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WHere INNOVATION FuelS PROGRESS
annual report 2012
QEP Resources, Inc. (NYSE:QEP), is a leading independent
energy company focused on the exploration, production,
gathering, processing and marketing of natural gas, natural
gas liquids and crude oil in the continental United States.
QEP is actively involved in several of North America’s most
prolific resource plays. QEP has a large inventory of identified
development drilling locations, primarily in the Williston
Basin in North Dakota; the Pinedale Anticline in western
Wyoming; the Haynesville/Cotton Valley plays in north-
western Louisiana; the Uinta Basin in eastern Utah; the
Anadarko Basin in Oklahoma and Texas; and other proven
properties in the Rockies and Midcontinent. At the end of
2012, QEP had estimated proved reserves of 3,936 Bcfe.
Headquartered in Denver, Colorado, QEP employs more than
900 people in eight states and is an S&P 500 Index member.
QEP Resources, Inc. – p.1
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QEP has a track record of
strong production growth.
319
275
229
171
190
140
Annual Production (in Bcfe/yr)
2007
2008
2009
2010
2011
2012
2012 SCORECARD
Maximize our Health, Safety, and Environmental (HSE) performance
through an increased focus on our HSE organization, policies, standards,
systems, performance measurements and reporting
Actual = Improvements in Total Recordable Incident Rate (TRIR), Vehicle
Incident Rate (VIR) and Spill Rate
Generate $1.4 billion of QEP Resources Adjusted EBITDA
Actual = $1.4 billion of Adjusted EBITDA
Grow production to 307 Bcfe with $1.2 billion of E&P CAPEX
Production of 319 Bcfe with $1.3 billion of E&P CAPEX, excluding
acquisitions
Increase liquids production to over 20% of total net production, up from
14% in 2011
Liquids comprised 22% of total net production
Achieve QEP Field Services Adjusted EBITDA of at least $320 million
X
Actual: $281 million of Adjusted EBITDA. Despite a strong operational
year, Field Services’ Adjusted EBITDA fell short of its goal due primarily to
weak NGL prices.
QEP Resources, Inc. – p.3
3.9Tcfe
2012 Proved Reserves
33 %
Liquids in Proved Reserves
$1.4 B
2012 Adjusted EBITDA
We are active in several
of North America’s most
economic resource plays.
1
2
3
Northern Region
(above line)
Southern Reg ion
(below line)
4
5
2012 Reserves:
3,936 (Bcfe)
2012 Production:
319 (Bcfe)
2 ,87 6
1 ,0 60
1 58
1 61
2012 Proved Reserves
PROPELLING FUTUR E ORGANIC GROW TH
Northern Region
Bcfe % Liquids
1 - Williston Basin
2 - Pinedale
3 - Uinta Basin
- Legacy (other
Northern Region)
Southern Region
4 - Midcontinent
5 - Haynesville/
Cotton Valley
615
1,531
618
112
530
531
92%
23%
33%
18%
33%
0%
QEP Energy operates in two core regions—the Northern Region
(primarily in the Rockies and the Williston Basin) and the
Southern Region (primarily Louisiana, Oklahoma and the Texas
Panhandle). The Northern Region contributed 49% of 2012
production while the Southern Region contributed 51%. QEP
Energy reported 3,936 Bcfe of estimated proved reserves at
December 31, 2012, up from 3,614 Bcfe at the end of 2011.
Approximately 54% of the proved reserves reported by QEP
Energy at year end 2012 were developed. Approximately 33% of
the estimated proved reserves at December 31, 2012, were com-
prised of crude oil and NGL, up from 24% at December 31, 2011.
QEP Resources, Inc. – p.4
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We acquired an additional
125 MMBOE of estimated proved
and probable reserves in the
Williston Basin of North Dakota.
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AN INCREASE IN QEP’S WILLISTON INVENTORY
During the third quarter of 2012, QEP Energy acquired oil and
gas properties in the Williston Basin of North Dakota for an
aggregate purchase price of $1.4 billion. The acquisition added
properties prospective for both Bakken and Three Forks forma-
tion development. The properties consist of approximately
27,600 net acres of producing and undeveloped oil and gas
leases within the Williston Basin, adding approximately 125
million barrels of oil equivalent proved and probable reserves
(estimated at time of closing) to QEP’s inventory and bringing
total Williston Basin acreage to approximately 117,000 net acres.
$1.4 B
Purchase Price
125 M MBOE
Estimated Proved
and Probable Reserves
90 %
Crude Oil and NGL
Ownership and control of
midstream assets is integral
to value maximization.
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$320
$281
$170
$163
$204
$113
Adjusted EBITDA ($MM/yr)
2007
2008
2009
2010
2011
2012
FIELD SERVICES ASSETS ARE CONCENTR ATED
QEP owns midstream (gathering, processing and treating)
assets to complement its exploration and production operations
in most of the regions where QEP Energy has production.
Through ownership and operation of these assets, QEP is able
to better manage the timing and costs associated with bringing
on new production and to enhance the value received for its
products by gathering, processing and treating the Company’s
production. In addition, QEP’s midstream business also
provides midstream services to third-party customers, including
major and independent producers. QEP generates revenues
from its midstream activities through a variety of agreements,
including fee-based gathering and both fee-based and keep-
whole processing agreements. QEP Field Services assets include
more than 2,000 miles of gathering lines and natural gas
processing capacity of 1.37 Bcfd.
QEP Resources, Inc. – p.9
$171 M
2012 Capital Investment
1.37Bcfd
Processing Capacity
2,000
Miles of Gathering Lines
Fellow Shareholders,
For QEP Resources, 2012 was truly a transformative year filled
with many significant accomplishments. We posted record
Adjusted EBITDA of $1.4 billion on record production of 319
Bcfe, and ended 2012 with record estimated proved reserves of
3.9 Tcfe. More important, we continued to successfully execute
on our multi-year strategy to rebalance our production mix
away from our sizeable exposure to natural gas. Even before our
debut as a standalone public company in July 2010, we had
already begun implementing a strategy to be more than just a
leading low-cost developer and producer of natural gas.
In 2007, our predecessor company generated annual Adjusted
EBITDA of $891 million, with 82% of revenues derived from
the sale of natural gas. In 2007, the NYMEX natural gas price
averaged $6.97 per MMBtu. Despite these strong natural gas
prices and a vibrant and growing business, we made a deliberate
decision in 2007 to diversify away from our exposure to natural
gas. By the end of 2008, we had built an 87,000-net-acre explor-
atory leasehold position in what was to become the largest new
source of crude oil production in the United States in decades:
North Dakota’s Williston Basin.
Our diversification strategy began to show results in 2010 as the
average annual natural gas price declined to $4.37 per MMBtu.
Even in this depressed natural gas price environment we were
able to deliver annual Adjusted EBITDA of $1.1 billion, a 28%
increase over 2007. Through successful delineation drilling, we
substantially de-risked our Williston Basin acreage, while Field
Services embarked upon a major program to expand our mid-
stream business through the construction of new gathering and
processing facilities.
Thanks to the ongoing, successful development of our Williston
Basin acreage—and a company-record $1.4 billion acquisition of
properties in the Williston Basin, which closed on September 27,
2012—liquids production jumped to 22% of total production
in 2012 and was at 27% in the fourth quarter of 2012. The suc-
cess of this diversification is also evident in our financial results.
Despite record Adjusted EBITDA of $1.4 billion, only 39% of
QEP Resources’ 2012 operating revenues were derived from the
sale of natural gas.
QEP Energy
QEP Energy’s net production was a record 319 Bcfe in 2012, a
16% increase over 2011 volumes. Segment Adjusted EBITDA
was a record $1.1 billion in 2012, a 7% increase from 2011,
despite a 15% decrease in net realized natural gas prices and a
24% decrease in net realized NGL prices. The decline in natural
gas and NGL prices was more than offset by growth in combined
crude oil and NGL production, up 81% from 2011. Our
commodity price risk-management program also performed as
designed. Settled commodity derivatives added $366 million to
our 2012 Adjusted EBITDA.
QEP Energy’s 2012 year-end estimated proved reserves increased
to 3.9 Tcfe, up 9% from 2011 levels. Crude oil and NGL reserves
grew by 52% in 2012 compared to 2011 and now represent 33%
of proved reserves, up from 24% in 2011. Despite a 33% decline in
the natural gas price used to calculate 2012 year-end estimated
proved reserves, our negative price-related reserve revisions were
among the lowest in the industry and serve as a testament to the
quality of QEP Energy’s reserve base.
During the third quarter of 2012, QEP Energy closed on its
Williston Basin acquisition adding approximately 125 million
barrels of crude oil equivalent to its proved and probable reserves.
These properties, combined with QEP’s existing acreage in
North Dakota, will serve as the foundation for QEP’s crude oil
production growth for the next several years.
QEP Field Services
Field Services had a very successful year operationally with record
gathering and processing volumes, but lower NGL prices nega-
tively impacted financial results. Adjusted EBITDA for Field
Services declined to $281 million in 2012, down from a record
$320 million in 2011. Field Services’ fee-based processing revenues
increased 40% from 2011 due to higher processing volumes and
per-unit revenue reflecting a full year of operation at our Blacks
Fork II cryogenic gas processing plant and an overall strategic shift
toward fee-based processing arrangements. Gathering volume
and unit revenue both increased slightly from the prior year.
During 2012, Field Services began construction on the 150
MMcfd Iron Horse II cryogenic gas processing plant in the
Uinta Basin of eastern Utah. The plant, which was completed
and operational in February 2013, is contracted under long-term,
fee-based processing agreements. In southwest Wyoming, Field
Services also began construction of a 10,000-barrel-per-day
expansion of the fractionation facilities at our Blacks Fork
processing complex. When complete in mid-2013, fractionation
capacity at Blacks Fork will total 15,000 barrels per day. To sup-
port the expansion, QEP is doubling the existing railcar-loading
capacity at Blacks Fork to facilitate access to what are often
higher-value local, regional and national NGL markets.
QEP Resources, Inc. – p.10
32%*
22
33%
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14
14
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09
08
% Liquids of Total Net Production
2007
2008
2009
2010
2011
2012
2013F
*Forecast
% Liquids of Total Proved Reserves
2009
2010
2007
2011
2008
2012
Looking ahead to 2013 and beyond…
As we look forward to 2013 and beyond, the future of QEP is
bright. We’ve successfully executed on our strategy to rebalance
our production mix away from one dominated by natural gas.
With our existing assets and recent acquisitions in North Dakota’s
Williston Basin, we have built a solid asset base and inventory of
future development locations to grow crude oil production in
2013 and beyond. The search continues for additional organic
growth opportunities and bolt-on acquisitions to broaden and
deepen that inventory. While the focus of this letter and our
efforts of late have been decidedly directed toward growing crude
oil production, QEP remains one of the lowest cost, most efficient
developers and producers of natural gas in North America. We
have a deep, high-quality inventory of natural gas development
locations in world-class assets like the Pinedale Anticline, the
Uinta Basin, and the Cana and Haynesville shale plays.
As I write this letter, North American natural gas markets remain
oversupplied, but there are signs that the situation is improving.
In response to declining gas-directed drilling activity, North
American natural gas production appears to have finally
plateaued, and in some dry gas plays, production is in decline.
While the decline in NGL prices appears to have dampened the
industry’s enthusiasm for many of the marginal liquids-rich gas
plays, demand for natural gas continues to grow. Natural gas
consumption in the electric power generation sector set new
records in 2012, thanks in part to very competitive natural gas
prices but also due to the inherent environmental advantages of
natural gas over competing fossil fuels. Industrial demand is
headed up too, as energy-intensive businesses from petrochemi-
cals to steel announce plans to build new facilities to take
advantage of clean, abundant U.S. natural gas. Finally, natural
gas is also making inroads into the transportation sector, as
vehicle owners and operators are attracted to the compelling
economics and environmental advantages of natural gas over
liquid fuels in trucks, buses and cars.
So while we focus on driving growth in crude oil production in
the near term—with some of the best gas assets in North
America and a track record of low-cost leadership in drilling,
completion and production—QEP is well positioned to benefit
from increased natural gas demand both now and in the future.
In conclusion
For QEP Resources, 2012 was a pivotal year. Our deep portfolio
of upstream and midstream projects is managed by some of the
most creative, innovative and hardest working women and men
in our industry. We maintain a corporate culture that is focused
on safe and reliable operations, on minimizing our impact on the
environment, and on giving back to the communities in which
we live and work. We all have a constant focus on enhancing
long-term shareholder value by continuing to be a best-in-class
low-cost producer, by focusing our investments on the highest
return projects in our portfolio and by maximizing the value of
our production. We run our business with a financial discipline
designed to ensure that we can withstand commodity price
volatility and take advantage of opportunities as they arise. I am
proud of what we have accomplished. And I am excited about
where we are headed!
On behalf of QEP’s board of directors, management and
dedicated employees, thank you for your investment in our
company. We manage this business for you, and we come to
work every day mindful of the trust that you place in us when
you buy QEP shares.
Sincerely,
Charles B. Stanley
Chairman, President and Chief Executive Officer
QEP Resources, Inc. – p.11
2013 Goals
Maximize our Health, Safety, and Environmental (HSE) performance through an increased focus
on our HSE organization, policies, standards, systems, performance measurements and reporting
Generate $1.57 billion of QEP Resources Adjusted EBITDA
Increase crude oil production by at least 65% from 2012 levels
QEP Resources
Financial Highlights (dollars in millions)
Adjusted EBITDA*
Total Assets
Capital Expenditures
Long-term Debt
Total Equity
Total Capitalization
% Debt to Total Capitalization
Debt to Adjusted EBITDA
Production (Bcfe)
Proved Reserves (Bcfe)
% Reserve Liquids
2010
2011
2012
$ 1,141
$ 1,387
$ 1,416
6,785
1,469
1,531
3,063
4,594
7,443
1,431
1,679
3,352
5,032
9,109
2,800
3,207
3,314
6,521
33%
1.3x
33%
1.2x
49%
2.3x
229
3,031
275
3,614
319
3,936
14%
24%
33%
* Adjusted EBITDA is a non-GAAP financial measure. Refer to Item 7 of Part II of the Form 10-K included in this Annual Report 2012 for management’s definition and a
reconciliation to net income of this non-GAAP financial measure.
QEP Resources, Inc. – p.12
FORM 10–K
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2012
001-34778
(Commission File No.)
QEP RESOURCES, INC.
(Exact name of registrant as specified in its charter)
STATE OF DELAWARE
(State or other jurisdiction of incorporation)
87-0287750
(I.R.S. Employer Identification No.)
1050 17th Street, Suite 500, Denver, Colorado 80265
(Address of principal executive offices)
Registrant's telephone number, including area code: 303-672-6900
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common stock, $0.01 par value
Name of each exchange on which registered
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes
No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the
Act. Yes
No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes
No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every
Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such
files). Yes
No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and
will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this Form 10-K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a
smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in
Rule 12b-2 of the Exchange Act.
Large accelerated filer
Accelerated filer
Non-accelerated filer
(Do not check if a smaller reporting company)
Smaller reporting company
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes
No
State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to
the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last
business day of the registrant's most recently completed second fiscal quarter (June 30, 2012): $5,327,744,063.
At January 31, 2013, there were 178,551,744 shares of the registrant's $0.01 par value common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Part III is incorporated by reference from the registrant's Definitive Proxy Statement for its 2013 Annual Meeting of
Stockholders to be filed, pursuant to Regulation 14A, no later than 120 days after the close of the registrant's fiscal year.
TABLE OF CONTENTS
PART I
Where You Can Find More Information
Forward-Looking Statements
Glossary of Terms
ITEM 1. BUSINESS
Nature of Business
Exploration and Production - QEP Energy Company
Midstream Field Services - QEP Field Services Company
Energy Marketing - QEP Marketing Company
Government Regulations
Employees
Executive Officers of the Registrant
ITEM 1A. RISK FACTORS
ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 2. PROPERTIES
Exploration and Production - QEP Energy
Midstream Field Services - QEP Field Services
Energy Marketing - QEP Marketing
ITEM 3. LEGAL PROCEEDINGS
ITEM 4. MINE SAFETY DISCLOSURES
Page
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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
38
ISSUER PURCHASES OF EQUITY SECURITIES
ITEM 6. SELECTED FINANCIAL DATA
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
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OPERATIONS
PART II
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9B. OTHER INFORMATION
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICIERS AND CORPORATE GOVERNANCE
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
PART IV
ITEM 15. EXHIBITS AND FINANCIALS STATEMENT SCEHDULES
SIGNATURES
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1
Where You Can Find More Information
QEP Resources, Inc. (QEP or the Company) files annual, quarterly, and current reports with the Securities and Exchange
Commission (SEC). Prior to QEP's Spin-off from Questar Corporation (described in more detail in Item 1 of Part I of this
Annual Report on Form 10-K), QEP's predecessor, Questar Market Resources, Inc., filed annual, quarterly and current reports
with the SEC. QEP also regularly files proxy statements and other documents with the SEC. These reports and other
information can be read and copied at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549-0213.
Please call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. The SEC also
maintains an Internet site at http://www.sec.gov that contains reports, proxy and information statements and other information
regarding issuers that file electronically with the SEC, including QEP.
Investors can also access financial and other information via QEP's website at www.qepres.com. QEP makes available, free of
charge through the website, copies of Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on
Form 8-K, and any amendments to such reports and all reports filed by executive officers and directors under Section 16 of the
Exchange Act reporting transactions in QEP securities. Access to these reports is provided as soon as reasonably practical after
such reports are electronically filed with the SEC. Information contained on or connected to QEP's website which is not
directly incorporated by reference into the Company's Annual Report on Form 10-K should not be considered part of this report
or any other filing made with the SEC.
QEP's website also contains copies of charters for various board committees, including the Audit Committee, Corporate
Governance Guidelines and QEP's Business Ethics and Compliance Policy.
Finally, you may request a copy of filings other than an exhibit to a filing unless that exhibit is specifically incorporated by
reference into that filing, at no cost by writing or calling QEP, 1050 17th Street, Suite 500, Denver, CO 80265 (telephone
number: 1-303-672-6900).
Forward-Looking Statements
This Annual Report on Form 10-K contains or incorporates by reference information that includes or is based upon "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 give expectations or forecasts of future events. You
can identify these statements by the fact that they do not relate strictly to historical or current facts. We use words such as
"anticipate," "estimate," "expect," "project," "intend," "plan," "believe," and other words and terms of similar meaning in
connection with a discussion of future operating or financial performance. Forward-looking statements include statements
relating to, among other things:
• QEP's growth strategies;
•
•
•
•
natural gas, oil and NGL prices and factors affecting the volatility of such prices;
plans to drill or participate in wells and to defer completion of wells;
results from planned drilling operations and production operations;
amount and allocation of forecasted capital expenditures and plans for funding capital expenditures and operating
expenses;
plans to divest of assets, including plans to separate portions of gathering assets into a master limited
partnership;
estimated reserves;
estimated accruals for loss contingencies and other items;
impact of lower commodity prices;
effect of recession;
plans to enter into derivative contracts for a portion of forecasted production;
future expenses and operating costs;
the ability to secure long-term gathering, processing and treating contracts from third parties as required to fully
utilize the Company's midstream assets;
operation of the Company's Blacks Fork II and other processing plants at assumed capacities;
the amount and timing of the settlement of derivative contracts;
incurrence of unrealized derivative gains and losses;
the ability of QEP to use derivative instruments to manage commodity price risk and the availability to the Company
of the end-user exemption under Title VII of the Dodd-Frank Act;
impact of nonperformance by trade creditors or joint venture partners;
•
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•
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2
the outcome of contingencies such as legal proceedings;
impact on earnings from discontinuing hedge accounting;
expected contributions to the Company's pension plans;
impact of recently issued accounting pronouncements;
•
•
•
•
• QEP's ability to develop reserves and grow production as necessary to satisfy delivery commitments and our ability
to purchase natural gas, crude oil and NGL in the market to cover any shortfalls;
conversion of proved undeveloped reserves to proved developed reserves;
the significance of Adjusted EBITDA as a measure of cash flow and liquidity;
payment of dividends;
potential for future asset impairments;
estimated future purchase accounting adjustments;
•
•
•
•
•
• maintaining an appropriate debt rating; and
•
future activist efforts.
Any or all forward-looking statements may turn out to be incorrect. They can be affected by inaccurate assumptions or by
known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. These
statements are based on current expectations and the current economic environment. They involve a number of risks and
uncertainties that are difficult to predict. These statements are not guarantees of future performance. Actual results could differ
materially from those expressed or implied in the forward-looking statements. Factors that could cause actual results to differ
materially include, but are not limited to the following:
the outcome of contingencies such as legal proceedings;
permitting delays;
operating risks such as unexpected drilling conditions;
the risk factors discussed in Part I, Item 1A of this Annual Report on Form 10-K;
changes in natural gas, oil and NGL prices;
general economic conditions, including the performance of financial markets and interest rates;
drilling results;
shortages of oilfield equipment, services and personnel;
lack of available pipeline capacity;
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• QEP's inability to successfully integrate acquired assets or dispose of non-core assets;
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• weather conditions;
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changes in maintenance and construction costs, including possible inflationary pressures;
the availability and cost of debt and equity financing;
changes in laws or regulations, including the implementation of the Dodd-Frank Act;
climate change and other initiatives related to drilling and completion techniques, including hydraulic fracturing;
derivative activities;
substantial liabilities from legal proceedings and environmental claims;
failure of internal controls and procedures;
elimination of federal income tax deductions for oil and gas exploration and development costs;
future opportunities that QEP's board of directors may determine present greater potential value to stockholders than
planned divestiture of assets;
regulatory approvals and compliance with contractual obligations;
failure to obtain court approval or class member acceptances of settlement agreement for the Company's class action
lawsuit;
actions, or inaction, by federal, state, local or tribal governments; and
other factors, most of which are beyond the Company's control.
