGL transportation and other handling costs
0.93

 
0.82

 
13
 %
 
0.90

 
0.78

 
15
 %
Production taxes
0.52

 
0.63

 
(17
)%
 
0.63

 
0.51

 
24
 %
Total Operating Expenses
$
5.45

 
$
5.36

 
2
 %
 
$
5.32

 
$
4.97

 
7
 %


12

QEP RESOURCES, INC.
NON-GAAP MEASURES

Adjusted EBITDA

This release contains references to the non-GAAP measure of Adjusted EBITDA. Management believes Adjusted EBITDA is an important measure of the Company's performance relative to other oil and gas producing companies. The use of this measure allows investors to understand how management evaluates financial performance to make operating decisions and allocate resources. Management defines Adjusted EBITDA as earnings before interest, income taxes, depreciation, depletion and amortization (EBITDA) adjusted to exclude changes in fair value of derivative contracts, exploration expenses, gains and losses from asset sales, impairment, and certain other non-cash and/or non-recurring items.

The following tables reconcile net income attributable to QEP to Adjusted EBITDA:
 
QEP Energy
 
QEP Marketing & Other (1)
 
Continuing Operations
 
Discontinued Operations
 
QEP Consolidated
Three Months Ended December 31, 2014
(in millions)
 
 
Net income (loss) attributable to QEP
$
(481.8
)
 
$
12.0

 
$
(469.8
)
 
$
1,135.7

 
$
665.9

Unrealized gains on derivative contracts
(304.4
)
 
(4.1
)
 
(308.5
)
 
—

 
(308.5
)
Net gain from asset sales
(61.7
)
 
—

 
(61.7
)
 
(1,793.5
)
 
(1,855.2
)
Interest and other income
(4.4
)
 
(0.6
)
 
(5.0
)
 
(0.3
)
 
(5.3
)
Income tax provision (benefit)
(261.5
)
 
2.9

 
(258.6
)
 
675.4

 
416.8

Interest expense (income)(2)
47.8

 
(7.1
)
 
40.7

 
0.6

 
41.3

Loss on early extinguishment of debt
—

 
2.0

 
2.0

 
2.4

 
4.4

Depreciation, depletion and amortization(3)
279.7

 
2.5

 
282.2

 
(0.1
)
 
282.1

Impairment
1,139.6

 
—

 
1,139.6

 
—

 
1,139.6

Exploration expenses
5.2

 
—

 
5.2

 
—

 
5.2

Adjusted EBITDA
$
358.5

 
$
7.6

 
$
366.1

 
$
20.2


$
386.3

 
 
 
 
 
 
 
 
 
 
Three Months Ended December 31, 2013
 
 
 
Net income (loss) attributable to QEP
$
(96.3
)
 
$
11.8

 
$
(84.5
)
 
$
32.5

 
$
(52.0
)
Unrealized losses on derivative contracts
32.0

 
1.2

 
33.2

 
—

 
33.2

Net loss from asset sales
9.3

 
0.6

 
9.9

 
0.1

 
10.0

Interest and other income
3.9

 
3.6

 
7.5

 
(3.6
)
 
3.9

Income tax provision (benefit)
(29.6
)
 
7.2

 
(22.4
)
 
17.2

 
(5.2
)
Interest expense (income)(2)
49.2

 
(8.8
)
 
40.4

 
0.1

 
40.5

Depreciation, depletion and amortization(3)
242.1

 
2.4

 
244.5

 
10.8

 
255.3

Impairment
89.0

 
—

 
89.0

 
—

 
89.0

Exploration expenses
2.4

 
—

 
2.4

 
—

 
2.4

Adjusted EBITDA
$
302.0

 
$
18.0

 
$
320.0

 
$
57.1

 
$
377.1











 
 

(1) Includes intercompany eliminations.
 
(2) Excludes noncontrolling interest's share of $0.4 million and $0.3 million during the three months ended December 31, 2014 and 2013, respectively, of interest expense attributable to QEP Midstream.

(3) Excludes noncontrolling interests' share of $2.7 million and $3.6 million during the three months ended December 31, 2014 and 2013, respectively, of depreciation, depletion and amortization attributable to Rendezvous Gas Services, L.L.C. and QEP Midstream.


13

 
QEP Energy
 
QEP Marketing & Other (1)
 
Continuing Operations
 
Discontinued Operations
 
QEP Consolidated
For the Year Ended December 31, 2014
(in millions)
 
 
Net income (loss) attributable to QEP
$
(432.5
)
 
$
23.0

 
$
(409.5
)
 
$
1,193.9

 
$
784.4

Unrealized gains on derivative contracts
(368.2
)
 
(6.2
)
 
(374.4
)
 
—

 
(374.4
)
Net (gain) loss from asset sales
148.6

 
—

 
148.6

 
(1,793.4
)
 
(1,644.8
)
Interest and other income
(11.8
)
 
(1.0
)
 
(12.8
)
 
(0.3
)
 
(13.1
)
Income tax provision (benefit)
(246.9
)
 
14.4

 
(232.5
)
 
708.2

 
475.7

Interest expense (income)(2)
210.3

 
(41.2
)
 
169.1

 
2.3

 
171.4

Loss on early extinguishment of debt
—

 
2.0

 
2.0

 
2.4

 
4.4

Depreciation, depletion and amortization(3)
984.4

 
10.3

 
994.7

 
31.3

 
1,026.0

Impairment
1,143.2

 
—

 
1,143.2

 
—

 
1,143.2

Exploration expenses
9.9

 
—

 
9.9

 
—

 
9.9

Adjusted EBITDA
$
1,437.0

 
$
1.3

 
$
1,438.3

 
$
144.4


$
1,582.7

 
 
 
 
 
 
 
 
 
 
For the Year Ended December 31, 2013
 
 
 
Net income loss attributable to QEP
$
25.6

 
$
26.5

 
$
52.1

 
$
107.3

 
$
159.4

Unrealized (gains) losses on derivative contracts
90.7

 
(2.0
)
 
88.7

 
—

 
88.7

Net (gain) loss from asset sales
(104.1
)
 
0.6

 
(103.5
)
 
0.5

 
(103.0
)
Interest and other income
(3.6
)
 
(11.6
)
 
(15.2
)
 
10.0

 
(5.2
)
Income tax provision (benefit)
41.5

 
18.6

 
60.1

 
59.7

 
119.8

Interest expense (income)(2)
192.6

 
(27.5
)
 
165.1

 
(2.2
)
 
162.9

Depreciation, depletion and amortization(3)
954.2

 
9.6

 
963.8

 
45.4

 
1,009.2

Impairment
93.0

 
—

 
93.0

 
—

 
93.0

Exploration expenses
11.9

 
—

 
11.9

 
—

 
11.9

Adjusted EBITDA
$
1,301.8

 
$
14.2

 
$
1,316.0

 
$
220.7


$
1,536.7

 
 
 
 
 
 
 
 
 
 

(1) Includes intercompany eliminations.
 
(2) Excludes noncontrolling interest's share of $1.5 million and $0.4 million during the years ended December 31, 2014 and 2013, respectively, of interest expense attributable to QEP Midstream.

(3) Excludes noncontrolling interests' share of $14.6 million and $6.8 million during the years ended December 31, 2014 and 2013 respectively, of depreciation, depletion and amortization attributable to Rendezvous Gas Services, L.L.C. and QEP Midstream.





14

Adjusted Net Income

This release also contains references to the non-GAAP measure of Adjusted Net Income. Management defines Adjusted Net Income as earnings excluding gains and losses from asset sales, unrealized gains and losses on derivative contracts, costs from early extinguishment of debt and asset impairments. Management believes Adjusted Net Income is an important measure of the Company’s operational performance relative to other gas and oil producing companies.

The following table reconciles net income attributable to QEP to Adjusted Net Income:
 
Three Months Ended
Year Ended
 
December 31,
December 31,
 
2014
 
2013
 
2014
 
2013
 
(in millions, except per earnings per share)
Net income (loss) attributable to QEP
$
665.9

 
$
(52.0
)
 
$
784.4

 
$
159.4

Adjustments to net income
 
 
 
 
 
 
 
Net (gain) loss from asset sales from continuing operations
(61.7
)
 
9.9

 
148.6

 
(103.5
)
Income taxes on net (gain) loss from asset sales from continuing operations(1)
21.9

 
(2.1
)
 
(53.8
)
 
55.5

Net (gain) loss from asset sales from discontinued operations
(1,793.5
)
 
—

 
(1,793.4
)
 
0.5

Income taxes on net (gain) loss from asset sales from discontinued operations(2)
667.2

 
—

 
660.0

 
(0.2
)
Unrealized (gains) losses on derivative contracts from continuing operations
(308.5
)
 
33.2

 
(374.4
)
 
88.7

Income taxes on unrealized (gains) losses on derivative contracts from continuing operations(1)
109.5

 
(7.0
)
 
135.5

 
(47.5
)
Loss on early extinguishment of debt from continuing operations
2.0

 
—

 
2.0

 
—

Income taxes on loss from early extinguishment of debt from continuing operations(1)
(0.7
)
 
—

 
(0.7
)
 
—

Loss on early extinguishment of debt from discontinued operations
2.4

 
—

 
2.4

 
—

Income taxes on loss from early extinguishment of debt from discontinued operations(2)
(0.9
)
 