•
•
•
•
QEP undertakes no obligation to publicly correct or update the forward-looking statements in this Annual Report on Form 10-
K, in other documents, or on the website to reflect future events or circumstances. All such statements are expressly qualified
by this cautionary statement.
3
Glossary of Terms
Adjusted EBITDA Adjusted EBITDA is a non-GAAP financial measure. Management defines Adjusted EBITDA as net
income before the following items: separation costs, accrued litigation loss contingency, depreciation, depletion and
amortization, exploration expense, abandonment and impairment, gains and losses from asset sales, unrealized gains and losses
on derivative contracts, interest and other income, loss on early extinguishment of debt, interest expense, income taxes and
discontinued operations.
B Billion.
bbl Barrel, which is equal to 42 U.S. gallons liquid volume and is a common measure of volume of crude oil and other liquid
hydrocarbons.
basis The difference between a reference or benchmark commodity price and the corresponding sales price at various regional
sales points.
basis-only swap A derivative that "swaps" the basis (defined above) between two sales points from a floating price to a fixed
price for a specified commodity volume over a specified time period. Typically used to fix the price relationship between a
geographic sales point and a NYMEX reference price.
Btu One British thermal unit – a measure of the amount of energy required to raise the temperature of a one-pound mass of
water one degree Fahrenheit at sea level.
cf Cubic foot or feet is a common unit of gas measurement. One standard cubic foot equals the volume of gas in one cubic foot
measured at standard conditions – a temperature of 60 degrees Fahrenheit and a pressure of 30 inches of mercury
(approximately 14.7 pounds per square inch).
cfe Cubic foot or feet of natural gas equivalents.
cryogenic processing Utilizes refrigeration by reducing gas pressure across a turbo expander that reduces the gas temperature
to 100 degrees below zero Fahrenheit.
cushion gas Volume of gas that must remain in a natural gas storage facility to provide the required pressure to extract the
stored or working gas volumes.
developed reserves Reserves of any category that can be expected to be recovered through existing wells with existing
equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a
new well. See 17 C.F.R. Section 4-10(a)(6).
development well A well drilled within the proved area of an oil or gas reservoir to the depth of a horizon known to be
productive.
dry hole A well drilled and abandoned and found to be incapable of producing hydrocarbons in sufficient quantities such that
proceeds from the sale of production exceed expenses and taxes.
exploratory well An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found
to be productive of oil or gas in another reservoir.
frac spread The difference between the market value for natural gas liquids (NGL) extracted from the natural gas stream and
the market value of the Btu-equivalent volume of natural gas required to replace the extracted liquids.
gas All references to "gas" in this report refer to natural gas.
gross "Gross" natural gas and crude oil wells or "gross" acres are the total number of wells or acres in which the Company has
a working interest.
IFNPCR Inside the Federal Energy Regulatory Commission (FERC) monthly settlement index for the Northwest Pipeline
Corporation Rocky Mountains.
4
IFPEPL Inside FERC monthly settlement index for the Panhandle Eastern Pipeline Company.
keep-whole processing Processing contracts where the Company retains and sells NGL extracted at its processing plants and
keeps the customer "whole" by buying and delivering a Btu-equivalent amount of natural gas to the customer.
LIBOR London Interbank Offered Rate (LIBOR) is the interest rate that banks charge each other for one-month, three-month,
six-month and one-year loans.
M Thousand.
MM Million.
Midstream Gas gathering, compression, treating, processing, and transmission assets and activities that are non-jurisdictional.
Also includes certain crude oil and produced water gathering systems and related commercial activities.
natural gas equivalents Oil and NGL volumes are converted to natural gas equivalents using the ratio of one barrel of crude
oil, condensate or NGL to 6,000 cubic feet of natural gas.
natural gas liquids (NGL) Liquid hydrocarbons that are extracted from the natural gas stream. NGL products include ethane,
propane, butane, natural gasoline and heavier hydrocarbons.
net "Net" gas and oil wells or "net" acres are determined by the sum of the fractional ownership working interest the Company
has in the gross wells or acres.
NYMEX The New York Mercantile Exchange.
NYMEX WTI The price of West Texas Intermediate crude oil on the New York Mercantile Exchange.
possible reserves Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
probable reserves Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but
which, together with proved reserves, are as likely as not to be recovered.
proved properties Properties with proved reserves.
proved reserves Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and
engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from
known reservoirs, and under existing economic conditions, operating methods, and government regulations. See 17 C.F.R.
Section 4-10(a)(22).
reserves Estimated remaining quantities of natural gas, crude oil and related substances anticipated to be economically
producible by application of development projects to known accumulations. In addition, there must exist, or there must be a
reasonable expectation that there will exist, the legal right to produce. See 17 C.F.R. Section 4-10(a)(26).
reservoir A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or
oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
resource play Refers to regionally distributed oil and natural gas accumulation as opposed to conventional plays which are more
limited in their area extent. Resource plays are characterized by continuous, aerially extensive hydrocarbon accumulations in tight
sand, shale and coal reservoirs.
royalty An interest in a gas and oil lease that gives the owner the right to receive a portion of the production from the leased
acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of
drilling or operating the wells on the leased acreage. Royalties may be either landowner's royalties, which are reserved by the
owner of the minerals at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the
leasehold in connection with a transfer to a subsequent owner.
5
seismic data An exploration method of sending energy waves or sound waves into the earth and recording the wave reflections
to indicate the type, size, shape and depth of a subsurface rock formation. 2-D seismic provides two-dimensional information
and 3-D seismic provides three-dimensional views.
T Trillion.
undeveloped reserves Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or
from existing wells where a relatively major expenditure is required for recompletion. See 17 C.F.R. Section 4-10(a)(31).
working interest An interest in a gas and oil lease that gives the owner the right to drill, produce and conduct operating
activities on the leased acreage and receive a share of any production, subject to all royalties, other burdens and to all capital
costs and operating expenses.
6
FORM 10-K
ANNUAL REPORT 2012
PART I
ITEM 1. BUSINESS
Nature of Business
QEP Resources, Inc. (QEP or the Company), is a holding company with three major lines of business: natural gas and crude oil
exploration and production; midstream field services; and energy marketing. These businesses are conducted through the
Company's three principal subsidiaries:
• QEP Energy Company (QEP Energy) acquires, explores for, develops and produces natural gas, crude oil, and natural
gas liquids (NGL);
• QEP Field Services Company (QEP Field Services) provides midstream field services, including natural gas
gathering, processing, compression and treating services for affiliates and third parties; and
• QEP Marketing Company (QEP Marketing) markets affiliate and third-party natural gas and crude oil, and owns and
operates an underground natural gas storage reservoir.
QEP operates in the Northern and Southern Regions of the United States and is headquartered in Denver, Colorado. Principal
offices are located in Denver, Colorado; Salt Lake City, Utah; and Tulsa, Oklahoma.
Reincorporation Merger and Spin-off from Questar
Effective May 18, 2010, Questar Market Resources Inc. (Market Resources), then a wholly owned, public subsidiary of Questar
Corporation (Questar), merged with and into a newly formed, wholly owned subsidiary, QEP Resources, Inc., a Delaware
corporation, in order to reincorporate in the State of Delaware (Reincorporation Merger). The Reincorporation Merger was
effected pursuant to an Agreement and Plan of Merger entered into between Market Resources and QEP. On June 30, 2010,
Questar distributed all of the shares of common stock of QEP held by Questar to Questar shareholders in a tax-free, pro rata
dividend (the Spin-off). Each Questar shareholder received one share of QEP common stock for each share of Questar common
stock held at the close of business on the record date. In connection with the Spin-off, QEP distributed Wexpro Company
(Wexpro), a wholly owned subsidiary of QEP at the time, to Questar. In addition, Questar contributed $250.0 million of equity
to QEP prior to the Spin-off.
In connection with the reorganization, QEP renamed its subsidiaries as follows:
• QEP Energy Company (formerly Questar Exploration and Production Company);
• QEP Field Services Company (formerly Questar Gas Management Company); and
• QEP Marketing Company (formerly Questar Energy Trading Company).
The financial information presented in this Annual Report on Form 10-K presents QEP's financial results as an independent
company separate from Questar and reflects Wexpro's financial condition and operating results as discontinued operations for
all periods presented. A summary of discontinued operations can be found in Note 13 - Discontinued Operations, to the
consolidated financial statements in Item 8 of Part II this Annual Report on Form 10-K.
Financial and Operating Highlights
Our financial and operating highlights for 2012 include:
• Generated net income of $128.3 million, or $0.72 per diluted share, a decrease of 52%, due primarily to the accrual of
a litigation loss contingency of $115.0 million;
• Generated Adjusted EBITDA (a non-GAAP financial measure defined and reconciled in Item 7 of Part II of this
Annual Report on Form 10-K) of $1,415.5 million, up from $1,386.6 million in 2011;
Increased total production by 16% to 319.2 Bcfe and liquids (oil and NGL) production by 80% to 69.9 Bcfe;
Increased total proved reserves 9% to 3.9 Tcfe and increased liquid (oil and NGL) proved reserves by 52% to 1.3 Tcfe;
•
•
• Added 572.5 Bcfe of proved reserves from extensions and discoveries;
• Acquired $1.4 billion of assets in QEP's existing core acreage in the Williston Basin, North Dakota;
•
Increased Field Services gathering throughput volumes, NGL sales volumes and fee-based processing volumes by 2%,
3% and 4%, respectively; and
7
•
Issued $1.15 billion of senior notes and entered into a $300 million five-year term loan.
Strategies
We create value for our shareholders through returns-focused growth, superior execution, and a low cost structure. To achieve
these objectives we will strive to:
•
operate in a safe and environmentally responsible manner;
•
allocate capital to those projects that generate optimal returns;
•
acquire businesses and assets that complement or expand our current business;
• maintain a sustainable, diverse inventory of low cost, high-margin resource plays;
•
•
•
•
•
be in the highest-potential areas of the resource plays in which we operate;
build contiguous acreage positions that drive operating efficiencies;
be the operator of our assets, whenever possible;
be the low-cost driller and producer in each area where we operate;
own a controlling interest in and operate midstream infrastructure in our core producing areas to capture value
downstream of the wellhead;
build gas processing plants to extract liquids from our natural gas streams;
gather, compress and treat our production to drive down costs;
support the growth of our midstream business with the intention of forming a Master Limited Partnership;
actively market our QEP Energy production to maximize value;
utilize derivative contracts to mitigate the impact of natural gas, crude oil or NGL price volatility, while locking in
acceptable cash flows required to support future capital expenditures;
attract and retain the best people; and
•
• maintain a capital structure that allows us the necessary financial flexibility with which to invest in organic growth and
•
•
•
•
•
potential acquisition opportunities, as they may arise.
Exploration and Production – QEP Energy Company
QEP Energy is actively involved in several of North America's most important hydrocarbon resource plays. QEP Energy has a
large inventory of identified development drilling locations, primarily on the Pinedale Anticline in western Wyoming; the
Williston Basin in North Dakota; the Haynesville/Cotton Valley in northwestern Louisiana; the Uinta Basin in eastern Utah;
Anadarko Basin in Oklahoma and Texas and other proven properties in Wyoming, Colorado and Utah. For 2013, QEP plans to
allocate approximately 91% of its capital budget to QEP Energy. The following map illustrates the location of the Company's
significant exploration and production activities, our Northern and Southern Regions described elsewhere in this report, and
related reserve and production data as of December 31, 2012:
8
QEP's exploration and production activities are conducted through QEP Energy, which generated approximately 80%, 76%,
and 81% of the Company's Adjusted EBITDA (refer to Item 7 of Part II of this Annual Report on Form 10-K for management's
definition and a reconciliation to net income of this non-GAAP financial measure) during the years ended December 31, 2012,
2011 and 2010, respectively. QEP Energy operates in two core regions – the Northern Region (including the states of Wyoming,
Utah, Colorado, New Mexico and North Dakota) and the Southern Region (including the states of Oklahoma, Texas and
Louisiana). The Northern Region contributed 49% of 2012 production while the Southern Region contributed 51%. QEP
Energy reported 3,936 Bcfe of estimated proved reserves as of December 31, 2012, up from 3,614 Bcfe at the end of 2011. Of
those estimated proved reserves, approximately 74%, or 2,876 Bcfe, were located in the Northern Region at December 31,
2012, compared to 64% or 2,312 Bcfe at December 31, 2011. The remaining 26%, or 1,061 Bcfe, were located in the Southern
Region at December 31, 2012, compared to 36% or 1,302 Bcfe at December 31, 2011. Approximately 54% of the proved
reserves reported by QEP Energy at year end 2012 were developed. Approximately 33% of the total proved reserves at
December 31, 2012, were comprised of crude oil and NGL up from 24% at December 31, 2011.
During the third quarter of 2012, QEP Energy acquired oil and gas properties in the Williston Basin for an aggregate purchase
price of $1.4 billion, subject to post-closing adjustments (the 2012 Acquisition). The acquired properties consist of
approximately 27,600 net acres of producing and undeveloped oil and gas properties in the active play area for the Bakken and
Three Forks Formations within the Williston Basin. The acquired properties added 313.8 Bcfe of proved reserves during 2012.
QEP Energy faces competition in every part of its business, including the acquisition of producing leaseholds and wells and
undeveloped leaseholds, the marketing of natural gas and oil, and the procurement of goods, services and labor. Its longer-term
growth strategy depends, in part, on its ability to acquire reasonably-priced acreage containing undeveloped reserves and
identify and develop them in a low-cost and efficient manner.
The Company seeks to acquire, develop and produce natural gas and oil from resource plays in its core areas. Since the
existence and distribution of hydrocarbons in resource plays is well understood, development of these accumulations has lower
risk than conventional discrete hydrocarbon accumulations. Resource plays typically require many wells, drilled at high
density, to fully develop and produce the hydrocarbon accumulations. Development of QEP Energy's resource play
accumulations requires expertise in drilling large numbers of complex, highly deviated or horizontal wells to vertical depths
that generally range between 10,000 and 14,000 feet and the application of advanced well completion techniques, including
hydraulic fracture stimulation, to achieve economic production rates. QEP Energy also continues to conduct some exploratory
drilling to determine the commerciality of its inventory of unproven leaseholds. QEP Energy seeks to maintain geographical
and geological diversity with its two core regions. The Company has in the past and may in the future pursue acquisition of
producing properties through the purchase of assets or corporate entities in order to expand its presence in its core areas or to
create new core areas.
QEP Energy, both directly and through QEP Marketing, sells its natural gas, crude oil and NGL production to a variety of
customers, including gas-marketing firms, industrial users, local-distribution companies, crude oil refiners and remarketers.
QEP Energy regularly evaluates counterparty credit and may require financial guarantees or prepayments from parties that fail
to meet its credit criteria.
Midstream Field Services – QEP Field Services Company
QEP owns midstream (gathering, processing and treating) systems to complement its exploration and production operations in
most of the regions where QEP Energy has production. Through ownership and operation of these facilities, QEP is able to
better manage the timing and costs associated with bringing on new production and enhance the value received for its products
by gathering, processing and treating the Company's production. In addition, QEP's midstream business also provides
midstream services to third-party customers, including major and independent producers. QEP generates revenues from its
midstream activities through a variety of agreements including fee-based gathering, processing and keep-whole processing
agreements. For 2013, QEP plans to allocate approximately 7% if its capital budget to QEP Field Services to grow its
midstream business, including completing the construction of its gathering system in the Uinta Basin as well as the 10,000 Bbl/
d expansion of the NGL fractionator located at the Blacks Fork processing complex (expected to be completed in the second
half of 2013).
The following map illustrates QEP Field Services' areas of operations and the locations corresponding with QEP Energy's
operating areas:
9
QEP Field Services generated approximately 20%, 23% and 18% of the Company's Adjusted EBITDA (refer to Item 7 of Part
II of this Annual Report on Form 10-K for management's definition and a reconciliation to net income of this non-GAAP
financial measure) in the years ended December 31, 2012, 2011 and 2010, respectively. QEP Field Services owns various
natural gas gathering, treating and processing facilities in the Northern and Southern Regions as well as 78% of Rendezvous
Gas Services, LLC (RGS), a partnership that operates gas gathering facilities in western Wyoming. RGS gathers natural gas for
the Pinedale Anticline and the Jonah Field producers for delivery to various interstate pipelines. QEP Field Services also owns
38% of Uintah Basin Field Services, LLC (UBFS) and 50% of Three Rivers Gathering, LLC (Three Rivers). These two
partnerships operate natural gas gathering facilities in eastern Utah. The Rendezvous Pipeline Co., LLC (Rendezvous Pipeline),
a wholly owned subsidiary of QEP Field Services, operates a Federal Energy Regulatory Commission (FERC) regulated, 21-
mile, 20-inch-diameter gas transmission pipeline between QEP Field Services' Blacks Fork gas processing plant and the Muddy
Creek compressor station owned by Kern River Gas Transmission Co. (Kern River Pipeline).
Fee-based gathering and processing revenues represented 77%, 70% and 78% of QEP Field Services' net operating revenues
(revenues less plant shrink and transportation costs) during the years ended December 31, 2012, 2011 and 2010, respectively.
Approximately 41%, 35%, and 36% of QEP Field Services' 2012, 2011 and 2010 net gas processing revenues (processing
revenues less plant shrink) were derived from fee-based processing agreements. The remaining revenues were derived from
keep-whole processing agreements. A keep-whole contract exposes QEP Field Services to frac-spread risk while a fee-based
contract eliminates direct commodity price exposure. To further reduce volatility associated with keep-whole contracts, QEP
Field Services may enter into forward-sales contracts for NGL or NGL price derivatives and equivalent gas volume derivatives
with the intent to lock in a processing margin.
QEP Field Services faces regional competition with varying competitive factors in each basin. QEP Field Services' gathering
and processing business competes with interstate and intrastate pipelines, producers and independent gatherers and processors.
Numerous factors impact a customer's choice of a gathering or processing service provider, including rate, location, term,
pressure obligations, timeliness of services, and contract structure. QEP Field Services provides natural gas gathering,
processing and treating services to affiliates and third-party producers who own producing natural gas fields in the Rocky
Mountain region, the Williston Basin and in northwest Louisiana. In addition to its natural gas operations, QEP Field Services
also provides crude oil and water gathering and handling to affiliates and third-party producers in the Rocky Mountain region
and the Williston Basin. QEP Field Services' gas gathering, processing and treating services are generally provided under long-
term agreements.
10
Energy Marketing—QEP Marketing Company
QEP Marketing provides wholesale marketing and sales of affiliate and third-party natural gas, oil and NGL and generated less
than 1% of the Company's Adjusted EBITDA (refer to Item 7 of Part II of this Annual Report on Form 10-K for management's
definition and a reconciliation to net income of this non-GAAP financial measure) in all of the years ended December 31, 2012,
2011 and 2010. As a wholesale marketing entity, QEP Marketing concentrates on markets in the Rocky Mountains and
Midcontinent that are either close to affiliate reserves and production or accessible by major pipelines. QEP Marketing
contracts for firm-transportation capacity on pipelines and firm-storage capacity at Clay Basin, a large storage facility in
northeast Utah.
QEP Marketing, through its wholly owned subsidiary Clear Creek Storage Company, LLC, (Clear Creek) owns and operates an
underground gas-storage reservoir in southwestern Wyoming. QEP Marketing uses owned and leased storage capacity together
with firm-transportation capacity to manage seasonal swings in prices in the Rocky Mountain region.
QEP Marketing competes directly with large independent energy marketers, marketing affiliates of regulated pipelines and
utilities and natural gas producers. QEP Marketing also competes with brokerage houses, energy hedge funds and other energy-
based companies offering similar services. QEP Marketing sells QEP Energy's natural gas and volumes purchased from third
parties to wholesale marketers, industrial end-users and utilities. QEP Marketing sells QEP Energy's crude oil volume to
refiners, remarketers and other companies, including some with pipeline facilities near company producing properties. QEP
Marketing sells NGL volumes from its Clear Creek storage facility to a refiner. In the event pipeline facilities are not available,
QEP Marketing arranges transportation of crude oil by truck or rail to storage, refining or pipeline facilities.
Government Regulation
QEP's business operations are subject to regulation under a wide range of local, state, tribal and federal statutes, rules, orders
and regulations. The regulatory burden on the oil and gas industry increases the cost of doing business and consequently affects
its profitability. While QEP believes that it is in substantial compliance with currently applicable laws and regulations and has
not experienced any material adverse effect arising from these requirements, there is no assurance that this trend will continue
in the future. Due to the myriad of complex federal, state, tribal and local regulations that may affect the Company, directly or
indirectly, the following discussion of certain laws and regulations should not be considered an exhaustive review of all
regulatory considerations affecting QEP's operations. See additional discussion of regulations under Item 1A - Risk Factors, in
this Annual Report on Form 10-K.
Regulation of Exploration, Production, Gathering and Processing Activities
The regulation of oil and gas exploration and production is a broad and increasingly complex area, notably including laws and
regulations governing the discharge or release of materials into the environment or otherwise relating to environmental
protection. These laws and regulations include the following:
Clean Air Act. The Clean Air Act and similar state laws regulate the emission of air pollutants from equipment and facilities
employed by QEP Energy in its business, including but not limited to engines, tanks, dehydrators and gas processing plant
components.
Greenhouse Gases Regulations and Climate Change Legislation. The Environmental Protection Agency (EPA) published its
findings that emissions of carbon dioxide, methane, and other greenhouse gases (GHG) present an endangerment to public
health and the environment because such emissions are, according to the EPA, contributing to the warming of the earth's
atmosphere and other climate changes. Based on these findings, the EPA adopted regulations for the measurement and reporting
of GHG emitted from certain large facilities. In November 2010, the EPA expanded its GHG Reporting Rule to include onshore
oil and natural gas production, processing, transmission, storage, and distribution facilities. This rule requires reporting of GHG
emissions from such facilities on an annual basis. In addition, both houses of Congress have considered legislation in recent
years to reduce emissions of GHG, and a number of states have already taken legal measures to reduce emissions of GHG,
primarily through the development of GHG inventories, greenhouse gas permitting and/or regional GHG cap and trade
programs.
Clean Water Act and Safe Drinking Water Act. The Clean Water Act and similar state laws regulate discharges of wastewater,
oil, and other pollutants to surface water bodies, such as lakes, rivers, wetlands, and streams, as well as discharges to storm
water. These laws also require the preparation and implementation of Spill Prevention, Control, and Countermeasure Plans in
connection with on-site storage of significant quantities of oil. The Safe Drinking Water Act (SDWA) and comparable state
statutes restrict the disposal, treatment or release of water produced or used during oil and gas development.
11
Oil Pollution Act of 1990. The Oil Pollution Act of 1990 (OPA) and regulations issued under OPA impose strict, joint and
several liability on "responsible parties" for removal costs and damages resulting from oil spills into or upon navigable waters,
adjoining shorelines or in the exclusive economic zone of the United States.
Comprehensive Environmental Response, Compensation and Liability Act of 1980. The Comprehensive Environmental
Response, Compensation and Liability Act of 1980 (CERCLA or Superfund) and comparable state laws impose liability,
without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a
"hazardous substance" into the environment.
Resource Conservation and Recovery Act. The Resource Conservation and Recovery Act (RCRA) is the principal federal statute
governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements and liability
for failure to meet such requirements on a person who is either a "generator" or "transporter" of hazardous waste or on an "owner"
or "operator" of a hazardous waste treatment, storage or disposal facility. RCRA and many state counterparts specifically exclude
from the definition of hazardous waste "drilling fluids, produced waters, and other wastes associated with the exploration,
development, or production of crude oil, natural gas or geothermal energy." It is possible, however, that certain exploration and
production wastes now classified as non-hazardous could be classified as hazardous waste in the future. Any repeal or modification
of the oil and gas exploration and production exemption would increase the volume of hazardous waste QEP is required to manage
and dispose of, and would cause QEP, as well as its competitors, to incur increased operating expenses.
Hydraulic Fracturing Regulations. All wells drilled in tight sand and shale reservoirs require hydraulic fracture stimulation to
achieve economic production rates and recoverable reserves. The majority of the Company's current and future production and
oil and gas reserves are derived from reservoirs that require hydraulic fracture stimulation to be commercially viable. Hydraulic
fracture stimulation involves pumping fluid at high pressure into tight sand or shale reservoirs to artificially induce fractures.
The artificially induced fractures allow better connection between the wellbore and the surrounding reservoir rock, thereby
enhancing the productive capacity and ultimate hydrocarbon recovery of each well. The fracture stimulation fluid is typically
comprised of over 99% water and sand, with the remaining constituents consisting of chemical additives designed to optimize
the fracture stimulation treatment and production from the reservoir. The Company does not use diesel fuel in any of its
fracturing operations. The Company supports disclosure of the contents of hydraulic fracturing fluids, and submits information
regarding its wells and the fluids used in them to the national online disclosure registry, FracFocus (www.fracfocus.org).
The Company obtains water for fracture stimulations from a variety of sources including industrial water wells and surface
water sources. When technically and economically feasible, the Company recycles flow-back and produced water, which
reduces water consumption from surface and groundwater sources and reduces produced water disposal volumes. The
Company believes that the employment of fracture stimulation technology does not present any significant additional risks
other than the risks generally associated with natural gas and oil drilling and production operations, such as the risk of spills,
releases, discharges, accidents and injuries to persons and property.
Currently, all well construction activities, including hydraulic fracture stimulation, are regulated by state agencies that review
and approve all aspects of natural gas and oil well design and operation. Additionally, the Bureau of Land Management (BLM)
proposed in May 2012 new regulations regarding chemical disclosure requirements and other regulations specific to well
stimulation activities, including hydraulic fracturing, on federal and tribal land. There has been a heightened debate recently
over whether the fluids used in hydraulic fracturing may contaminate drinking water supplies, and proposals have been made to
revisit the environmental exemption for hydraulic fracturing under the SDWA or to enact separate federal legislation or
legislation at the state and local government levels that would regulate hydraulic fracturing.
The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing
practices and a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the
potential environmental effects of hydraulic fracturing on drinking water and groundwater, with final results expected to be
available by 2014. Moreover, the EPA announced in October 2011 that it is also launching a study regarding wastewater
resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet
before being transported to a publicly owned treatment plant. In addition, the Department of Energy is conducting an
investigation of practices the agency could recommend to better protect the environment from drilling employing hydraulic
fracture stimulation.
Additionally, a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing
practices, and recent Congressional legislative efforts seek to regulate hydraulic fracturing under the SDWA's Underground
Injection Control program, which would significantly increase well capital costs. Certain members of Congress have also called
upon (1) the Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources;
(2) the Securities and Exchange Commission (SEC) to investigate the natural gas industry and any possible misleading of
12
investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic
fracturing; and (3) the Energy Information Administration to provide a better understanding of that agency's estimates
regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those
estimates. Air quality impacts from hydraulic fracturing practices are also being studied currently by various federal and state
agencies. These various ongoing or proposed studies and investigations, depending on their degree of pursuit and any
meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA, the Clean Air Act
or other statutes and regulatory programs. The Company supports disclosure of the contents of hydraulic fracturing fluids, and
submits information regarding its wells to the national online disclosure registry, FracFocus (www.fracfocus.org).
Tribal Lands and Minerals. Various federal agencies within the U.S. Department of the Interior, particularly the BLM and the
Bureau of Indian Affairs, along with certain Native American tribes, promulgate and enforce regulations pertaining to natural
gas and oil operations on Native American tribal lands on which QEP Energy operates. These regulations include such matters
as lease provisions, drilling and production requirements, environmental standards and royalty considerations.
Endangered Species Act, National Environmental Policy Act. The Endangered Species Act restricts activities that may affect
federally identified endangered and threatened species or their habitats through the implementation of operating restrictions or
a temporary, seasonal, or permanent ban in affected areas. Many of QEP's operations are subject to the requirements of the
National Environmental Policy Act (NEPA), and are therefore evaluated under NEPA for their direct, indirect and cumulative
environmental impacts. This is done in Environmental Assessments or Environmental Impact Statements prepared for a lead
agency under the Council on Environmental Quality and other agency regulations, usually for the BLM in the areas where QEP
operates currently.
Emergency Planning and Community Right-to-Know Act and Occupational Safety and Health Act. The Emergency Planning
and Community Right-to-Know Act (EPCRA) requires facilities to disseminate information on chemical inventories to
employees as well as local emergency planning committees and emergency response departments. The Non-Government
Organization Environmental Integrity Project has filed a petition for rulemaking with the EPA under the EPCRA and the federal
Administrative Procedure Act to add the "Oil and Gas Extraction Industry" to the list of industries required to report releases of
certain "toxic chemicals" under EPCRA's Toxics Release Inventory (TRI) program. The federal Occupational Safety and
Health Act establishes workplace standards for the protection of the health and safety of employees, including the
implementation of hazard communication programs designed to inform employees about hazardous substances in the
workplace, potential harmful effects of these substances, and appropriate control measures.
Dodd-Frank Wall Street Reform and Consumer Protection Act. The Dodd-Frank Wall Street Reform and Consumer
Protection Act (Dodd-Frank Act) was passed by Congress and signed into law in July 2010. The Dodd-Frank Act is designed to
provide a comprehensive framework for the regulation of the over-the-counter derivatives market with the intent to provide
greater transparency and reduction of risk between counterparties. The Dodd-Frank Act subjects swap dealers and major swap
participants to capital and margin requirements and requires many derivative transactions to be cleared on exchanges. The
Dodd-Frank Act provides for a potential exemption from these clearing and cash collateral requirements for commercial end-
users. In addition, in August 2012, the SEC issued a final rule under Section 1504 of the Dodd-Frank Act, Disclosure of
Payments by Resource Extraction Issuers, which requires resource extraction issuers, such as QEP, to file annual reports that
provide information about the type and total amount of payments made for each project related to the commercial development
of oil, natural gas, or minerals to each foreign government and the federal government.
Regulation of Transportation and Sales of Natural Gas
Natural Gas Act of 1938, Natural Gas Policy Act of 1978 and Energy Policy Act of 2005. The FERC regulates the
transportation and sale for resale, of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 and the Natural
Gas Policy Act of 1978 and regulations issued under those Acts.
Other Regulations. QEP Field Services' construction and operation activities are subject to various local, state, federal and
tribal rules and regulations. Most of these rules and regulations are administered by the Department of Transportation, the
Occupational Safety and Health Administration, and the EPA.
Regulation of Transportation of Crude Oil by Pipeline
The Interstate Commerce Act (ICA), as applied to liquids pipelines, requires that rates and terms of service be just and
reasonable and non-discriminatory. Under the ICA, FERC regulates the rates and terms and conditions of service for interstate
movements of crude oil, natural gas liquids and refined petroleum products.
13
Regulation of Underground Storage
QEP through Clear Creek Storage Company, LLC, operates an underground gas-storage facility under the jurisdiction of the
FERC. The FERC establishes rates for the storage of natural gas. The FERC also regulates, among other things, the extension
and enlargement or abandonment of jurisdictional natural gas facilities. Regulation is intended to permit the recovery, through
rates, of the cost of service, including a return on investment.
Significant Customers
The Company's five largest customers accounted for 37%, 32%, and 27% in aggregate, of QEP revenues during the years ended
December 31, 2012, 2011 and 2010, respectively. During the year ended December 31, 2012, Chevron U.S.A. Inc. and
Enterprise Products Operating, L.P. accounted for 13% and 10%, respectively, of the Company's total revenues. Management
believes that the loss of either customer, or any other customer, would not have a material effect on the financial position or
results of operations of QEP, since there are numerous potential purchasers of its production. During the years ended December
31, 2011 and 2010, each of the five largest customers sales were below 10% of QEP's total revenues.
Employees
At December 31, 2012, QEP Resources, Inc. had 936 employees compared to 876 employees at December 31, 2011. None of
QEP's employees are represented by unions or covered by collective bargaining agreements.
Executive Officers of the Registrant
The name, age, period of service, title and business experience of each of QEP's executive officers as of February 19, 2013, are
listed below:
Charles B. Stanley
Richard J. Doleshek
Jay B. Neese
Austin S. Murr
Perry H. Richards
Jim E. Torgerson
Abigail L. Jones
Christopher K.
Woosley
Margo Fiala
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54
54
59
52
49
52
43
49
Chairman (2012 to present), President, and Chief Executive Officer, QEP (2010 to
present). Previous titles with Questar: Chief Operating Officer (2008 to 2010);
Executive Vice President and Director (2003 to 2010); President, Chief Executive
Officer and Director, Market Resources and Market Resources subsidiaries (2002 to
2010).
Executive Vice President, Chief Financial Officer, and Treasurer QEP (2010 to
present). Previous titles with Questar: Executive Vice President and Chief Financial
Officer (2009 to 2010). Prior to joining Questar, Mr. Doleshek was Executive Vice
President and Chief Financial Officer, Hilcorp Energy Company (2001 to 2009).
Executive Vice President, QEP (2010 to present). Previous titles with Questar: Senior
Vice President (2005 to 2010); Executive Vice President, Market Resources and
Market Resources subsidiaries (2005 to 2010); Vice President, Market Resources and
Market Resources subsidiaries (2003 to 2005); Assistant Vice President (2001 to
2003).
Senior Vice President - Land and Business Development (2012 to present). Vice
President - Land and Business Development (2010 - 2012). Previous titles with
Questar: Vice President - Land and Business Development (2006 - 2010); Director of
Business Development (2004 to 2006).
Senior Vice President – Field Services (2010 to present). Previous title with Questar:
Vice President, Questar Gas Management (2005 to 2010).
Senior Vice President - Operations (2012 to present). Previous title with QEP: Senior
Vice President, Drilling and Completions (2011 to 2012). Previous titles with Questar:
Vice President, Drilling and Completions (2009 to 2010); Vice President, Rockies
Drilling and Completions (2005 to 2008).
Vice President, Compliance and Corporate Secretary, QEP (2010 to present). Previous
titles with Questar: Vice President Compliance (2007 to 2010); Corporate Secretary
(2005 to 2010); Assistant Secretary (2004 to 2005).
Vice President and General Counsel (2012 to present). Previous title with QEP: Senior
Attorney (2010 to 2012). Prior to joining QEP, Mr. Woosley was a partner in the law
firm Cooper Newsome & Woosley PLLP (2003 to 2010).
Vice President - Human Resources (2010 to present). Prior to joining QEP, Ms. Fiala
held a variety of roles at Suncor Energy (1995 to 2010) and most recently was the
Director of Human Resources for Suncor Energy U.S.A. (2004 to 2010).
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There is no "family relationship" between any of the listed officers or between any of them and the Company's directors. The
executive officers serve at the pleasure of the Company's Board of Directors. There is no arrangement or understanding under
which the officers were selected.
ITEM 1A. RISK FACTORS
Investors should read carefully the following factors as well as the cautionary statements referred to in "Forward-Looking
Statements" herein. If any of the risks and uncertainties described below or elsewhere in this Annual Report actually occur, the
Company's business, financial condition or results of operations could be materially adversely affected.
The prices for natural gas, oil and NGL are volatile, and a decline in such prices could adversely affect QEP's results, stock
price and growth plans. Historically natural gas, oil and NGL prices have been volatile and will likely continue to be volatile
in the future. U.S. natural gas prices in particular are significantly influenced by weather and weather forecasts. Any significant
or extended decline in commodity prices would impact the Company's future financial condition, revenue, operating results,
cash flow, return on invested capital, and rate of growth. In addition, significant and extended declines in commodity prices
could limit QEP's access to sources of capital or cause QEP to delay or postpone some of its capital projects. Because a
significant portion of QEP Energy's future production is natural gas, the Company's financial results are substantially more
sensitive to changes in natural gas prices than to changes in oil prices.
QEP cannot predict the future price of natural gas, oil and NGL because of factors beyond its control, including but not limited
to:
changes in domestic and foreign supply of natural gas, oil and NGL;
changes in local, regional, national and global demand for natural gas, oil, NGL and related commodities;
the activities of the Organization of Petroleum Exporting Countries;
domestic and global economic conditions;
regional price differences resulting from available pipeline transportation capacity or local demand;
terrorist attacks on production or transportation assets;
the level of imports of, and the price of, foreign natural gas, oil and NGL;
the potential long-term impact of an abundance of natural gas, oil and NGL from unconventional sources on the
global and local energy supply;
domestic political developments and actions;
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• weather conditions and weather forecasts;
•
domestic government regulations and taxes, including regulations or legislation relating to climate change or natural
gas and oil exploration and production activities;
technological advances affecting energy consumption and energy supply;
conservation efforts;
the price, availability and acceptance of alternative fuels, including coal, nuclear energy and biofuels;
demand for electricity as well as natural gas used for fuel for electricity generation;
storage levels of natural gas, oil, and NGL; and
the quality of natural gas and oil produced.
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In addition, lower commodity prices may result in asset impairment charges from reductions in the carrying values of QEP's
natural gas and oil properties or a reduction in the carrying value of goodwill. During the years ended December 31, 2012 and
2011, QEP recorded impairment charges of $107.6 million and $195.5 million, respectively, on its proven properties and $23.7
million and $20.3 million, respectively, on its unproven properties. See Part I, Item 8, Note 1 - Summary of Significant
Accounting Policies, of this Annual Report on Form 10-K for additional information.
Slower economic growth rates in the U.S. may materially adversely impact QEP's operating results. The U.S. and other
economies are recovering from a global financial crisis and recession that began in 2008. Growth has resumed but has been
modest and at an unsteady rate. There could be significant long-term effects resulting from the financial crisis and recession,
including a future global economic growth rate that is slower than that experienced in the years leading up to the crisis, and
more volatility may occur before a sustainable, yet lower, growth rate is achieved. In addition, the Organization for Economic
Cooperation and Development has encouraged countries with large federal budget deficits, such as the U.S., to initiate deficit
reduction measures. Such measures, if they are undertaken too rapidly, could further undermine economic recovery and slow
growth by reducing demand. Global economic growth drives demand for energy from all sources, including fossil fuels. A
lower future economic growth rate is likely to result in decreased demand growth for QEP's natural gas, oil and NGL
production. A decrease in demand, excluding changes in other factors, could potentially result in lower commodity prices,
which would reduce QEP's cash flows from operations and its profitability.
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The Company may not be able to economically find and develop new reserves. The Company's profitability depends not only
on prevailing prices for natural gas, oil and NGL, but also its ability to find, develop and acquire gas and oil reserves that are
economically recoverable. Producing natural gas and oil reservoirs are generally characterized by declining production rates
that vary depending on reservoir characteristics. Because natural gas and oil production volumes from QEP wells typically
experience relatively steep declines in the first year of operation and continue to decline over the economic life of the well,
QEP must continue to invest significant capital to find, develop and acquire gas and oil reserves to replace those depleted by
production.
Gas and oil reserve estimates are imprecise and subject to revision. QEP's proved natural gas and oil reserve estimates are
prepared annually by independent reservoir engineering consultants. Gas and oil reserve estimates are subject to numerous
uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and timing of
development expenditures. The accuracy of these estimates depends on the quality of available data and on engineering and
geological interpretation and judgment. Reserve estimates are imprecise and will change as additional information becomes
available. Estimates of economically recoverable reserves and future net cash flows prepared by different engineers, or by the
same engineers at different times, may vary significantly. Results of subsequent drilling, testing and production may cause
either upward or downward revisions of previous estimates. In addition, the estimation process also involves economic
assumptions relating to commodity prices, operating costs, severance and other taxes, capital expenditures and remediation
costs. Actual results most likely will vary from the estimates. Any significant variance from these assumptions could affect the
recoverable quantities of reserves attributable to any particular properties, the classifications of reserves, the estimated future
net cash flows from proved reserves and the present value of those reserves.
Investors should not assume that QEP's presentation of the Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Reserves in this Annual Report is reflective of the current market value of the estimated natural gas and oil
reserves. In accordance with SEC disclosure rules, the estimated discounted future net cash flows from QEP's proved reserves
are based on the first-of-the-month prior 12-month average prices and current costs on the date of the estimate, holding the
prices and costs constant throughout the life of the properties and using a discount factor of 10 percent per year. Actual future
production, prices and costs may differ materially from those used in the current estimate, and future determinations of the
Standardized Measure of Discounted Future Net Cash Flows using similarly determined prices and costs may be significantly
different from the current estimate.
Shortages of, and increasing prices for, oilfield equipment, services and qualified personnel could impact results of
operations. The demand for and availability of qualified and experienced personnel to drill wells and conduct field operations,
in addition to geologists, geophysicists, engineers, landmen and other professionals in the oil and gas industry, can fluctuate
significantly, often in correlation with natural gas and oil prices, causing periodic shortages. There have also been regional
shortages of drilling rigs and other equipment, as demand for specialized rigs and equipment has increased along with the
number of wells being drilled. These factors also cause increases in costs for equipment, services and personnel. These cost
increases could impact profit margin, cash flow and operating results or restrict the ability to drill wells and conduct operations,
especially during periods of lower natural gas and oil prices.
QEP's operations involve numerous risks that might result in accidents and other operating risks and costs. Drilling of
natural gas and oil wells is potentially a high-risk activity. Risks include:
•
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•
•
•
injuries and/or deaths of employees, supplier personnel, or other individuals;
fire, explosions and blow-outs;
unexpected drilling conditions such as abnormally pressured formations;
pipe, cement or casing failures;
title disputes;
equipment malfunctions and/or mechanical failure on high-volume wells;
security breaches, cyber attacks, piracy, or terroristic acts;
theft or vandalism of oilfield equipment and supplies, especially in areas of increased activity;
severe weather that could affect our operations;
plant, pipeline, and other facility accidents and failures; and
environmental accidents such as oil spills, natural gas leaks, ruptures or discharges of air pollutants, brine water or
well fluids into the environment, including from hydraulic fracturing activities.
The Company could incur substantial losses as a result of injury or loss of life; pollution or other environmental damage;
damage to or destruction of property and equipment; regulatory compliance investigations; fines or curtailment of operations;
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or attorney's fees and other expenses incurred in the prosecution or defense of litigation. As a working interest owner in wells
operated by other companies, the Company may also be exposed to the risks enumerated above from operations that are not
within its care, custody or control.
There are also inherent operating risks and hazards in the Company's gas and oil production and gas gathering, processing and
treating operations that could cause substantial financial losses. These risks could result in personal injury or loss of human life,
significant damage to property, environmental pollution, impairment of operations and substantial losses. The location of
pipelines near populated areas, including residential areas, commercial business centers and industrial sites could increase the
level of damages resulting from these risks. Certain segments of the Company's pipelines run through such areas. In spite of the
Company's precautions, an accident or other event could cause considerable harm to people or property, and could have a
material adverse effect on the financial position and results of operations, particularly if the event is not fully covered by
insurance. Accidents or other operating risks once realized could further result in lost business activity. Such circumstances
could adversely impact the Company's ability to meet contractual obligations.
As is customary with industry practice, operators generally indemnify drilling contractors and oilfield service companies
(collectively, contractors) against certain losses suffered by the operator and third parties resulting from a well blowout or fire
or other uncontrolled flow of hydrocarbons, regardless of the relative fault of the contractor. Therefore, QEP may be liable,
regardless of the fault of the contractor, for some or all of the costs of controlling a blowout, drilling a relief and/or replacement
well and the cleanup of any pollution or contamination resulting from a blowout as well as for claims for personal injury or
death suffered by QEP's employees and others. QEP's drilling contracts and oilfield service agreements, however, generally
provide that the contractor will indemnify QEP for claims related to injury and death of employees of the contractor and its
subcontractors and for property damage suffered by the contractor and its contractors.