—

 
(0.9
)
 
—

Impairment charges from continuing operations
1,139.6

 
89.0

 
1,143.2

 
93.0

Income taxes impairment charges from continuing operations(1)
(404.6
)
 
(18.7
)
 
(413.8
)
 
(49.8
)
Total after-tax adjustments to net income
(627.3
)
 
104.3

 
(545.3
)
 
36.7

Adjusted net income attributable to QEP Resources
$
38.6

 
$
52.3

 
$
239.1

 
$
196.1

 
 
 
 
 
 
 
 
Earnings (Loss) per Common Share attributable to QEP
 
 
 
 
 
 
 
Diluted earnings per share
$
3.72

 
$
(0.29
)
 
$
4.36

 
$
0.89

Diluted after-tax adjustments to net income per share
(3.50
)
 
0.58

 
(3.03
)
 
0.20

Diluted Adjusted Net Income per share
$
0.22

 
$
0.29

 
$
1.33

 
$
1.09

 
 
 
 
 
 
 
 
Weighted-average common shares outstanding
 
 
 
 
 
 
 
Diluted
179.0

 
179.7

 
179.8

 
179.5

 
 
 
 
 
 
 
 
Non-GAAP reconciliation of weighted-average common shares outstanding diluted (3)
 
 
 
 
 
 
Weighted-average common shares outstanding used in GAAP calculation
 
 
179.3

 
 
 
 
Potential number of shares issuable upon exercise of in-the-money stock options under the long-term stock incentive plan
 
 
0.4

 
 
 
 
Weighted-average diluted common shares outstanding used in Non-GAAP calculation
 
 
179.7

 
 
 
 
(1) Uses the effective income tax rate from continuing operations of 35.5% and 21.0% for the three months ended December 31, 2014 and 2013, respectively, and 36.2% and 53.6% for the years ended December 31, 2014 and 2013, respectively.
 
(2) Uses the effective income tax rate from discontinued operations of 37.2% for the three months ended December 31, 2014, and 36.8% and 33.4% for the years ended December 31, 2014 and 2013, respectively.

(3) The three months ended December 31, 2013, diluted common shares outstanding for purposes of calculating Diluted Adjusted Net Income per share includes potential increases in shares that could result from the exercise of in-the-money stock options. These

15

potential shares are excluded for the three months ended December 31, 2013, in calculating earnings-per-share for GAAP purposes, because the effect is antidilutive due to the Company's net loss for GAAP purposes.
     

16

The following table presents open derivative positions as of February 20, 2015:

QEP Energy Commodity Derivative Positions
Year
 
Type of Contract
 
Index
 
Total
Volumes
 
Average price
per unit
 
 
 
 
 
 
(in millions)
 
 
Gas sales
 
 
 
 
 
(MMBtu)

 
 
2015
 
Swap
 
NYMEX HH
 
58.1

 
$
3.48

2015
 
Swap
 
IFNPCR
 
39.8

 
$
3.55

2016
 
Swap
 
NYMEX HH
 
11.0

 
$
3.32

2016
 
Swap
 
IFNPCR
 
7.3

 
$
3.02

 
 
 
 
 
 
 
 
 
Oil sales
 
 
 
 
 
(Bbls)

 
 

2015
 
Swap
 
NYMEX WTI
 
6.7

 
$
88.49

2015
 
Swap
 
ICE Brent
 
0.3

 
$
104.95

2016
 
Swap
 
NYMEX WTI
 
0.4

 
$
90.00


QEP Energy Crude Oil Sales Costless Collars
 
 


Total Volume

Average Price

Average Price
Year
 
Index

Bbls

Floor

Ceiling
 
 


(in millions)




2015
 
NYMEX WTI

0.4


$
50.00


$
63.83


QEP Energy Gas Sales Basis Swaps
Year
 
Index
 
Index Less Differential
 
Total Volumes
MMBtu
 
Weighted Average Differential
Gas basis swaps
 
 
 
 
 
(in millions)
 
 
2015
 
NYMEX HH
 
IFNPCR
 
27.5

 
$
0.30



QEP Marketing Commodity Derivative Positions
Year
 
Type of Contract
 
Index
 
Total
Volumes
 
Average price
per MMBtu
 
 
 
 
 
 
(in millions)
 
 
Gas sales
 
 
 
 
 
(MMBtu)

 
 
2015
 
Swap
 
IFNPCR
 
1.9

 
$
3.57

2016
 
Swap
 
IFNPCR
 
1.4

 
$
3.34

 
 
 
 
 
 
 
 
 
Gas purchases
 
 
 
 
 
(MMBtu)

 
 

2015
 
Swap
 
IFNPCR
 
1.1

 
$
2.97



17