As is also customary in the gas and oil industry, the Company maintains insurance against some, but not all, of these potential
risks and losses. Although QEP believes the coverage and amounts of insurance that it carries are consistent with industry
practice, QEP does not have insurance protection against all risks that it faces, because QEP chooses not to insure certain risks,
insurance is not available at a level that balances the costs of insurance and QEP's desired rates of return, or actual losses may
exceed coverage limits.
Certain of QEP's undeveloped leasehold assets are subject to lease agreements that will expire over the next several years
unless production is established on units containing the acreage.
Leases on natural gas and oil properties typically have a term of three to five years after which they expire unless, prior to
expiration, a well is drilled and production of hydrocarbons in paying quantities is established. If QEP's leases expire and QEP
is unable to renew the leases, QEP will lose its right to develop the related reserves. While QEP seeks to actively manage its
leasehold inventory by drilling sufficient wells to hold the leases that it believes are material to its operations, QEP's drilling
plans are subject to change based upon various factors, including drilling results, natural gas and oil prices, the availability and
cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline
transportation constraints and regulatory approvals.
Lack of availability of pipeline and other transportation capacity could impact results of operations. The lack of availability
of satisfactory oil, natural gas and NGL transportation facilities may hinder QEP's access to oil, NGL and natural gas markets
or delay production from its wells. QEP's ability to market its production depends in substantial part on the availability and
capacity of pipelines owned and operated by third parties. Although QEP has some contractual control over the transportation
of its production through firm transportation arrangements, third-party systems may be temporarily unavailable due to market
conditions, mechanical failures, or other reasons. If pipelines do not exist near producing wells, if pipeline capacity is limited or
if pipeline capacity is unexpectedly disrupted, sales could be reduced or production shut in, reducing profitability. Furthermore,
if QEP were required to shut in wells, it might also be obligated to pay shut-in royalties to certain mineral interest owners in
order to maintain its leases; or depending on the specific lease provisions, some leases could terminate. If pipeline quality
requirements change, QEP might be required to install or contract for additional treating or processing equipment, which could
also increase costs. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies,
changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions
could also adversely affect QEP's ability to transport natural gas and oil.
The fees charged by QEP to third parties under its gathering and processing agreements may not escalate sufficiently to
cover increases in costs, or the agreements may not be renewed or may be suspended in some circumstances. QEP's costs
may increase at a rate greater than the fees it charges to third parties for gathering, treating and processing services.
Furthermore, third parties may not renew their contracts with QEP. Additionally, some third parties' obligations under their
agreements with QEP may be permanently or temporarily reduced due to certain events, some of which are beyond QEP's
control, including force majeure events wherein the supply of either natural gas, oil or NGL are curtailed or cut off. Force
17
majeure events include (but are not limited to): revolutions, wars, acts of enemies, embargoes, import or export restrictions,
strikes, lockouts, fires, storms, floods, earthquakes, acts of God, explosions and mechanical or physical failures of equipment
affecting QEP's facilities or facilities of third parties. If the escalation of fees is insufficient to cover increased costs, if third
parties do not renew or extend their contracts with QEP or if third parties suspend or terminate their contracts with QEP, the
Company's financial results would suffer.
QEP is dependent on its revolving credit facility and continued access to capital markets to successfully execute its operating
strategies. If QEP is unable to obtain needed capital or financing on satisfactory terms, QEP may experience a decline in its
natural gas and oil production rates and reserves. QEP is partially dependent on external capital sources to provide financing for
certain projects. The availability and cost of these capital sources is cyclical, and these capital sources may not remain
available, or the Company may not be able to obtain financing at a reasonable cost in the future. Over the last few years,
conditions in the global capital markets have been volatile, making terms for certain types of financings difficult to predict, and
in certain cases, resulting in certain types of financing being unavailable. If QEP's revenues decline as a result of lower natural
gas, oil or NGL prices, operating difficulties, declines in production or for any other reason, QEP may have limited ability to
obtain the capital necessary to sustain its operations at current levels. The Company utilizes its revolving credit facility,
provided by a group of financial institutions, to meet short-term funding needs. All of QEP's debt under its revolving credit
facility is floating-rate debt. From time to time, the Company may use interest-rate derivatives to manage the interest rate on a
portion of its floating-rate debt. The interest rates for the Company's revolving credit facility are tied to QEP's ratio of
indebtedness to Consolidated EBITDAX (as defined in the credit agreement). QEP's failure to obtain additional financing could
result in a curtailment of its operations relating to exploration and development of its prospects or construction of new oil and
gas processing facilities, which in turn could lead to a possible reduction in QEP's natural gas or oil production, reserves and its
revenues, and could negatively impact its results of operations.
A downgrade in QEP's credit rating could negatively impact QEP's cost of and ability to access capital. Although QEP is not
aware of any current plans of credit rating agencies to lower their ratings on QEP's debt, QEP's credit ratings may be subject to
future downgrades. A downgrade of credit ratings may make it more difficult or expensive to raise capital from financial
institutions or other sources. A downgrade in QEP's credit rating below a certain level could limit the amount of debt that QEP
may incur. In addition, a downgrade could affect QEP's requirements to provide financial assurance of its performance under
certain contractual arrangements and derivative agreements.
QEP's debt and other financial commitments may limit its financial and operating flexibility. QEP's total debt was
approximately $3.2 billion at December 31, 2012. QEP also has various commitments for leases, drilling contracts, derivative
contracts, firm transportation, and purchase obligations for services and products. QEP's financial commitments could have
important consequences to its business including, but not limited to, limiting QEP's ability to fund future working capital and
capital expenditures, to engage in future acquisitions or development activities, to pay dividends to shareholders, or to
otherwise realize the value of its assets and opportunities fully because of the need to dedicate a substantial portion of its cash
flows from operations to payments on its debt or to comply with any restrictive terms of its debt. Additionally, the credit
agreements governing QEP's revolving credit facility and term loan facility contain a number of covenants that impose
constraints on the Company, including restrictions on QEP's ability to dispose of assets, make certain investments, and incur
liens.
QEP is exposed to counterparty credit risk as a result of QEP's receivables and commodity derivative transactions. QEP has
significant credit exposure to outstanding accounts receivable from purchasers of its production, joint interest and working
interest owners as well as customers in all segments of its business. Because QEP is the operator of a majority of its production
and major development projects, QEP pays joint venture expenses and in some cases makes cash calls on its non-operating
partners for their respective shares of joint venture costs. These projects are capital intensive and, in some cases, a non-
operating partner may experience a delay in obtaining financing for its share of the joint venture costs. Counterparty liquidity
problems could result in a delay in QEP receiving proceeds from commodity sales or reimbursement of joint venture costs.
Credit enhancements, such as financial guarantees or prepayments, have been obtained from some but not all
parties. Nonperformance by a trade creditor or joint venture partner could result in financial losses. In addition, QEP's
commodity derivative transactions expose it to risk of financial loss if the counterparty fails to perform under a contract.
During periods of falling commodity prices, QEP's commodity derivative receivable positions increase, which increases its
counterparty credit exposure.
QEP faces various risks associated with the trend toward increased activism against oil and gas exploration and
development activities. Opposition to oil and gas drilling and development activity has been growing globally and is
particularly pronounced in the U.S. Companies in the oil and gas industry, such as QEP, are often the target of activist efforts
from both individuals and non-governmental organizations regarding safety, environmental compliance and business practices.
Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay
18
or cancel certain projects such as the development of oil or gas shale plays. For example, environmental activists continue to
advocate for increased regulations on shale drilling in the U.S., even in jurisdictions that are among the most stringent in their
regulation of the industry. Future activist efforts could result in the following:
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delay or denial of drilling and other necessary permits;
shortening of lease terms or reduction in lease size;
restrictions on installation or operation of production, gathering or processing facilities;
setback requirements from houses, schools and businesses;
towns, cities, states and counties considering bans on certain activities, including hydraulic fracturing;
restrictions on the use of certain operating practices, such as hydraulic fracturing, or the disposition of related waste
materials, such as hydraulic fracturing fluids and produced water;
increased severance and/or other taxes;
cyber attacks;
legal challenges or lawsuits;
negative publicity about QEP;
increased costs of doing business;
reduction in demand for QEP's products; and
other adverse effects on QEP's ability to develop its properties and increase production.
QEP's need to incur costs associated with responding to these initiatives or complying with any resulting additional legal or
regulatory requirements that are substantial and not adequately provided for could have a material adverse effect on its
business, financial condition and results of operations.
QEP's use of derivative instruments to manage exposure to uncertain prices could result in financial losses or reduce its
income. QEP uses commodity-price derivative arrangements to reduce exposure to the volatility of natural gas, oil, and NGL
prices, and to protect cash flow and returns on capital from downward commodity price movements. To the extent the
Company enters into commodity derivative transactions, it may forgo some or all of the benefits of commodity price increases.
Additional financial regulations may change QEP's reporting and margining requirements relating to such instruments.
Furthermore, QEP's use of derivative instruments through which it attempts to reduce the economic risk of its participation in
commodity markets could result in increased volatility of QEP's reported results. Changes in the fair values (gains and losses)
of derivatives are recorded into QEP's income. This creates the risk of volatility in earnings even if no economic impact to QEP
has occurred during the applicable period. QEP has incurred significant unrealized gains and losses in prior periods and may
continue to incur these types of gains and losses in the future.
QEP enters into commodity-price derivative arrangements with creditworthy counterparties (banks and energy-trading firms)
that do not require collateral deposits. QEP is exposed to the risk of counterparties not performing. The amount of credit
available may vary depending on QEP's counterparty's assessment of QEP's credit risk.
Relative changes in NGL and natural gas prices may adversely impact QEP's results due to changes in the frac spread.
Approximately 23%, 30% and 22% of QEP Field Services' net operating revenues for the years ended December 31, 2012,
2011 and 2010, respectively, were derived from keep-whole processing agreements. Under QEP's keep-whole processing
contracts, QEP is exposed to the frac spread and transportation and fractionation exposure from firm transportation constraints.
Generally, the frac spread and, consequently, the net operating margins are positive under these contracts. In the event natural
gas becomes more expensive on a Btu equivalent basis than NGL products, QEP's cost of keeping the producer "whole" would
result in operating losses. Due to timing of gas purchases and liquid sales, direct exposure to changes in market prices of either
gas or liquids can be created, because there is an offsetting purchase or sale that remains exposed to market pricing. Through
QEP's marketing and derivatives activity, direct exposure may occur naturally or QEP may choose direct price exposure to
either gas or liquids when QEP favors that exposure over frac spread risk. Given that QEP has derivative positions, adverse
movement in prices to the positions QEP has taken will negatively impact results.
QEP has made significant investments in new cryogenic gas processing plants in its Northern Region (Rockies) in recent years.
The expected returns on these investments depend in large part on the future ethane price and margin, which historically have
been more volatile than the price of other NGL products, including propane, butane and gasoline. QEP's competitors have also
made significant investments in gas processing plants that recover significant volumes of ethane. The U.S. ethane market is
currently oversupplied, and probably will remain oversupplied in the foreseeable future, resulting in lower ethane prices.
QEP's plans to grow its midstream business by constructing new processing and treating facilities subjects the Company to
construction risks and the risk that the Company will not be able to secure long-term contracts from third parties required to
earn acceptable returns on these investments. One of the ways QEP has grown its business is through the construction of new
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gathering, treating and processing facilities. The construction of gathering, treating and processing facilities requires the
expenditure of significant amounts of capital and involves numerous regulatory, environmental, political, legal and inflationary
uncertainties. If QEP undertakes these projects, QEP may not be able to complete them on schedule, or at all, or at the budgeted
cost. While QEP may commit natural gas supplies from its production, such supplies may not be sufficient to fill available
capacity at these facilities, leaving QEP with limited natural gas supplies committed to these facilities prior to and after their
construction. Moreover, QEP may construct facilities to capture anticipated future growth in production in a region in which
anticipated production growth does not materialize. QEP may also rely on estimates of proved reserves in its decision to
construct new facilities, which may prove to be inaccurate, because there are numerous uncertainties inherent in estimating
quantities of proved reserves. As a result, new facilities may not be able to process or treat enough natural gas to achieve QEP's
expected investment return, which could adversely affect QEP's operations and cash flows.
If QEP's plan to separate a majority of its gathering assets in Wyoming and North Dakota into a new publicly traded master
limited partnership is delayed or not completed, QEP's stock price may decline and its growth potential may not be
enhanced. In January 2013, QEP announced a plan to separate a majority of its gathering assets in Wyoming and North Dakota
into a new publicly traded master limited partnership (“MLP”) and to file an initial registration statement in connection with
this planned initial public offering in the second quarter of 2013. Completion of this plan is subject to market conditions and
numerous other risks beyond QEP's control, including, but not limited to, the general economy, credit markets, equity markets,
energy prices, regulatory approvals, compliance with contractual obligations, and future opportunities that QEP's board of
directors may determine present greater potential value to stockholders than the planned MLP. Therefore, it is possible that
QEP will not file a registration statement for an initial public offering, that the MLP will not complete an offering of securities,
and that QEP will not be able to complete its proposed actions on the desired timetable. If the transaction is not completed or
delayed, QEP's stock price may decline and its growth potential may not be enhanced. If completed, QEP's plan to separate
portions of gathering assets may not achieve its intended results. QEP's announcement of this plan did not, and this risk factor
does not, constitute an offer to sell or the solicitation of an offer to buy any securities and shall not constitute an offer,
solicitation or sale in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or
qualification under the securities laws of that jurisdiction.
QEP faces significant competition and certain of its competitors have resources in excess of QEP's available resources. QEP
operates in the highly competitive areas of natural gas and oil exploration, exploitation, acquisition and production. QEP faces
competition from:
large multi-national, integrated oil companies;
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• U.S. independent oil and gas companies;
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service companies engaging in oil and gas exploration and production activities; and
private equity funds investing in oil and gas assets.
QEP faces competition in a number of areas such as:
acquiring desirable producing properties or new leases for future exploration;
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• marketing its natural gas, oil and NGL production;
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obtaining the equipment and expertise necessary to operate and develop properties; and
attracting and retaining employees with certain critical skills.
Certain of QEP's competitors have financial and other resources in excess of those available to QEP. Such companies may be
able to pay more for natural gas and crude oil properties and exploratory prospects and to define, evaluate, bid for and purchase
a greater number of properties and prospects than QEP's financial or human resources permit. This highly competitive
environment could have an adverse impact on QEP's business.
QEP may be unable to make acquisitions, successfully integrate acquired businesses and/or assets, or adjust to the effects of
divestitures, causing a disruption to its business. One aspect of QEP's business strategy calls for acquisitions of businesses and
assets that complement or expand QEP's current business, such as QEP's 2012 Acquisition in the Williston Basin. This may
present greater risks for QEP than those faced by peer companies that do not consider acquisitions as a part of their business
strategy. QEP cannot provide assurance that it will be able to identify acquisition opportunities. Even if QEP does identify
acquisition opportunities, it may not be able to complete the acquisitions due to capital constraints. Any acquisition of a
business or assets involves potential risks, including, among others:
•
•
difficulty integrating the operations, systems, management and other personnel and technology of the acquired
business with QEP's own;
the assumption of unidentified or unforeseeable liabilities, resulting in a loss of value;
20
•
•
the inability to hire, train or retain qualified personnel to manage and operate QEP's growing business and assets; or
a decrease in QEP's liquidity to the extent it uses a significant portion of its available cash or borrowing capacity to
finance acquisitions or operations of the acquired properties.
Organizational modifications due to acquisitions, divestitures or other strategic changes can alter the risk and control
environments, disrupt ongoing business, distract management and employees, increase expenses and adversely affect results of
operations. Even if these challenges can be dealt with successfully, the anticipated benefits of any acquisition, divestiture or
other strategic change may not be realized.
QEP may be unable to dispose of non-core, non-strategic assets on financially attractive terms, resulting in reduced cash
proceeds and/or losses. QEP's business strategy also includes sales of non-core, non-strategic assets. QEP continually evaluates
its portfolio of assets related to capital investments, divestitures and joint venture opportunities. Various factors can materially
affect QEP's ability to dispose of assets on terms acceptable to QEP. Such factors include current commodity prices, laws,
regulations and the permitting process impacting oil and gas operations in the areas where the assets are located, willingness of
the purchaser to assume certain liabilities such as asset retirement obligations, QEP's willingness to indemnify buyers for
certain matters, and other factors. Inability to achieve a desired price for the assets, or underestimation of amounts of retained
liabilities or indemnification obligations, can result in a reduction of cash proceeds, a loss on sale due to an excess of the asset's
net book value over proceeds, or liabilities that must be settled in the future at amounts that are higher than QEP had expected.
QEP is involved in legal proceedings that may result in substantial liabilities. Like many oil and gas companies, QEP is
involved in various legal proceedings, such as title, royalty, and contractual disputes, in the ordinary course of its business. The
cost to settle legal proceedings or any resulting judgment against QEP in such proceedings could result in a substantial liability,
which could materially and adversely impact QEP's cash flows and operating results for a particular period. Current accruals
for such liability may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal
proceedings could change from one period to the next and such changes could be material.
Failure of the Company's controls and procedures to detect errors or fraud could seriously harm its business and results of
operations. QEP's management, including its Chief Executive Officer and Chief Financial Officer, does not expect that the
Company's internal controls and disclosure controls will prevent all possible errors and all fraud. A control system, no matter
how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system
are being met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit
of controls must be relative to their costs. Because of the inherent limitations in all control systems, no evaluation of QEP's
controls can provide absolute assurance that all control issues and instances of fraud, if any, in the Company have been
detected. The design of any system of controls is based in part upon the likelihood of future events, and there can be no
assurance that any design will succeed in achieving its intended goals under all potential future conditions. Over time, a control
may become inadequate because of changes in conditions or the degree of compliance with its policies or procedures may
deteriorate. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur
without detection.
QEP is subject to complex federal, state, tribal, local and other laws and regulations that could adversely affect its cost of
doing business and recording of proved reserves. QEP's operations are subject to extensive federal, state, tribal and local tax,
energy, environmental, health and safety laws and regulations. The failure to comply with applicable laws and regulations can
result in substantial penalties and may threaten the Company's authorization to operate.
Environmental laws and regulations are complex, change frequently and have tended to become more onerous over time. The
regulatory burden on the Company's operations increases its cost of doing business and, consequently, affects its profitability.
In addition to the costs of compliance, substantial costs may be incurred to take corrective actions at both owned and previously
owned facilities. Accidental spills and leaks requiring cleanup may occur in the ordinary course of QEP's business. As
standards change, the Company may incur significant costs in cases where past operations followed practices that were
considered acceptable at the time, but now require remedial work to meet current standards. Failure to comply with these laws
and regulations may result in fines, significant costs for remedial activities, or injunctions that could limit the scope of QEP's
planned operations.
Current federal regulations restrict activities during certain times of the year on significant portions of QEP Energy leasehold
due to wildlife activity and/or habitat. QEP Energy has worked with federal and state officials in Wyoming to obtain
authorization for limited winter-drilling activities on the Pinedale Anticline and has developed measures, such as drilling
multiple wells from a single pad location, to minimize the impact of its activities on wildlife and wildlife habitat in its
operations on federal lands. Various wildlife species inhabit QEP Energy's leaseholds at Pinedale and in other areas. The
presence of wildlife or plants, including species that are protected under the federal Endangered Species Act, could limit access
21
to leases held by QEP Energy on public and other lands. Many of QEP's operations are subject to the requirements of the
National Environmental Policy Act (NEPA), and are therefore evaluated under NEPA for their direct, indirect and cumulative
environmental impacts. This is done in Environmental Assessments or Environmental Impact Statements prepared for a lead
agency under Council on Environmental Quality and other agency regulations, usually for the BLM in the areas where QEP
operates currently. In September 2008, the BLM issued a Record of Decision (ROD) on the Final Supplemental Environmental
Impact Statement (FSEIS) for long-term development of natural gas resources in the Pinedale Anticline Project Area (PAPA).
Under the ROD, QEP Energy is allowed to drill and complete wells year-round in one of five Concentrated Development Areas
defined in the PAPA. The ROD contains additional requirements and restrictions on development of the PAPA to which QEP
Energy is subject.
Several of QEP Field Services' transportation facilities are subject to FERC jurisdiction, and as such, are subject to specific
regulations regarding interstate transmission facilities and activities, including but not limited to rates charged for transmission,
open access/non-discrimination, and public daily capacity and flow reporting requirements. Additionally, FERC has jurisdiction
over the operation of QEP Marketing's Clear Creek storage facility by virtue of the facility being connected to interstate
pipelines (also subject to FERC jurisdiction) at both its inlet and outlet. Clear Creek is subject to specific FERC regulations
governing interstate transmission facilities and activities, including but not limited to rates charges for transmission, open
access/non-discrimination, and public disclosure via an electronic bulletin board of daily capacity and flows.
Section 1(b) of the Natural Gas Act exempts gathering activities from regulation or jurisdiction by the FERC. QEP owns, or
holds interests in, a number of pipelines that it believes meet the tests FERC has used to determine a pipeline system's status as
a non-jurisdictional gatherer. There is, however, no bright-line test for determining jurisdictional status of QEP Field Services'
gathering systems, so the distinction between non-jurisdictional gathering and FERC-regulated transmission pipelines may
from time-to-time be the subject of disputes and litigation. QEP Field Services therefore cannot guarantee that the jurisdictional
status of its gathering systems will remain unchanged. QEP's gas gathering systems are not currently subject to state utility
regulations. The FERC has jurisdiction under the Energy Policy Act of 2005 to impose rules and regulations applicable to all
natural gas market participants to ensure market transparency.
Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may
be eliminated as a result of future legislation. The U.S. President's Fiscal Year 2013 Budget Proposal includes provisions
that, if enacted into law, would eliminate certain key U.S. federal income tax incentives currently available to oil and natural
gas exploration and production companies. These changes include (i) the repeal of the percentage depletion allowance for oil
and natural gas wells, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the
elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for
certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted,
how soon any such changes could become effective. The passage of this legislation or any similar changes in U.S. federal
income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural
gas exploration and development and increase the cost of exploration and development of natural gas and oil resources.
Environmental laws are complex and potentially burdensome for QEP's operations. QEP must comply with numerous and
complex federal, state and tribal regulations governing activities on federal, state and tribal lands, notably including the Clean
Air Act, the Clean Water Act, the SDWA, OPA, CERCLA, RCRA, NEPA, the Endangered Species Act, the National Historic
Preservation Act and similar state laws and tribal codes. Federal, state and tribal regulatory agencies frequently impose
conditions on the Company's activities under these laws. These restrictions have become more stringent over time and can limit
or prevent exploration and production on significant portions of the Company's leasehold. These laws also allow certain
environmental groups to oppose drilling on some of QEP's federal and state leases. These groups sometimes sue federal and
state regulatory agencies and/or the Company under these laws for alleged procedural violations in an attempt to stop, limit or
delay natural gas and oil development on public and other lands.
QEP may not be able to obtain the permits and approvals necessary to continue and expand its operations. Regulatory
authorities exercise considerable discretion in the timing and scope of permit issuance. Requirements imposed by these
authorities may be costly and time consuming and may result in delays in the commencement or continuation of the Company's
exploration and production and midstream field services operations. For example, QEP's drilling operations in the Powder
River Basin in Wyoming continue to be delayed due to an over two-year backlog of permit applications. Further, the public
may comment on and otherwise seek to influence the permitting process, including through intervention in the courts.
Accordingly, necessary permits may not be issued, or if issued, may not be issued in a timely fashion, or may involve
requirements that restrict QEP's ability to conduct its operations or to do so profitably.
Federal and state hydraulic fracturing legislation or regulatory initiatives could increase QEP's costs and restrict its access
to natural gas and oil reserves. Currently, all well construction activities, including hydraulic fracture stimulation, are
22
regulated by state agencies that review and approve all aspects of natural gas and oil well design and operation. The EPA
recently asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the federal
SDWA and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. The EPA
appears to be considering its existing regulatory authorities for possible avenues to further regulate hydraulic fracturing fluids
and/or the components of those fluids. Additionally, the Bureau of Land Management proposed in May 2012, new regulations
regarding chemical disclosure requirements and other regulations specific to well stimulation activities, including hydraulic
fracturing, on federal and tribal lands. Legislation has also been introduced before Congress to provide for federal regulation of
hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process, notwithstanding the
proposed and ongoing rulemaking proceedings noted above. At the state level, some states have adopted and other states are
considering adopting regulations that could restrict hydraulic fracturing in certain circumstances. In the event that new or more
stringent federal, state or local regulations, restrictions or moratoria are adopted in areas where QEP operates, QEP could incur
potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of
exploration, development, or production activities, and perhaps even be precluded from drilling or stimulating wells in some
areas.
QEP's ability to produce natural gas and oil economically and in commercial quantities could be impaired if it is unable to
acquire adequate supplies of water for its drilling and completion operations or is unable to dispose of or recycle the water it
uses at a reasonable cost and in accordance with applicable environmental rules. The hydraulic fracture stimulation process
on which QEP depends to produce commercial quantities of natural gas and oil requires the use and disposal of significant
quantities of water. QEP's inability to secure sufficient amounts of water, or to dispose of or recycle the water used in its
operations, could adversely impact its operations. As noted above, the imposition of new environmental initiatives and
regulations could include restrictions on QEP's ability to conduct certain operations such as hydraulic fracturing or disposal of
waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration,
development or production of natural gas. Compliance with environmental regulations and permit requirements governing the
withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase QEP's
operating costs and cause delays, interruptions or termination of its operations, the extent of which cannot be predicted.
The adoption of greenhouse gas (GHG) emission or other environmental legislation could result in increased operating
costs, delays in obtaining air pollution permits for new or modified facilities, and reduced demand for the natural gas, oil
and NGL that QEP produces. Federal and state courts and administrative agencies are considering the scope and scale of
climate-change regulation under various laws pertaining to the environment, energy use and development. Federal, state and
local governments may also pass laws mandating the use of alternative energy sources, such as wind power and solar energy,
which may reduce demand for natural gas and crude oil. QEP's ability to access and develop new natural gas and crude oil
reserves may be restricted by climate-change regulation, including GHG reporting and regulation. Legislative bills have been
proposed in Congress that would regulate GHG emissions through a cap-and-trade system under which emitters would be
required to buy allowances for offsets of emissions of GHG. The EPA has adopted final regulations for the measurement and
reporting of GHG emitted from certain large facilities. Additionally, the EPA and authorized states have begun the permitting of
major sources of GHG under the Clean Air Act pursuant to the EPA's GHG Tailoring Rule whereby new and existing sources of
GHG emitting above major source thresholds are required to obtain major source permits. In addition, several of the states in
which QEP operates are considering various GHG registration and reduction programs. While additional climate-change
regulation is possible at the federal level, it is too early to predict how such regulation would affect QEP's business, operations
or financial results. It is uncertain whether QEP's operations and properties, located in the Northern and Southern Regions of
the United States, are exposed to possible physical risks, such as severe weather patterns, due to climate change that may or
may not be the result of anthropogenic emissions of GHG. Management does not, however, believe such physical risks are
reasonably likely to have a material effect on the Company's financial condition or results of operations.
The adoption and implementation of new statutory and regulatory requirements for swap transactions could have an
adverse impact on QEP's ability to mitigate risks associated with its business and increase the working capital requirements
to conduct these activities. The Dodd-Frank Act, which was passed by Congress and signed into law in July 2010, contains
significant derivatives regulation. QEP is currently evaluating the final rules of the Commodity Futures Trading Commission
and assessing the impact on the Company's risk management program. QEP believes it will meet the requirements for the
commercial end-user clearing exception and be able to continue to execute derivative transactions and not be required to meet
the mandated clearing requirements.
QEP will need to expend significant resources complying with and adapting to the new regulatory regime, including significant
reporting and record keeping requirements, as well as otherwise ensuring that QEP continues to be able to rely on certain
exemptions from mandatory clearing requirements. In addition, the changes to the swap market as a result of the
implementation of the Dodd-Frank Act could significantly increase the cost of entering into new swaps or maintaining existing
23
swaps, materially alter the terms of new or existing swap transactions, impose additional documentation requirements, and/or
reduce the availability of new or existing swaps.
Depending on the final form of the margin rules for uncleared swaps and whether swap dealers elect to collect margin from
end-user clients even if there is no requirement to do so under the Dodd-Frank Act, QEP might in the future be required to
provide cash collateral for its commodity derivative transactions under circumstances in which it does not currently post cash
collateral. Requirements to post cash collateral could not only cause significant liquidity issues by reducing QEP's flexibility in
using its cash and other sources of funds, such as its revolving credit facility, but could also cause QEP to incur additional
debt. In addition, a requirement for QEP's counterparties to post cash collateral would likely result in additional costs being
passed on to QEP, thereby decreasing the effectiveness of its commodity derivatives and its profitability. If the costs of
complying with the clearing and margin requirements and business conduct rules under the Dodd-Frank Act significantly
increase the costs of entering into commodity derivative transactions, QEP may reduce its commodity derivative program,
which could increase its exposure to fluctuating commodity prices, increase the volatility of QEP's results of operations and
reduce the predictability of the Company's cash flows, which in turn could adversely affect QEP's ability to plan for and fund
capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices.
QEP's revenues could be adversely affected if a consequence of the legislation and regulations is to lower commodity prices.
Any of these consequences could have a material adverse effect on QEP's consolidated financial position, results of operations
or cash flows.
General economic and other conditions impact QEP's results. QEP's results may also be negatively affected by: changes in
global economic conditions; availability and economic viability of gas and oil properties for sale or exploration; rate of
inflation and interest rates; assumptions used in business combinations; weather and natural disasters; changes in customers'
credit ratings; competition from other forms of energy, other pipelines and storage facilities; effects of accounting policies
issued periodically by accounting standard-setting bodies; and terrorist attacks or acts of war.
The Company's pension plans are currently underfunded and may require large contributions, which may divert funds from
other uses. QEP has a closed defined benefit pension plan that covers 145, or 16%, of QEP's active employees and 70
participants that are retired, terminated and vested, or suspended. Over time, periods of declines in interest rates and pension
asset values may result in a reduction in the funded status of the Company's pension plans. As of December 31, 2012 and 2011,
QEP's pension plans were underfunded by $74.4 million and $59.9 million, respectively. The underfunded status of QEP's
pension plans may require that the Company make large contributions to such plans. QEP made cash contributions of $6.9
million and $14.8 million during the years ended December 2012 and 2011, respectively, to its defined benefit pension plans
and expects to make contributions of approximately $11.3 million to its pension plans in 2013. QEP cannot, however, predict
whether changing economic conditions, the future performance of assets in the plans or other factors will require the Company
to make contributions in excess of its current expectations, diverting funds QEP would otherwise apply to other uses.
QEP is subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption,
operational disruption and/or financial loss. The oil and gas industry has become increasingly dependent on digital
technologies to conduct certain exploration, development, production, and processing activities. For example, QEP depends on
digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering and processing systems,
conduct reservoir modeling and reserves estimation, and process and record financial and operating data. Pipelines, refineries,
power stations and distribution points for both fuels and electricity are becoming more interconnected by computer systems. At
the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. QEP's technologies,
systems, networks, and those of its vendors, suppliers and other business partners may become the target of cyber attacks or
information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of
proprietary and other information, or other disruption of its business operations. In addition, certain cyber incidents, such as
surveillance, may remain undetected for an extended period. QEP's systems and insurance coverage for protecting against
cyber security risks may not be sufficient.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
24
ITEM 2. PROPERTIES
Exploration and Production - QEP Energy
QEP's exploration and production business is conducted through QEP Energy in two core regions – the Northern Region
(including the states of Wyoming, Utah, Colorado, New Mexico and North Dakota) and the Southern Region (including the
states of Oklahoma, Texas and Louisiana).
Northern Region
Pinedale
In 2005, the Wyoming Oil and Gas Conservation Commission (WOGCC) approved 10-acre density drilling for Lance Pool
wells on about 12,700 gross acres (8,091 net acres) of QEP Energy's 17,115 gross acres (11,601 net acres) Pinedale leasehold.
In January 2008, the WOGCC approved five-acre density drilling for Lance Pool wells on about 4,200 gross acres (2,677 net
acres) of QEP Energy's Pinedale leasehold. On March 13, 2012, the WOGCC approved five-acre density drilling for Lance
Pool wells on approximately 7,200 additional gross acres (4,317 net acres). The area approved for increased density
corresponds to the currently estimated economic productive limits of QEP Energy core acreage in the field. The top of the
Lance Pool tight gas sand reservoir interval ranges from 8,500 to 9,500 feet across QEP Energy's acreage. The Company
currently estimates that more than 900 additional wells will be required to fully develop its Pinedale acreage on 5 to 10-acre
density. At December 31, 2012, QEP Energy had four operated rigs drilling in the Pinedale Anticline. In addition to QEP
Energy's 715 gross producing wells, QEP Energy has an overriding royalty interest only in an additional 21 wells at Pinedale.
Williston Basin
QEP has approximately 117,000 net acres of leaseholds in the Williston Basin in western North Dakota, where the Company is
targeting the Bakken and Three Forks formations. During the third quarter of 2012, QEP Energy closed the 2012 Acquisition,
which added 27,600 net acres of producing leasehold in the Williston Basin. As a result of the 2012 Acquisition and
development drilling on existing acreage, Williston Basin reserves represent 16% of the Company's total reserves. Accordingly,
Williston Basin reserves and production are shown separately from Legacy's results in the years presented. The top of the
Bakken Formation ranges from approximately 9,500 feet to 10,000 feet across QEP Energy's leasehold. The Three Forks
Formation lies approximately 60 to 70 feet below the Middle Bakken Formation and is also a target for horizontal drilling. As
of December 31, 2012, QEP Energy had five operated rigs drilling in the Williston Basin.
Uinta Basin
The majority of Uinta Basin proved reserves are found in a series of vertically stacked, laterally discontinuous reservoirs at
depths of 4,500 feet to deeper than 18,000 feet. QEP Energy owns working interests in approximately 257,000 net leasehold
acres in the Uinta Basin. QEP Energy had three operated rigs drilling in the Uinta Basin at December 31, 2012, two of which
were targeting the Lower Mesaverde Formation productive fairway in the Red Wash Unit, in which QEP holds 32,300 net
acres, and the other drilling various vertical and horizontal oil targets.
Legacy
The remainder of QEP Energy Northern Region leasehold interests, productive wells and proved reserves are distributed over a
number of fields and properties managed as Legacy. Exploration and development activity in 2012 included wells in the Powder
River and Greater Green River Basins in Wyoming.
Southern Region
Haynesville/Cotton Valley
QEP Energy has approximately 50,700 net acres of Haynesville Shale leaseholds in northwest Louisiana and additional lease
rights that cover the Hosston and Cotton Valley formations. The top of the Haynesville Shale ranges from approximately
10,500 feet to 12,500 feet across QEP Energy's leasehold and is below the Hosston and Cotton Valley formations that QEP
Energy has been developing in northwest Louisiana since the 1990's. As of December 31, 2012, due to depressed natural gas
prices, QEP Energy did not have any operated rigs drilling in the Haynesville/Cotton Valley area.
Midcontinent
QEP Energy's Midcontinent operations cover all properties in the Southern Region except the Haynesville/Cotton Valley area
of northwest Louisiana and are distributed over a large area, including the Anadarko Basin of Oklahoma and the Texas
Panhandle.
25
QEP Energy has approximately 76,000 net acres of Woodford "Cana" Shale leaseholds in western Oklahoma. The top of the
Woodford Shale ranges from approximately 10,500 feet to 14,500 feet across QEP Energy's leasehold. As of December 31,
2012, QEP Energy had two operated rigs drilling in the Woodford/Cana play.
QEP Energy has approximately 35,000 net acres of Granite Wash/Atoka Wash leaseholds in the Texas Panhandle and western
Oklahoma and has been drilling vertical Granite Wash/Atoka Wash wells for over a decade. The top of the Granite Wash/Atoka
Wash interval ranges from approximately 11,100 feet to 15,900 feet across QEP Energy's leasehold. In the past few years, QEP
and other operators have drilled a number of successful horizontal wells in the Granite Wash/Atoka Wash play but have also
drilled some uneconomic wells. As of December 31, 2012, QEP Energy had one rig drilling in oil and liquids-rich gas plays in
the Texas Panhandle.
Reserves – QEP Energy
At both December 31, 2012 and 2011, approximately 91% of QEP Energy's estimated proved reserves were Company operated.
Proved developed reserves represented 54% of the Company's total proved reserves at both December 31, 2012 and 2011,
while the remaining 46% of reserves were classified as proved undeveloped at both December 31, 2012 and 2011. All reported
reserves are located in the U.S. QEP Energy does not have any long-term supply contracts with foreign governments, reserves
of equity investees or reserves of subsidiaries with a significant minority interest. QEP Energy's estimated proved reserves are
summarized as follows:
December 31, 2012
December 31, 2011
Natural
Gas
Oil
NGL
Natural Gas
Equivalents (1)
Natural
Gas
Oil
NGL
Natural Gas
Equivalents (1)
(Bcf)
(MMbbl)
(MMbbl)
(Bcfe)
(Bcf)
(MMbbl)
(MMbbl)
(Bcfe)
Proved developed
reserves
Proved undeveloped
reserves
1,531.7
1,090.7
47.4
71.6
Total proved
reserves
2,622.4
119.0
____________________________
49.3
50.6
99.9
2,111.9
1,538.3
1,824.2
1,211.1
3,936.1
2,749.4
33.0
34.6
67.6
38.4
38.2
76.6
1,966.3
1,647.5
3,613.8
(1) Oil and NGL are converted to natural gas equivalents at the ratio of one bbl of crude oil, condensate or NGL to six
Mcf of equivalent natural gas.
QEP Energy's reserve, production and production life index for each of the years ended December 31, 2010, through December
31, 2012, is summarized below:
Year ended
December 31,
Year End
Reserves (Bcfe)
Natural Gas, Oil
and NGL Production (Bcfe)
Reserve Life
Index (1) (Years)
2010
2011
2012
3,030.7
3,613.8
3,936.1
____________________________
229.0
275.2
319.2
13.2
13.1
12.3
(1) Reserve life index is calculated by dividing year-end proved reserves by production for that year.
Proved Reserves
Reserve and related information is presented consistent with the requirements of the SEC's rules for the Modernization of Oil
and Gas Reporting. These rules expand the use of reliable technologies to estimate and categorize reserves and require the use
of the average of the first-of-the-month commodity prices, adjusted for location and quality differentials, for the prior 12
months (unless contractual arrangements designate the price) used to calculate economic producibility of reserves and the
discounted cash flows reported as the Standardized Measure of Future Net Cash Flows Relating to Proved Reserves. Refer to
Note 17 - Supplemental Gas and Oil Information (unaudited), of in Item 8 of Part II of this Annual Report for additional
information regarding estimates of proved reserves and the preparation of such estimates.
26
QEP Energy's proved reserves in major operating areas are summarized below:
Northern Region
Pinedale
Williston Basin
Uinta Basin
Legacy
Southern Region
Haynesville/Cotton Valley
Midcontinent
Total QEP Energy
December 31,
2012
2011
(Bcfe)
1,530.8
614.7
617.9
112.2
(% of total)
39 %
16 %
16 %
3 %
(Bcfe)
1,531.0
259.0
393.6
128.6
(% of total)
42%
7%
11%
4%
530.5
530.0
3,936.1
13 %
13 %
782.9
518.7
100 %
3,613.8
22%
14%
100%
Estimates of the quantity of proved reserves increased during 2012, primarily related to reserve additions in the Williston and
Uinta Basins, offset by decreases in estimated Haynesville/Cotton Valley proved reserves. The increase in Williston Basin
reserves was primarily the result of the 2012 Acquisition, while increases in the Uinta Basin were attributable to extensions and
additions from the recognition of additional proved undeveloped locations due to QEP's increased drilling program. The
Haynesville/Cotton Valley decrease was primarily related to downward pricing related revisions, resulting from lower natural
gas prices mostly related to proved undeveloped reserves.
Proved Undeveloped Reserves
Significant changes to proved undeveloped reserves (PUDs) occurring during 2012, are summarized in the table below:
2012
(Bcfe)
1,647.5
(255.6)
225.1
(283.5)
490.7
1,824.2
Proved undeveloped reserves at January 1,
Transferred to proved developed reserves
Purchase of reserves in place
Revisions to previous estimates (1)
Extensions and discoveries
Proved undeveloped reserves at December 31, (2)
____________________________
(1) The decrease was primarily related to downward pricing related revisions for Haynesville/Cotton Valley, resulting
from lower natural gas prices.
(2) All of QEP Energy's PUDs at December 31, 2012, are scheduled to be developed within five years from the date such
locations were initially disclosed as PUDs, except for 200 Bcfe of reserves located within the northern portion of the
Company's Pinedale Anticline leasehold in western Wyoming. Long-term development of natural gas reserves in
Pinedale is governed by the BLM's September 2008, ROD on the FSEIS. Under the ROD, QEP Energy is allowed to
drill and complete wells year-round in designated concentrated development areas. The ROD contains additional
requirements and restrictions on the sequence of development, which require the Company to develop its leasehold
from the south to the north. These restrictions result in protracted, phased development that is beyond the control of
the Company. The Company has an ongoing development plan and the financial capability to continue development
in the manner estimated.
The costs incurred to continue the development of PUDs were approximately $513.0 million, $533.6 million and $434.2
million for the years ended December 31, 2012, 2011 and 2010, respectively. The costs incurred in 2012 related to the drilling
of PUDs in QEP's development projects. This investment resulted in the transfer in 2012 of 255.6 Bcfe of reserves from proved
undeveloped to proved developed, representing 16% of the Company's total proved undeveloped reserves as of December 31,
2011.
Estimated future development costs relating to the development of PUDs are projected to be approximately $1,042.5 million in
2013, $871.1 million in 2014 and $814.5 million in 2015. Estimated future development costs include capital spending on
major development projects, some of which will take several years to complete. PUDs related to major development projects
will be reclassified to proved developed reserves when production commences.
27
Internal Controls Over Proved Reserve Estimates, Technical Qualifications and Technologies Used
Estimates of proved gas and oil reserves have been completed in accordance with professional engineering standards and the
Company's established internal controls, which includes the compliance oversight of a multi-functional reserves review
committee reporting to the Company's Board of Directors. We retained Ryder Scott Company, independent oil and gas reserve
evaluation engineering consultants ("Ryder Scott"), to prepare the estimates of 100% of our proved reserves as of December
31, 2012, 2011 and 2010. The individual at Ryder Scott who was responsible for overseeing the preparation of our reserve
estimates as of December 31, 2012, is a registered Professional Engineer in the State of Colorado and graduated with a Masters
of Science degree in Geological Engineering from the University of Missouri at Rolla in 1976. The individual has over thirty
years experience in the Petroleum Industry, including experience estimating and evaluating petroleum reserves. A more detailed
letter of the individual's professional qualifications has been filed as part of Exhibit 99.1 to this report.
The individual at QEP Resources responsible for insuring the accuracy of the reserve estimate preparation material provided to
Ryder Scott and reviewing the estimates of reserves received from Ryder Scott is our Chief Engineer. This individual is a
member of the Society of Petroleum Engineers and graduated with a Bachelors of Science degree in Geological Engineering
from South Dakota School of Mines and Technology in 1979. He is a registered Professional Petroleum Engineer in the state of
Colorado. This individual has over 30 years experience in the Petroleum Industry, including more than 20 years reservoir
engineering experience in most of the active domestic basins in the U.S.
To establish reserves, the SEC allows a company to use technologies that have been proved effective by actual production from
projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes
reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that
have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in
the formation being evaluated or in an analogous formation. A variety of methodologies were used to determine our proved
reserve estimates. The principal methodologies employed are performance, analogy, volumetric methods or a combination of
methods.
All of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods.
Performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of historical
production data available through December 2012 in those cases where such data were considered to be definitive. For wells
currently on production, forecasts of future production rates are based on historical performance data. If no production decline
trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where
appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of
the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.
Approximately 99% of QEP's proved developed non-producing and undeveloped reserves included in this Annual Report on
Form 10-K were estimated by analogy. The remaining one percent of such reserves were estimated by the volumetric method.
The volumetric analysis utilized pertinent well data furnished to Ryder Scott by QEP or obtained from available public data
sources through December 2012. Test data and other related information were used to estimate the anticipated initial production
rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to
commence at an anticipated date furnished by QEP. Wells or locations that are not currently producing may start producing
earlier or later than anticipated in these estimates due to unforeseen factors causing a change in the timing to initiate
production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or
recompleting wells and/or constraints set by regulatory bodies. The future production rates from wells currently on production
or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not
limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline
capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.
Some combination of these methods is used to determine reserve estimates in substantially all of QEP's fields.
Refer to Note 17 - Supplemental Gas and Oil Information (Unaudited), of the consolidated financial statements included in
Item 8 of Part II of this Annual Report on Form 10-K for additional information pertaining to QEP Energy's proved reserves as
of the end of each of the last three years.
In addition to this filing, QEP Energy will file reserves estimates as of December 31, 2012, with the Energy Information
Administration of the Department of Energy on Form EIA-23. Although QEP uses the same technical and economic
assumptions when it prepares the EIA-23 as used to estimate reserves for this Annual Report on Form 10-K, it is obligated to
report reserves for only wells it operates, not for all of the wells in which it has an interest, and to include the reserves
attributable to other owners in such wells.
28
Production, Production Prices and Production Costs
The following table sets forth the net production volumes, the field-level prices per Mcf of natural gas, per bbl of oil and per
bbl of NGL produced, and the operating expenses per Mcfe for the years ended December 31, 2012, 2011 and 2010:
Year Ended December 31,
2011
2010
2012
QEP Energy
Volumes produced and sold
Natural gas (Bcf)
Oil (MMbbl)
NGL (MMbbl)
Total equivalent production (Bcfe)
Average field-level price (1)
Natural gas (per Mcf)
Oil (per bbl)
NGL (per bbl)
Lifting costs (per Mcfe)
Lease operating expense
Production taxes
Total lifting costs
249.3
6,306.9
5,349.0
319.2
236.4
3,741.3
2,715.6
275.2
203.8
2,979.8
1,225.8
229.0
$
$
$
2.68
84.45
34.43
0.55
0.30
0.85
$
$
$
3.95
86.20
47.76
0.54
0.36
0.90
$
$
$
4.18
69.39
39.04
0.56
0.34
0.90
____________________________
(1) The average field-level price does not include the impact of settled commodity price derivatives.
A summary of natural gas production by major geographical area is shown in the following table:
Year ended December 31,
2011
2010
2012
Change
2012 vs. 2011
2011 vs. 2010
QEP Energy - Natural gas (Bcf)
Northern Region
Pinedale
Williston Basin
Uinta Basin
Legacy
Southern Region
Haynesville/Cotton Valley
Midcontinent
Total production
77.4
0.9
16.3
11.4
112.0
31.3
249.3
69.3
0.1
14.9
12.1
107.1
32.9
236.4
65.1
—
14.9
13.7
79.3
30.8
203.8
8.1
0.8
1.4
(0.7)
4.9
(1.6)
12.9
4.2
0.1
—
(1.6)
27.8
2.1
32.6
29
A summary of oil production by major geographical area is shown in the following table:
Year ended December 31,
2011
2010
2012
Change
2012 vs. 2011
2011 vs. 2010
QEP Energy - Oil (Mbbl)
Northern Region
Pinedale
Williston Basin
Uinta Basin
Legacy
Southern Region
Haynesville/Cotton Valley
Midcontinent
Total production
664.4
3,029.5
890.9
297.6
43.4
1,381.1
6,306.9
583.8
1,133.5
866.7
271.0
51.0
835.3
3,741.3
551.8
478.7
957.1
269.5
78.4
644.3
2,979.8
80.6
1,896.0
24.2
26.6
(7.6)
545.8
2,565.6
32.0
654.8
(90.4)
1.5
(27.4)
191.0
761.5
A summary of NGL production by major geographical area is shown in the following table:
Year ended December 31,
2011
2010
2012
Change
2012 vs. 2011
2011 vs. 2010
QEP Energy - NGL (Mbbl)
Northern Region
Pinedale
Williston Basin
Uinta Basin
Legacy
Southern Region
Haynesville/Cotton Valley
Midcontinent
Total production
3,054.3
197.1
371.1
100.1
8.5
1,617.9
5,349.0
1,099.6
29.5
106.4
100.5
8.4
1,371.2
2,715.6
—
3.9
121.5
97.9
5.5
997.0
1,225.8
1,954.7
167.6
264.7
(0.4)
0.1
246.7
2,633.4
1,099.6
25.6
(15.1)
2.6
2.9
374.2
1,489.8
A summary of natural gas equivalent total production by major geographical area is shown in the following table:
Year ended December 31,
2011
2010
2012
Change
2012 vs. 2011
2011 vs. 2010
QEP Energy - Total Production (Bcfe)
Northern Region
Pinedale
Williston Basin
Uinta Basin
Legacy
Southern Region
Haynesville/Cotton Valley
Midcontinent
Total production
Northern Region
99.7
20.3
23.9
13.7
112.3
49.3
319.2
79.4
7.1
20.8
14.2
107.5
46.2
275.2
68.5
2.9
21.4
15.8
79.8
40.6
229.0
20.3
13.2
3.1
(0.5)
4.8
3.1
44.0
10.9
4.2
(0.6)
(1.6)
27.7
5.6
46.2
Pinedale
Net production from the Pinedale Anticline, located in western Wyoming, grew 26% to 99.7 Bcfe during 2012, compared to the
year earlier. Net production from Pinedale grew 16% to 79.4 Bcfe during 2011, compared to a year earlier. Pinedale production
growth in 2012 and 2011 was driven by increased drilling activity over that period and the fee-based processing agreement at
Blacks Fork II entered into in the third quarter of 2011 between QEP Energy and QEP Field Services. As a result of the
processing agreement, QEP Energy's NGL production at Pinedale during 2012, was 3,054.3 Mbbl, contrasted with 1,099.6
30
Mbbl in the comparable 2011 period. During the years ended December 31, 2012, 2011 and 2010, Pinedale's production
represented 31%, 29% and 30% of QEP Energy's total production, respectively.
Williston Basin
In the Williston Basin, production increased 186% to 20.3 Bcfe during 2012, from the year earlier, and increased 145% during
2011, compared to 2010, due to increased oil-directed drilling activity in the basin. In addition, the 2012 Acquisition
contributed 5.2 Bcfe of increased production in the fourth quarter 2012. During the years ended December 31, 2012, 2011 and
2010, Williston Basin production represented 6%, 3% and 1% of QEP Energy's total production, respectively.
Uinta Basin
In the Uinta Basin, which is located in eastern Utah, production increased 15% to 23.9 Bcfe during 2012 due to increased
drilling activity in the Lower Mesaverde formation in the Red Wash Unit. NGL production increased 264.7 Mbbl during 2012
compared to 2011, primarily as a result of QEP Energy executing a cryogenic, fee-based processing agreement with QEP Field
Services for a portion of the Red Wash Unit's natural gas production in mid-2012. During 2011, production decreased 3% from
decreased drilling activity, despite a first quarter 2011 prior-period adjustment of QEP's ownership interest within a federal unit
participating area, which resulted in a positive adjustment to reported volumes of 1.6 Bcfe. During the years ended December
31, 2012, 2011 and 2010, Uinta Basin production represented 7%, 8%, and 9%, respectively, of QEP Energy's total production.
Legacy
QEP Energy's Legacy properties include all Northern Region Rockies properties except those at Pinedale, the Williston Basin
and the Uinta Basin. Legacy's net production during 2012, decreased 4% to 13.7 Bcfe and decreased 10% during the year ended
December 31, 2011. The decreased production was primarily due to declining production on older wells partially offset by
drilling activity in the Powder River Basin. During both the years ended December 31, 2012 and 2011, Legacy's production
represented 4% of QEP Energy's total production and 7% during the year ended December 31, 2010.
Southern Region
Haynesville/Cotton Valley
Net production from the Haynesville Shale and Cotton Valley's tight sand gas plays in northwest Louisiana increased 4% to
112.3 Bcfe during 2012 when compared to 2011. The increase in 2012 was due to the completion of several high-rate wells in
early 2012 that were drilled during the latter half of 2011. QEP Energy has discontinued operated development drilling in the
Haynesville Shale and Cotton Valley's tight sand gas plays in response to depressed natural gas prices. QEP Energy expects
production from the Haynesville/Cotton Valley to continue to decline from its peak in the second quarter of 2012 as the last
operated rig was released in July 2012. In addition, the completion of five wells that were drilled and cased in 2012 were
completed in January 2013. Net production in the Haynesville/Cotton Valley area grew 35% to 107.5 Bcfe during 2011
compared to 2010, due to the Company's active drilling in the play in 2011. During the years ended December 31, 2012, 2011
and 2010, Haynesville/Cotton Valley's production comprised 35%, 39% and 35% of QEP Energy's total production,
respectively.
Midcontinent
Net production in the Midcontinent grew 7% to 49.3 Bcfe during 2012 compared to 2011, driven by a 65% increase in crude oil
production and an 18% increase in NGL production. Net production in the Midcontinent grew 14% to 46.2 Bcfe during 2011
compared to 2010. Midcontinent production growth in 2012 and 2011 was driven by the continued development of the Granite
Wash, Marmaton and Tonkawa plays in Texas and western Oklahoma and the Woodford "Cana" Shale liquids-rich gas play in
the Anadarko Basin of western Oklahoma. During the years ended December 31, 2012, 2011 and 2010, Midcontinent's
production represented 15%, 17% and 18% of QEP Energy's total production, respectively.
31
Productive Wells
The following table summarizes the Company's productive wells as of December 31, 2012, all of which are located in the U.S.:
Northern Region
Pinedale
Williston Basin
Uinta Basin
Legacy
Southern Region
Haynesville/Cotton Valley
Midcontinent
Total productive wells
Natural gas
Oil
Total
Gross
Net
Gross
Net
Gross
Net
715
—
685
787
815
2,522
5,524
450
—
497
248
469
763
2,427
—
263
1,771
381
1
429
2,845
—
108
209
133
—
98
548
715
263
2,456
1,168
816
2,951
8,369
450
108
706
381
469
861
2,975
The term "gross" refers to all wells or acreage in which QEP has at least a partial working interest and the term "net" refers to
QEP's ownership represented by that working interest. Although many wells produce both natural gas and oil, and many natural
gas wells also have allocated NGL volumes from processing, a well is categorized as either a natural gas or an oil well based
upon the ratio of gas to oil produced at the wellhead. Each gross well completed in more than one producing zone is counted as
a single well. At December 31, 2012, the Company had 77 gross wells with completions in more than one reservoir.
The Company also holds numerous overriding royalty interests in oil and gas wells, a portion of which are convertible to
working interests after recovery of certain costs by third parties. Once the overriding royalty interest are converted to working
interests, these wells are included in the Company's gross and net well count.
32
Leasehold Acreage
The following table summarizes developed and undeveloped leasehold acreage in which the Company owns a working interest
or mineral interest as of December 31, 2012. "Undeveloped Acreage" includes leasehold interests that already may have been
classified as containing proved undeveloped reserves and unleased mineral interest acreage owned by the Company. Excluded
from the table is acreage in which the Company's interest is limited to royalty, overriding royalty and other similar interests. All
leasehold acres are located in the U.S.
Developed Acres (1)
Net
Gross
Undeveloped Acres (2)
Net
Gross
Total Acres
Gross
Net
Northern Region
Colorado
Montana
New Mexico
North Dakota
South Dakota
Wyoming
Utah
Other
Southern Region
Arkansas
Kansas
Louisiana
Oklahoma
Texas
Other
Total
158,865
33,245
94,169
97,222
40
272,964
191,247
13,986
40,423
32,224
79,652
599,554
130,241
—
1,743,832
106,062
10,776
66,433
42,523
40
159,598
147,772
3,723
103,455
343,606
34,689
214,232
204,798
351,361
221,511
157,059
30,624
62,764
12,714
85,834
107,551
247,842
140,107
42,129
11,352
13,368
65,103
276,764
42,744
—
946,258
2,940
52,379
2,205
1,884
17,205
2,165
449,006
45,893
1,757
2,184,891
132,443
45,091
1,300
929,653
1,048,560
176,134
1,757
3,928,723
262,320
376,851
128,858
311,454
204,838
624,325
412,758
171,045
—
43,363
84,603
81,857
136,686
73,540
79,147
128,357
107,591
407,440
287,879
45,852
—
13,236
30,573
67,268
409,207
87,835
1,300
1,875,911
____________________________
(1) Developed acreage is leased acreage assigned to productive wells.
(2) Undeveloped acreage is leased acreage on which wells have not been drilled or completed to a point that would permit
the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved
reserves.
Expiring Leaseholds
A portion of the leases summarized in the preceding table will expire at the end of their respective primary terms unless the
leases are renewed or drilling or production has occurred on the acreage subject to the lease prior to that date. Leases held by
production remain in effect until production ceases. The following table sets forth the gross and net undeveloped acres subject
to leases summarized in the preceding table that will expire during the periods indicated:
Year ending December 31,
2013
2014
2015
2016
2017 and later
Total
Undeveloped Acres Expiring
Net
Gross
107,088
59,538
90,924
35,496
116,851
409,897
62,324
43,584
72,145
32,921
112,614
323,588
33
Drilling Activity
The following table summarizes the number of development and exploratory wells drilled during the years indicated:
Developmental Wells
Exploratory Wells
Productive
Dry
Productive
Dry
Gross
Net
Gross
Net
Gross
Net
Gross
Net
Year Ended December 31, 2012
Northern Region
Pinedale
Williston Basin
Uinta Basin
Legacy
Southern Region
Haynesville/Cotton Valley
Midcontinent
Total
Year Ended December 31, 2011
Northern Region
Pinedale
Uinta Basin
Legacy (1)
Southern Region
Haynesville/Cotton Valley
Midcontinent
Total
Year Ended December 31, 2010
Northern Region
Pinedale
Uinta Basin
Legacy (1)
Southern Region
Haynesville/Cotton Valley
Midcontinent
Total
____________________________
102.0
88.0
254.0
31.0
35.0
157.0
667.0
105.0
176.0
85.0
91.0
221.0
678.0
103.0
188.0
42.0
85.0
98.0
516.0
73.3
28.0
45.1
6.6
15.7
32.2
200.9
71.6
6.3
22.5
36.7
39.6
176.7
72.5
23.9
7.7
44.0
22.4
170.5
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1.0
—
2.0
—
3.0
—
—
—
6.0
—
6.0
—
—
—
—
—
0.6
—
1.6
—
2.2
—
—
—
1.7
—
1.7
—
—
—
33.0
—
33.0
16.2
—
16.2
—
—
—
—
—
—
—
—
—
—
2.0
4.0
6.0
—
—
1.0
1.0
—
2.0
—
—
—
—
—
—
—
—
—
—
0.7
1.9
2.6
—
—
0.9
1.0
—
1.9
(1) Due to the 2012 Acquisition, the Company began breaking out the results of Williston Basin from Legacy in 2012.
The Legacy well totals for the years ended December 31, 2011 and 2010, include the total development and
exploratory wells drilled in the Williston Basin.
34
The following table presents operated and non-operated well completions for the year ended December 31, 2012:
Northern Region
Pinedale
Williston Basin
Uinta Basin
Legacy
Southern Region
Haynesville/Cotton Valley
Midcontinent
Operated Completions
Net
Gross
Non-operated Completions
Gross
Net
102
28
48
7
29
26
73.3
24.2
45.2
4.6
16.5
20.4
—
60
207
24
8
131
—
3.9
0.5
2.0
0.8
11.8
The following table presents operated and non-operated wells drilling and waiting on completion at December 31, 2012:
Operated
Non-operated
Drilling
Waiting on
completion
Drilling
Waiting on
completion
Gross
Net
Gross
Net
Gross
Net
Gross
Net
2
11
8
—
—
3
2.0
9.4
8.0
—
—
2.1
63
9
3
—
5
10
45.9
8.0
3.0
—
2.4
8.8
—
16
—
6
—
6
—
1.1
—
0.2
—
0.5
—
23
—
—
—
35
—
0.8
—
—
—
1.6
Northern Region
Pinedale (1)
Williston Basin
Uinta Basin
Legacy
Southern Region
Haynesville/Cotton Valley
Midcontinent
____________________________
(1) QEP suspends Pinedale completion operations during the coldest months of the winter, generally from December to
mid-March.
Delivery Commitments
The Company sells NGL under a term sales agreement that contains a delivery commitment for 8,500 barrels per day of NGL
extracted at several of QEP Field Services' gas processing facilities in the Northern Region. The agreement, which was
effective May 1, 2010, extends for a period of seven years and contains terms and conditions customary for an agreement of
this type in the oil and gas industry. The Company believes that the reserves dedicated to its gas processing facilities and
projected processing volumes are adequate to satisfy its delivery commitments under this agreement.
The Company is a party to various long-term sales commitments for physical delivery of natural gas with future firm delivery
commitments as follows:
Period
2013
2014
2015
Delivery
Commitments
(millions of MMBtu)
164.7
54.8
29.8
These commitments are physical delivery obligations with prices related to the prevailing index prices for natural gas at the
time of delivery. None of these commitments require the Company to deliver natural gas produced specifically from any of the
Company's properties. The Company believes that its production and reserves are adequate to meet these term sales
commitments. If for some reason the Company's natural gas production is not sufficient to satisfy its term sales commitments,
the Company believes it can purchase sufficient volumes of natural gas in the market at index-related prices to satisfy its
35
commitments. See also Item 7 "Contractual Cash Obligations and Other Commitments" for discussion of firm transportation
and storage commitments related to natural gas deliveries.
In addition, none of the Company's production from QEP Energy's owned properties is subject to any priorities, proration or
third-party imposed curtailments that may affect quantities delivered to its customers, any priority allocations or price
limitations imposed by federal or state regulatory agencies, or any other factors beyond the Company's control that may affect
its ability to meet its contractual obligations other than those discussed in Item 1A - Risk Factors, in this Annual Report on
Form 10-K.
Midstream Field Services – QEP Field Services
QEP Field Services owns 1,950 miles of gathering lines in Utah, Wyoming, Colorado, Louisiana and North Dakota. At
December 31, 2012, QEP Field Services owns six processing plants, which extract NGL from the natural gas stream and have
an aggregate capacity of 1.37 Bcf per day of unprocessed natural gas. In addition, QEP Field Services owns treating facilities in
northwest Louisiana which remove impurities from the natural gas stream and have an aggregate capacity of 600 MMcf per day
of untreated natural gas. QEP Field Services also owns compression facilities and field dehydration and measurement systems.
The 21-mile, 20-inch diameter pipeline owned by Rendezvous Pipeline can deliver up to 300 MMcf of natural gas per day to
the Kern River Pipeline. QEP Field Services' partnership facilities include the RGS system, consisting of 300 miles of gathering
lines and associated field equipment, the UBFS system, which consists of 78 miles of gathering lines and associated field
equipment, and the Three Rivers system, which consists of 52 miles of gathering lines and associated field equipment. QEP
Field Services Company owns a 60 mile crude oil pipeline regulated by FERC under the ICA.
In February 2013, QEP Field Services put into service the 150 MMcf per day cryogenic Iron Horse II processing plant, an
expansion of its Stagecoach and Iron Horse processing complex in the Uinta Basin of eastern Utah. The plant predominantly
provides fee-based processing services to third parties and affiliates.
Energy Marketing – QEP Marketing
QEP Marketing owns and operates an underground gas storage reservoir in southwestern Wyoming. The reservoir has a gas
storage capacity of approximately 8 Bcf, comprised of an inventory of approximately 4 Bcf of QEP Marketing-owned cushion
gas and working gas storage capacity of about 4 Bcf.
ITEM 3. LEGAL PROCEEDINGS
QEP is a defendant in a number of lawsuits and is involved in governmental proceedings and regulatory controls arising in the
ordinary course of business. QEP is also subject to various environmental-remediation and reclamation obligations arising from
federal, state, and local laws and regulations. While the ultimate outcome and impact on QEP cannot be predicted with
certainty, except as discussed below, management does not believe that the resolution of pending proceedings will materially
affect the Company's consolidated financial position, results of operations, or cash flows.
Chieftain Royalty Company v. QEP Energy Company, Case No CJ2011-1, U. S. District Court for the Western District of
Oklahoma. This statewide class action was filed on January 20, 2011, on behalf of QEP's Oklahoma royalty owners asserting
various claims for damages related to royalty valuation on all of QEP's Oklahoma wells operated by QEP or from which QEP
marketed gas. Claims included breach of contract, breach of fiduciary duty, fraud, unjust enrichment, tortious breach of
contract, conspiracy, and conversion, based generally on asserted improper deduction of post-production costs. The Court
certified the class as to the breach of contract, breach of fiduciary duty and unjust enrichment claims. The parties successfully
mediated the case in January 2013. On February 13, 2013, the parties executed a Stipulation and Agreement of Settlement (the
Chieftain Settlement Agreement) providing for a cash payment from QEP to the class in the amount of $115.0 million, payable
into an escrow account within five business days following the Court's preliminary approval of the settlement. In consideration
for the settlement payment, QEP will receive a full release of all claims regarding the calculation, reporting and payment of
royalties from the sale of natural gas and its constituents for all periods prior to February 28, 2013, and all class members are
enjoined from asserting claims related to such royalties. As part of the Chieftain Settlement Agreement, the parties also agreed
on the methodology for the calculation and payment of future royalties payable by QEP, or its successors and assigns, under all
class leases for the life of such leases. The Court has entered a Preliminary Order Approving Class Action Settlement.
Questar Gas Company v. QEP Field Services Company, Civil No. 120902969, Third Judicial District Court, State of Utah. QEP
Field Services' former affiliate Questar Gas Company (QGC) filed this complaint in state court in Utah on May 1, 2012,
asserting claims for breach of contract and breach of implied covenant of good faith and fair dealing, for an accounting and
declaratory judgment related to a 1993 gathering agreement (1993 Agreement) entered into when the parties were affiliates.
36
Under the 1993 Agreement, QEP Field Services provides gathering services for producing properties developed by former
affiliate Wexpro Company on behalf of QGC's utility ratepayers. The core dispute pertains to the annual calculation of the
gathering rate, which is based on a cost of service concept expressed in the 1993 Agreement and in a 1998 amendment. The
annual gathering rate has been calculated in the same manner under the contract since it was amended in 1998, without any
prior objection or challenge by QGC. Specific monetary damages are not asserted. Also, on May 1, 2012, QEP Field Services
Company filed a legal action against QGC entitled QEP Field Services Company v. Questar Gas Company, in the Second
District Court in Denver County, Colorado, seeking declaratory judgment relating to its gathering service and charges under the
same agreement.
In October 2009, the Company received a cease and desist order from the U.S. Army Corps of Engineers (COE) to refrain from
unpermitted work resulting in the discharge of dredged and/or fill material into waters of the United States at three sites located
in Caddo and Red River Parishes, Louisiana. EPA Region 6 has assumed lead responsibility for enforcement of the cease and
desist order and any possible future orders for the removal of unauthorized fills and/or civil penalties under the Clean Water
Act. In 2012, the Company completed a field audit, which identified 112 additional instances affecting approximately 90 acres
where work may have been conducted in violation of the Clean Water Act. The Company has disclosed each of these instances
to the EPA under the EPA's Audit Policy (to reduce penalties) and to the COE. The Company is working with the EPA and the
COE to resolve these matters, which will require the Company to undertake certain mitigation and permitting activities, and
may require the Company to pay a monetary penalty. At this time, QEP is unable to estimate the potential loss related to this
matter, but believes it exceeds the $100,000 threshold for disclosure of environmental matters.
See also Note 9 (Commitments and Contingencies) to the consolidated financial statements in Item 8 of Part II of this Annual
Report.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
37
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
PART II
QEP's common stock is listed and traded on the New York Stock Exchange (NYSE:QEP). As of January 31, 2013, QEP had
7,260 shareholders of record. The declaration and payment of dividends are at the discretion of QEP's Board of Directors and
the amount thereof will depend on QEP's results of operations, financial condition, contractual restrictions, cash requirements,
future prospects and other factors deemed relevant by the Company's Board of Directors. The Company expects that cash
dividends will continue to be paid in the future.
The following table is a summary of the high and low sales price per share of QEP's common stock on the NYSE and quarterly
dividends paid per share:
2012
First quarter
Second quarter
Third quarter
Fourth quarter
Total
2011
First quarter
Second quarter
Third quarter
Fourth quarter
Total
Stock Performance Graph
High price
Low price
(per share)
Dividend
$
$
$
$
35.61
32.03
33.50
32.92
42.00
43.70
45.20
38.44
$
26.73
24.35
26.12
25.99
$
$
$
35.78
37.11
26.52
23.56
0.02
0.02
0.02
0.02
0.08
0.02
0.02
0.02
0.02
0.08
The following stock performance information in this Item 5 of this Annual Report on Form 10-K is not deemed to be "soliciting
material" or to be "filed" with the SEC or subject to Regulation 14A or 14C under the Securities Exchange Act of 1934 or to the
liabilities of Section 18 of the Securities Exchange Act of 1934, and will not be deemed to be incorporated by reference into
any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent QEP specifically
incorporate it by reference into such a filing.
The performance presentation shown below is being furnished as required by applicable rules of the SEC and was prepared
using the following assumptions:
• A $100 investment was made in QEP's common stock, the S&P 500 Index and the Company's peer group as of
•
July 1, 2010, which is the date when QEP's common stock began trading on the NYSE;
Investment in the Company's peer group was weighted based on the stock market capitalization of each individual
company within the peer group at the beginning of each period for which a return is indicated; and
• Dividends were reinvested on the relevant payment dates.
QEP's peer group, as defined, consists of the following companies: Cabot Oil & Gas Corporation, Cimarex Energy Company,
Denbury Resources Inc., EOG Resources, Inc., Forest Oil Corporation, Newfield Exploration Company, Noble Energy, Inc.,
Pioneer Natural Resources Company, Plains Exploration & Production Company, Quicksilver Resources, Inc., Range
Resources Corporation, Southwestern Energy Company, Ultra Petroleum Corporation and Whiting Petroleum Corporation.
Management believes this peer group provides a meaningful comparison based upon the Company's review of asset size,
geographic location of assets, market capitalization, revenues, culture and performance, among other things.
38
Recent Sales of Unregistered Securities; Purchases of Equity Securities by QEP and Affiliated Purchasers
QEP had no unregistered sales of securities, or purchases of equity securities by QEP or affiliated purchasers, during the fourth
quarter of 2012.
39
ITEM 6. SELECTED FINANCIAL DATA
Selected financial data for the five years ended December 31, 2012, is provided in the table below. Refer to Item 7 and Item 8
in Part II of this Annual Report on Form 10-k for discussion of facts affecting the comparability of the Company's financial
data.
Results of Operations (1)
Revenues (2)
Operating (loss) income
Income from continuing operations
Discontinued operations, net of income tax
Net income attributable to QEP
Earnings per common share attributable to QEP
Basic from continuing operations
Basic from discontinued operations
Basic total
Diluted from continuing operations
Diluted from discontinued operations
Diluted total
Dividends per share
Weighted-average common shares outstanding
Used in basic calculation
Used in diluted calculation
Financial Position
Total Assets at December 31,
Capitalization at December 31,
Long-term debt
Total equity
Total Capitalization
Cash Flow From Continuing Operations
Net cash provided by operating activities
Capital expenditures
Net cash used in investing activities
Net cash provided by (used in) financing activities
Non-GAAP Measures
Adjusted EBITDA (3)
____________________________
$
$
$
$
$
$
2012
2,349.8
(133.3)
132.0
—
128.3
0.72
—
0.72
0.72
—
0.72
0.08
177.8
178.7
Year Ended December 31,
2010
(in millions, except per share information)
2009
2011
$
$
$
$
$
$
$
$
$
$
$
$
3,159.2
505.9
270.4
—
267.2
1.51
—
1.51
1.50
—
1.50
0.08
176.5
178.4
$
$
$
$
$
$
2,300.6
545.3
285.9
43.2
326.2
1.61
0.25
1.86
1.60
0.24
1.84
0.04
175.3
177.3
$
$
$
$
2,011.2
585.5
215.4
80.7
293.5
1.23
0.46
1.69
1.21
0.46
1.67
$
— $
174.1
176.3
2008
2,360.9
933.2
520.6
73.9
585.5
2.96
0.43
3.39
2.90
0.42
3.32
—
172.8
176.1
$
9,108.5
$
7,442.7
$
6,785.3
$
6,481.4
$
6,342.7
3,206.9
3,313.7
$
6,520.6
1,296.0
(2,799.7)
(2,794.5)
1,498.5
$
$
1,679.4
3,352.1
5,031.5
1,292.6
(1,431.1)
(1,422.9)
130.3
$
$
1,530.8
3,063.1
4,593.9
997.5
(1,469.0)
(1,390.5)
373.7
$
$
1,348.7
2,808.7
4,157.4
1,149.4
(1,196.9)
(1,146.4)
(8.8)
$
$
1,299.1
2,779.4
4,078.5
1,224.7
(2,136.7)
(2,021.0)
818.7
1,415.5
$
1,386.6
$
1,140.5
$
1,165.5
$
1,310.7
(1) QEP completed a Spin-off from Questar in June 2010 as discussed in more detail in Item 1 of Part I of this Annual
Report on Form 10-K. As a result of the Spin-off, Wexpro's financial results have been reflected as discontinued
operations and all prior periods have been recast.
(2) Revenue for the years ended December 31, 2011 and 2010, reflect the impact of QEP's settled derivative contracts
which during the year ended December 31, 2012, are reflected below operating (loss) income. See Note 6 - Derivative
Contracts, in Part II, Item 8 of this Annual Report on Form 10-K for detailed information on derivative contract
settlements in the years ended December 31, 2012, 2011 and 2010.
40
(3) Adjusted EBITDA is a non-GAAP financial measure. Management defines Adjusted EBITDA as net income before
the following items: separation costs, accrued litigation loss contingency, depreciation, depletion and amortization,
exploration expense, abandonment and impairment, gains and losses from asset sales, unrealized gains and losses on
derivative contracts, interest and other income, loss on early extinguishment of debt, interest expense, income taxes
and discontinued operations. Management focuses on Adjusted EBITDA to assess the Company's operating results.
Management believes Adjusted EBITDA is an important measure of the Company's cash flow and liquidity and its
ability to incur and service debt, fund capital expenditures and make distributions to shareholders, and an important
measure for comparing the Company's financial performance to other gas and oil producing companies.
The following table reconciles QEP Resources' net income to Adjusted EBITDA:
2012
Year Ended December 31,
2010
(in millions, except per share information)
2009
2011
Adjusted EBITDA
Net income attributable to QEP
Net income attributable to noncontrolling interest
$
Net income
Discontinued operations, net of tax
Income from continuing operations
Unrealized (gains) losses on derivative contracts
Net gains from asset sales
Interest and other income
Income taxes
Interest expense
Accrued litigation loss contingency (1)
Separation costs
Loss from early extinguishment of debt
Depreciation, depletion and amortization
Abandonment and impairment
Exploration expenses
$
128.3
3.7
132.0
—
132.0
(63.2)
(1.2)
(6.6)
66.5
122.9
115.0
—
0.6
904.9
133.4
11.2
$
267.2
3.2
270.4
—
270.4
(117.7)
(1.4)
(4.1)
154.4
90.0
—
—
0.7
765.4
218.4
10.5
$
326.2
2.9
329.1
(43.2)
285.9
(121.7)
(12.1)
(2.3)
167.0
84.4
—
13.5
13.3
643.4
46.1
23.0
$
$
293.5
2.6
296.1
(80.7)
215.4
164.0
(1.5)
(4.5)
117.6
70.1
—
—
—
559.1
20.3
25.0
2008
585.5
9.0
594.5
(73.9)
520.6
79.2
(60.4)
(10.2)
283.6
61.7
—
—
—
361.5
45.4
29.3
Adjusted EBITDA
$
1,415.5
$
1,386.6
$
1,140.5
$
1,165.5
$
1,310.7
____________________________
(1) See Note 9 (Commitments and Contingencies) to the consolidated financial statements in Item 8 of Part II of this
Annual Report.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide a
reader of the financial statements with a narrative from the perspective of management on the financial condition, results of
operations, liquidity and certain other factors that may affect the Company's operating results. MD&A should be read in
conjunction with the consolidated financial statements and related notes included in Item 8 of Part II of this Annual Report on
Form 10-K.
The following information updates the discussion of QEP's financial condition provided in its 2011 Annual Report on Form 10-
K filing, and analyzes the changes in the results of operations between the years ended December 31, 2012 and 2011, and
between the years ended December 31, 2011 and 2010.
OVERVIEW
QEP Resources, Inc. (QEP or the Company) is a holding company with three major lines of business: natural gas and crude oil
exploration and production (QEP Energy); midstream field services (QEP Field Services); and energy marketing (QEP
Marketing).
41
Outlook
The Company has substantial acreage positions and operations in some of the most prolific hydrocarbon resource plays in the
continental United States, including the Williston Basin, Pinedale Anticline, Uinta Basin, Woodford "Cana" and Haynesville
Shale. These resource plays are characterized by unconventional oil or natural gas accumulations in continuous tight sands or
shales that underlie broad geographic areas. The lateral continuity of such resource plays means that aside from wells
abandoned due to mechanical issues, the Company does not expect to drill many unsuccessful wells as it develops these
resource plays. Resource plays allow the Company the opportunity to gain considerable operational efficiencies through high-
density, repeatable drilling and completion operations. The Company has a large inventory of lower-risk, predictable
development drilling locations across its acreage holdings in the onshore United States that provide a solid base for consistent
growth in organic production and reserves. QEP believes that it has one of the lowest cash operating structures among its
exploration and production company peers. However, in certain of its resource plays, QEP, along with its peers, has
experienced increased drilling and completion costs which could impact future drilling plans.
While predominantly a natural gas producer, the Company has increased its focus on growing the relative proportion of crude
oil and NGL production in its exploration and production business. As part of the Company's liquids growth strategy, QEP
Energy completed the 2012 Acquisition during the third quarter of 2012 and acquired oil and gas properties in the Williston
Basin.
During the year ended December 31, 2012, QEP Energy increased its crude oil and NGL production by 80% compared with
2011. During 2012, crude oil and NGL revenue accounted for approximately 52% of QEP Energy's field-level production
revenues.
While QEP believes that it can grow production and reserves from its extensive inventory of identified drilling locations, the
Company continues to evaluate acquisition opportunities that might create significant long-term value. QEP believes that its
experience, expertise, and substantial presence in its core operating areas, combined with its low-cost operating model and
financial strength, enhance its ability to pursue acquisition opportunities. In addition, the Company is seeking to divest select
non-core portfolio assets to redirect capital towards higher-return projects.
QEP owns and operates gathering and transmission pipelines and natural gas processing and treatment facilities in many of its
core producing areas. These assets enable the Company to promptly connect its wells, better control its costs, and generate a
significant, consistent revenue stream by providing gathering and processing services to third parties. In early January 2013,
QEP announced that its Board of Directors had authorized the formation of a Master Limited Partnership (MLP) to support the
growth of QEP's midstream business. QEP expects to file a registration statement with the SEC in the second quarter of 2013
for an initial public offering of common units of the MLP. QEP plans to contribute a majority of its gathering assets in
Wyoming and North Dakota to the MLP. QEP expects to sell a minority interest in the MLP and raise $300 million to $400
million in gross proceeds. QEP plans to use the proceeds from such offering to fund ongoing operations, to repay debt under
the Company's revolving credit facility and for general corporate purposes. QEP's announcement of this plan did not, and this
disclosure does not, constitute an offer to sell or the solicitation of an offer to buy any securities and shall not constitute an
offer, solicitation or sale in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or
qualification under the securities laws of that jurisdiction.
Financial and Operating Results
During the year ended December 31, 2012, QEP Energy experienced substantial production growth, while QEP Field Services
increased system throughput. For the years ended December 31, 2012 and 2011, QEP Energy reported total equivalent
production of 319.2 Bcfe and 275.2 Bcfe, increases of 16% and 20%, from the 2011 and 2010 comparable prior periods,
respectively. QEP Field Services' gathering throughput volumes during the years ended December 31, 2012 and 2011, were 2%
and 4% higher, respectively, than the 2011 and 2010 comparable periods. During the years ended December 31, 2012 and 2011,
QEP Field Services reported 3% and 42% increases in NGL sales volumes, respectively. QEP Field Services' fee-based
processing volumes were 4% and 6% higher during the years ended December 31, 2012 and 2011, respectively, when
compared to the prior year periods.
The increases in production at QEP Energy and system throughput at QEP Field Services were offset by declining commodity
prices at both QEP Energy and QEP Field Services. For the years ended December 31, 2012, 2011 and 2010, QEP Energy's
average net realized equivalent prices (including realized commodity derivative impact) were $5.48 per Mcfe, $5.72 per Mcfe
and $5.81 per Mcfe, respectively. In addition, at QEP Field Services, the increase in NGL sales volumes during 2012, was
offset by a decrease in average net realized NGL sales prices. Specifically, during 2012, a 21% decrease in the average net
42
realized NGL sales price occurred, resulting in a 35% decrease to the keep-whole processing margin. During 2011, QEP Field
Services' average net realized sales prices were 34% higher than 2010.
At the end of the third quarter of 2012, QEP Energy acquired oil and gas properties in the Williston Basin for approximately
$1.4 billion. The properties are located in Williams and McKenzie counties of North Dakota, approximately 12 miles west of
QEP's existing core acreage in the Williston Basin. The 2012 Acquisition added revenues of $63.7 million and net income of
$14.9 million to QEP's fourth quarter results.
In the first quarter of 2012, QEP completed a public offering for $500.0 million in aggregate principal amount of 5.375% senior
notes due in October 2022 (2022 Senior Notes). The 2022 Senior Notes were issued at par. The net proceeds of $493.1 million
were used to repay indebtedness under QEP's revolving credit facility.
During the second quarter of 2012, QEP entered into a $300.0 million senior unsecured term loan agreement (Term Loan) with
a group of financial institutions. The Term Loan provides for borrowings at short-term interest rates and contains covenants,
restrictions and interest rates that are substantially the same as the Company's existing revolving credit agreement. The Term
Loan matures in April 2017, and the maturity date may be extended one year with the agreement of the lenders. In conjunction
with the Term Loan, QEP entered into interest rate swap contracts with an aggregate notional amount of $300.0 million that
effectively lock in a fixed rate of 1.07% that QEP will pay over the duration of the Term Loan.
QEP completed a public offering for $650.0 million in aggregate principal amount of 5.25% senior notes due in May 2023
(2023 Senior Notes) in the third quarter of 2012. The 2023 Senior Notes were issued at par. The estimated net proceeds of
approximately $641 million were used to fund a portion of the 2012 Acquisition.
Factors Affecting Results of Operations
Oil, Natural Gas, and NGL Prices
Historically, field-level prices received for QEP's natural gas, NGL, and crude oil production have been volatile and
unpredictable, and that volatility is expected to continue. In recent years, domestic natural gas supply has grown faster than
natural gas demand, driven by advances in drilling and completion technologies, including horizontal drilling and multi-stage
hydraulic fracturing. These changes have allowed producers to extract increased quantities of natural gas from shale, tight sand
formations, and other unconventional reservoirs. Increased natural gas supplies have resulted in downward pressure on natural
gas prices, while concern about the global economy and other factors has created volatility in the price of crude oil. Changes in
the market prices for natural gas, crude oil, and NGL directly impact many aspects of QEP's business, including its financial
condition, revenues, results of operations, planned drilling activity and related capital expenditures, liquidity, rate of growth,
and costs of goods and services required to drill and complete wells, and may impact the carrying value of its oil and natural
gas properties.
QEP uses commodity derivatives to reduce the volatility of the prices QEP receives for a portion of its production and to
protect cash flow and returns on invested capital from a drop in commodity prices. Generally, QEP intends to enter into
commodity derivative contracts for approximately 50% of its forecasted annual production by the end of the first quarter of
each fiscal year. Assuming 2013 annual production of 327.5 Bcfe, QEP Energy had approximately 44% of its forecasted natural
gas, oil and NGL equivalent production covered with fixed-price swaps or costless collars, including 51% of its forecasted
natural gas production covered with fixed-price swaps. See Item 7A of Part II of this Annual Report on Form 10-K for further
details concerning QEP's commodity derivatives transactions. In addition, as a result of the continued relative price relationship
between crude oil, NGL and natural gas prices, QEP Energy has allocated approximately 98% of its 2013 total forecasted
capital expenditure budget to crude oil and liquids-rich natural gas plays.
Unrealized Derivative Gains and Losses
The Company elected to discontinue hedge accounting beginning January 1, 2012, and unrealized gains and losses from mark-
to-market valuations of all derivative positions are reflected as unrealized derivative gains or losses in the Company's
Consolidated Statement of Operations. See Note 6 - Derivative Contracts, to the Consolidated Financial Statements, in Item 8,
Part II of this Annual Report on Form 10-K, for additional information regarding the discontinuance of hedge accounting. The
payments due to or from counterparties on these derivatives will typically be offset by corresponding changes in prices
ultimately received from the sale of QEP's production. QEP has incurred significant unrealized gains and losses in 2012, and in
prior periods and may continue to incur these types of gains and losses in the future.
43
Global Geopolitical and Macroeconomic Factors
QEP continues to monitor the outlook of the global economy, including the European debt crisis and its potential impact on
global economic growth and the banking and financial sectors, political unrest in the Middle East, a slowing of growth in Asia,
particularly China, the United States federal budget deficit, changes in regulatory oversight policy and commodity price
volatility. A dramatic decline in regional or global economic conditions, a major recession or depression, regional political
instability, economic sanctions, war, or other factors beyond the control of QEP could have a significant impact on natural gas,
NGL and crude oil supply, demand and prices, and could materially impact the Company's financial position, results of
operations and cash flow from operations and operating activities.
Supply, Demand and Other Market Risk Factors
U.S. natural gas directed drilling rig count decreased throughout 2012, as producers reduced drilling for natural gas in response
to low natural gas prices. A reduction in natural gas production has lagged the downturn in the natural gas rig count because
natural gas producers have a significant inventory of drilled wells waiting on completion and new high-rate horizontal wells
continue to be completed. As a result of the lag, U.S. natural gas production did not decline in 2012. The U.S. natural gas
market entered the storage injection season with record high inventory levels. However, strong natural gas demand from
electric power generation has resulted in a general firming of natural gas prices during the last half of 2012. Despite increased
stability in natural gas prices during the second half of 2012, QEP expects U.S. natural gas prices to remain volatile and below
the five year average price over the near term. Continued low natural gas prices have caused U.S. E&P companies, including
QEP, to shift capital investments away from predominantly dry gas areas toward plays that are known to have liquids-rich
natural gas and crude oil. This shift in focus has caused domestic NGL production to increase dramatically. Increased NGL
products, warmer-than-average winters, and price dislocations from infrastructure bottlenecks in certain regions, have all
contributed to a weakening in domestic NGL prices, particularly ethane. QEP expects NGL prices to remain volatile for the
foreseeable future. QEP anticipates global crude oil prices to remain near current levels, assuming the global economy and
socio-political backdrops remain relatively stable. Disruption to the global oil supply system, political and/or economic
instability, and/or other factors could trigger additional volatility in crude oil prices. In addition, transportation, refining, or
other infrastructure constraints could introduce significant price differentials between regional markets where QEP sells its
crude oil production and national (NYMEX or Cushing) and global (Brent or U.S. Gulf Coast) markets. Because of the global
and regional price volatility and the uncertainty around the commodity price environment, QEP continues to manage its capital
spending program and financial flexibility accordingly.
Potential for Future Asset Impairments
In 2012, U.S. natural gas prices were lower than in 2011 and 2010. The carrying value of the Company's properties is sensitive
to declines in natural gas, crude oil and NGL prices. These assets are at risk of impairment if future prices for natural gas, crude
oil or NGL prices decline. The cash flow model that the Company uses to assess proved properties for impairment includes
numerous assumptions, such as management's estimates of future oil, gas and NGL production, market outlook on forward
commodity prices, operating and development costs, and discount rates. All inputs to the cash flow model must be evaluated at
each date of estimate. However, a decrease in forward natural gas, crude oil and NGL prices alone could result in an
impairment of properties. For additional information see Item 1A - Risk Factors, of Part I and see Item 8 of Part II, Note 1 -
Significant Accounting Policies, of this Annual Report on Form 10-K. During the year ended December 31, 2012, QEP
recorded abandonment and impairment charges of $133.4 million, on some of its oil and gas properties. The impairment
charges related to the reduced value of certain fields resulting from lower natural gas, crude oil and NGL prices and
impairments of unproven leasehold costs. Proved impairments were primarily the result of lower natural gas and NGL prices
that impacted the carrying value of proved reserves in several Midcontinent (Oklahoma and Texas) and one Uinta Basin
successful efforts pools. Of the $133.4 million abandonment and impairment charge during 2012, $107.6 million related to the
impairment charge on proved properties and $23.7 million related to impairment on unproved properties. Oil and gas properties
and leaseholds in the Southern Region accounted for $104.8 million of the $133.4 million abandonment and impairment
charges during 2012, and $28.6 million related to oil and gas properties and leaseholds in the Northern Region.
RESULTS OF OPERATIONS
Net Income
QEP Resources' net income attributable to QEP during the year ended December 31, 2012, was $128.3 million, or $0.72 per
diluted share, compared to $267.2 million, or $1.50 per diluted share, in 2011. The decrease in net income during 2012, was
due to an 101% decrease in QEP Energy's net income, a 17% decrease in QEP Field Services' net income and an 100%
decrease in QEP Marketing and other net income. QEP Energy's net income decreased during 2012, due to the accrual of a
$115.0 million litigation loss contingency, 4% lower net realized equivalent commodity prices, and a 18% increase in DD&A,
partially offset by a $68.4 million unrealized gain on commodity derivative contracts, $87.9 million lower proved property
impairment charges and production volumes that increased 16%. QEP Field Services' decrease in net income during 2012, was
44
driven by a 35% decrease in the keep-whole processing margin and 7% lower gathering margins. QEP Resources' net income
from continuing operations attributable to QEP in 2011 was $267.2 million, or $1.50 per diluted share, compared to $283.0
million, or $1.60 per diluted share, in 2010. The decrease in 2011 was due to a $99.2 million, or 49%, decline in QEP Energy's
net income, partially offset by a $63.4 million, or 70%, increase in QEP Field Services' net income. QEP Energy's net income
declined in 2011 because of a price-related impairment charge of $195.5 million during 2011 on some of its mature, dry gas,
and higher cost properties in both the Northern and Southern Regions. Offsetting the decline at QEP Energy, QEP Field
Services' increase in net income was driven by higher gathering and processing margins and increased throughput volumes.
The following table provides a summary of net income from continuing operations attributable to QEP by line of business:
Year Ended December 31,
Change
2012 vs. 2011 2011 vs. 2010
QEP Energy
QEP Field Services
QEP Marketing and other
Net income from continuing operations
Earnings per diluted share
Average diluted shares
Adjusted EBITDA
2012
2011
$
$
$
(0.7) $
129.0
—
128.3
0.72
178.7
$
$
$
$
$
104.7
154.5
8.0
267.2
1.50
178.4
2010
(in millions)
$
203.9
91.1
(12.0)
283.0
1.60
177.3
$
$
(105.4) $
(25.5)
(8.0)
(138.9) $
(0.78) $
0.3
(99.2)
63.4
20.0
(15.8)
(0.10)
1.1
Management believes Adjusted EBITDA (a non-GAAP financial measure) is an important measure of the Company's cash
flow, liquidity, and ability to incur and service debt, fund capital expenditures and make distributions to shareholders. The use
of this measure allows investors to understand how management evaluates financial performance to make operating decisions
and allocate resources. It is also an important measure for comparing the Company's financial performance to other gas and oil
producing companies.
Management defines Adjusted EBITDA as net income before the following items: separation costs, accrued litigation loss
contingency, depreciation, depletion and amortization, exploration expense, abandonment and impairment, gains and losses
from asset sales, unrealized gains and losses on derivative contracts, interest and other income, loss on early extinguishment of
debt, interest expense, income taxes and discontinued operations.
The following table provides a summary of Adjusted EBITDA by line of business:
QEP Energy
QEP Field Services
QEP Marketing and other
Adjusted EBITDA
Year Ended December 31,
Change
2012
2011
2010
(in millions)
2012 vs. 2011
2011 vs. 2010
$
$
1,133.6
281.1
0.8
1,415.5
$
$
1,057.5
320.3
8.8
1,386.6
$
$
926.2
203.9
10.4
1,140.5
$
$
76.1 $
(39.2)
(8.0)
28.9 $
131.3
116.4
(1.6)
246.1
Adjusted EBITDA increased to $1,415.5 million during the year ended December 31, 2012, compared to $1,386.6 million in
2011. During 2012, QEP Energy's Adjusted EBITDA increased 7%, despite 15% lower net realized natural gas prices and 24%
lower net realized NGL prices. The impact of lower net realized prices during 2012 was offset by a 16% increase in total
production at QEP Energy. QEP Field Services' Adjusted EBITDA decreased 12% due to a decrease in the keep-whole
processing margin and lower gathering margins. Adjusted EBITDA increased 22% to $1,386.6 million for 2011, compared to
$1,140.5 million in the 2010 period, despite an 11% decrease in net realized natural gas prices. The impact of lower net realized
natural gas prices during 2011, was offset by a 20% increase in total production, 30% higher net realized crude oil prices and
22% higher net realized NGL prices in QEP Energy, along with increased gathering margins that were 22% higher and
processing margins that were 93% higher in QEP Field Services.
45
The following table is a reconciliation of Adjusted EBITDA to QEP Resources' net income, the most comparable GAAP
financial measure:
Year Ended December 31,
Change
2012 vs. 2011
2011 vs. 2010
Net income attributable to QEP Resources
$
128.3
$
267.2
$
2012
2011
2010
(in millions)
$
326.2
Net income attributable to noncontrolling interest
Net income
Discontinued operations, net of tax
Income from continuing operations
Unrealized gains on derivative contracts
Net gain from asset sales
Interest and other income
Income tax provision
Interest expense
Accrued litigation loss contingency
Separation costs
Loss on early extinguishment of debt
Depreciation, depletion and amortization
Abandonment and impairment
Exploration expenses
Adjusted EBITDA
3.7
132.0
—
132.0
(63.2)
(1.2)
(6.6)
66.5
122.9
115.0
—
0.6
904.9
133.4
11.2
$ 1,415.5
3.2
270.4
—
270.4
(117.7)
(1.4)
(4.1)
154.4
90.0
—
—
0.7
765.4
218.4
10.5
$ 1,386.6
2.9
329.1
(43.2)
285.9
(121.7)
(12.1)
(2.3)
167.0
84.4
—
13.5
13.3
643.4
46.1
23.0
$ 1,140.5
$
The following table is a reconciliation of QEP Energy Adjusted EBITDA to net income:
Year Ended December 31,
2011
2012
(59.0)
0.3
(58.7)
43.2
(15.5)
4.0
10.7
(1.8)
(12.6)
5.6
—
(13.5)
(12.6)
122.0
172.3
(12.5)
246.1
(138.9) $
0.5
(138.4)
—
(138.4)
54.5
0.2
(2.5)
(87.9)
32.9
115.0
—
(0.1)
139.5
(85.0)
0.7
28.9
$
Change
2010
(in millions)
2012 vs. 2011
2011 vs. 2010
$
$
203.9
(121.7)
(13.7)
(2.1)
119.7
78.5
—
592.5
46.1
23.0
926.2
$
$
(105.4) $
49.3
0.2
(2.2)
(62.2)
34.9
115.0
130.8
(85.0)
0.7
76.1
$
(99.2)
4.0
12.3
(1.9)
(61.8)
3.4
—
114.7
172.3
(12.5)
131.3
Net income from continuing operations attributable
to QEP Energy
$
Unrealized gains on derivative contracts
Net gain from asset sales
Interest and other income
Income tax (benefit) provision
Interest expense
Accrued litigation loss contingency
Depreciation, depletion and amortization
Abandonment and impairment
Exploration expenses
Adjusted EBITDA
(0.7) $
(68.4)
(1.2)
(6.2)
(4.3)
116.8
115.0
104.7
(117.7)
(1.4)
(4.0)
57.9
81.9
—
838.0
133.4
11.2
$ 1,133.6
707.2
218.4
10.5
$ 1,057.5
46
The following table is a reconciliation of QEP Field Services' Adjusted EBITDA to net income:
Year Ended December 31,
2011
2012
Change
2012 vs. 2011 2011 vs. 2010
2010
(in millions)
Net income from continuing operations attributable
to QEP Field Services
$
Net income attributable to noncontrolling interest
Net income
Net gain from asset sales
Interest and other income
Income tax provision
Interest expense
Depreciation, depletion and amortization
Adjusted EBITDA
$
129.0
3.7
132.7
—
(0.2)
71.8
13.6
63.2
281.1
$
$
$
154.5
3.2
157.7
—
(0.1)
93.4
13.6
55.7
320.3
91.1
2.9
94.0
1.6
(0.1)
51.9
7.6
48.9
203.9
$
$
$
(25.5) $
0.5
(25.0)
—
(0.1)
(21.6)
—
7.5
(39.2) $
63.4
0.3
63.7
(1.6)
—
41.5
6.0
6.8
116.4
The following table is a reconciliation of QEP Marketing and other Adjusted EBITDA to net income:
Year Ended December 31,
2011
2012
Change
2012 vs. 2011 2011 vs. 2010
2010
(in millions)
Net income from continuing operations attributable
to QEP Marketing and other
$
Discontinued operations, net of tax
Income from continuing operations
Unrealized loss on derivative contracts
Other income
Income tax (benefit) provision
Interest income, net of interest expense
Separation costs
Loss on early extinguishment of debt
Depreciation, depletion and amortization
Adjusted EBITDA
$
Production
—
—
—
5.2
(0.2)
(1.0)
(7.5)
—
0.6
3.7
0.8
$
$
8.0
—
8.0
—
—
3.1
(5.5)
—
0.7
2.5
8.8
$
31.2
(43.2)
(12.0)
—
(0.1)
(4.6)
(1.7)
13.5
13.3
2.0
10.4
$
(8.0) $
—
(8.0)
5.2
(0.2)
(4.1)
(2.0)
—
(0.1)
1.2
(8.0) $
(23.2)
43.2
20.0
—
0.1
7.7
(3.8)
(13.5)
(12.6)
0.5
(1.6)
$
$
QEP Energy reported production of 319.2 Bcfe during the year ended December 31, 2012, a 16% increase over the 275.2 Bcfe
a year earlier. During the year ended December 31, 2011, QEP Energy reported a 20% increase in production from 2010. On an
energy-equivalent basis, crude oil and NGL comprised approximately 22% of QEP Energy's production for 2012, up from 14%
and 11% during 2011 and 2010, respectively.
A summary of QEP Energy production is shown in the following table:
Year Ended December 31,
2011
2012
2010
Change
2012 vs. 2011 2011 vs. 2010
QEP Energy Production Volumes
Natural gas (Bcf)
Oil (Mbbl)
NGL (Mbbl)
Total production (Bcfe)
Average daily production (MMcfe)
249.3
6,306.9
5,349.0
319.2
872.1
236.4
3,741.3
2,715.6
275.2
753.9
203.8
2,979.8
1,225.8
229.0
627.4
12.9
2,565.6
2,633.4
44.0
118.2
32.6
761.5
1,489.8
46.2
126.5
47
Pricing
A regional comparison of average field-level prices is shown in the following table:
Year Ended December 31,
Change
2012
2011
2010
2012 vs. 2011
2011 vs. 2010
QEP Energy - Average field-level natural gas price (per Mcf)
Northern Region
Southern Region
Average field-level natural gas price
QEP Energy - Average field-level oil price (per bbl)
Northern Region
Southern Region
Average field-level oil price
$
$
2.64
2.70
2.68
$
3.87
4.00
3.95
$
4.11
4.24
4.18
$
83.03
$
84.88
$
67.62
$
89.32
84.45
90.45
86.20
74.93
69.39
QEP Energy - Average field-level NGL price (per bbl)
Northern Region
Southern Region
Average field-level NGL price
$
36.17
$
52.00
$
54.62
$
30.44
34.43
43.66
47.76
35.57
39.04
(1.23) $
(1.30)
(1.27)
(1.85) $
(1.13)
(1.75)
(15.83) $
(13.22)
(13.33)
(0.24)
(0.24)
(0.23)
17.26
15.52
16.81
(2.62)
8.09
8.72
A comparison of net realized average natural gas, oil and NGL prices, including the realized gains and losses on commodity
derivative contracts, is shown in the following table:
Year Ended December 31,
2011 (2)
2010 (2)
2012 (1)
Change
2012 vs. 2011
2011 vs. 2010
Natural gas (per Mcf)
Average field-level price
Commodity derivative impact
Net realized price
Oil (per bbl)
Average field-level price
Commodity derivative impact
Net realized price
NGL (per bbl)
Average field-level price
Commodity derivative impact
Net realized price
Average net equivalent price (per Mcfe)
Average field-level price
Commodity derivative impact
Net realized price
____________________________
$
$
$
$
$
$
$
$
2.68
1.37
4.05
84.45
2.28
86.73
34.43
1.90
36.33
4.34
1.14
5.48
$
$
$
$
$
$
$
$
3.95
0.79
4.74
86.20
0.43
86.63
47.76
—
47.76
5.04
0.68
5.72
$
$
$
$
$
$
$
$
4.18
1.14
5.32
69.39
(2.91)
66.48
39.04
—
39.04
4.83
0.98
5.81
$
$
$
$
$
$
$
$
(1.27) $
0.58
(0.69) $
(1.75) $
1.85
0.10
$
(13.33) $
1.90
(11.43) $
(0.70) $
0.46
(0.24) $
(0.23)
(0.35)
(0.58)
16.81
3.34
20.15
8.72
—
8.72
0.21
(0.30)
(0.09)
(1) The impact from commodity derivatives is reported below operating (loss) income in "Realized and unrealized gains
on derivative contracts" beginning January 1, 2012, in the Consolidated Statement of Operations.
(2) For the years ended December 31, 2011 and 2010, the impact of settled commodity derivatives that qualified for
hedge accounting was reported in "Revenues" in the Consolidated Statement of Operations. The impact of the
commodity derivatives that did not qualify for hedge accounting was reported below operating (loss) income in
"Realized and unrealized gains on derivative contracts."
48
Gathering
During the year ended December 31, 2012, QEP Field Services' gathering margins declined 7% primarily due to a decrease in
other gathering revenue and the related margin from the elimination of a third-party interruptible processing agreement.
Partially offsetting the decline in gathering margin was a 2% increase in gathering system throughput volume and a 3%
increase in average gas gathering revenue per MMBtu during 2012. Gathering system throughput average volume was 1.4
million MMBtu per day for the year ended December 31, 2012. The 11.1 million MMBtu increase in gathering volumes were
mainly related to increased gathering volumes at the Blacks Fork hub in southwest Wyoming and the northwest Louisiana
gathering system, which were 2% higher and 12% higher, respectively, during 2012. During 2012, the gathering volume
increase at the Blacks Fork hub was driven by a 17.5 million MMBtu increase in affiliated production at Pinedale offset by a
9.9 million MMBtu decrease in deliveries from unaffiliated customers. The Blacks Fork hub and the Hall Summit hub
accounted for 51% and 23%, respectively, of the total gathering system throughput during 2012. QEP Field Services posted a
22% increase in gathering margin during 2011, primarily due to an increase in the NGL value received from a short-term, third-
party processing arrangement for certain volumes in the Northern Region and a 3% increase in the average gathering rate.
Gathering system throughput volume was 1.4 million MMBtu per day for 2011, up from the 1.3 million MMBtu per day during
2010. The increased volumes in 2011 were mainly related to the northwest Louisiana gathering system, as described above,
which accounted for 21% and 16% of the total throughput during the years ended December 31, 2011 and 2010, respectively.
During the year ended December 31, 2011, QEP Field Services reported other gathering revenues and related gathering expense
related to a short-term interruptible gas processing contract with a third-party processor. The short-term processing arrangement
was in effect prior to the startup of QEP Field Services' Blacks Fork II processing plant. The $31.9 million decrease in other
gathering revenues in 2012 was primarily related to the termination of this contract. In addition, gathering expenses related to
the termination of this contract were $10.7 million lower during 2012.
The following tables are a summary of QEP Field Services' financial and operating results from gathering activities:
Year Ended December 31,
2011
2012
Change
2012 vs. 2011
2011 vs. 2010
2010
(in millions)
$
152.5
36.7
(37.6)
151.6
$
Gathering Margin
Gathering revenues
Other gathering revenues
Gathering expense
Gathering margin
$
$
172.9
36.6
(37.4)
172.1
$
$
161.1
68.5
(44.6)
185.0
$
$
Operating Statistics
Natural gas gathering volumes (in millions of MMBtu)
For unaffiliated customers
For affiliated customers
Total gas gathering volumes
240.0
266.5
506.5
Average gas gathering revenue (per MMBtu)
$
0.34
$
261.2
234.2
495.4
0.33
$
276.8
198.9
475.7
0.32
Processing
$
11.8
(31.9)
7.2
(12.9) $
(21.2)
32.3
11.1
$
0.01
$
8.6
31.8
(7.0)
33.4
(15.6)
35.3
19.7
0.01
Although a significant portion of the QEP Field Services' gas processing services are performed for a volumetric-based fee,
QEP Field Services also provides keep-whole processing services for certain customers which exposes the Company to the frac
spread.
QEP Field Services' processing margin decreased 14% during the year ended December 31, 2012, due to a 35% decline in
keep-whole processing margins, partially offset by a 40% increase in fee-based processing revenues. Processing margin
increased 93% during 2011, compared to 2010, due to increased keep-whole processing margins and fee-based processing
volumes and lower natural gas prices.
During the year ended December 31, 2012, the keep-whole processing margin per NGL barrel was $22.88 compared to $35.99
during the year ended December 31, 2011. The keep-whole processing margins decreased in 2012 due to a decrease in the net
realized NGL sales price per bbl, partially offset by increased NGL sales volumes. Including the impact of gains on derivative
contract settlements, NGL prices decreased 21% in 2012, which caused a corresponding decrease in the keep-whole processing
margin per NGL bbl. NGL sales volumes increased 3% in 2012, primarily the result of the Blacks Fork II plant, which
49
commenced operations in July 2011, partially offset by the execution, in the second quarter of 2012, of a fee-based processing
agreement with QEP Energy in the Uinta Basin that effectively transferred NGL bbls from QEP Field Services to QEP Energy.
The increased keep-whole processing margin in 2011 was the result of increased NGL prices and volume compared to 2010.
NGL prices increased 34% and NGL volumes increased 42% during 2011 from 2010.
Fee-based processing revenues increased during the year ended December 31, 2012, due to a 27% increase in average fee-based
processing revenue to $0.28 per MMBtu and a 4% increase in fee-based processing volumes to 251.3 million MMBtu. Fee-
based processing revenues increased 53% during 2011, compared to 2010, due to a 6% increase in fee-based processing
volumes to 240.7 million MMBtu and a 38% increase in the processing fee rate. The increased processing volume during the
years ended December 31, 2012 and 2011, was primarily the result of the start-up of the 150 MMcf per day Iron Horse
cryogenic processing plant in the Uinta Basin of eastern Utah during the first quarter of 2011 and the start-up of the Blacks
Fork II plant in the third quarter of 2011. Approximately 77%, 70% and 78% of QEP Field Services' net operating revenue was
derived from fee-based gathering and processing agreements in the years ended December 31, 2012, 2011 and 2010,
respectively.
Keep-whole processing margin, as reflected in the table below, is defined as the market value for NGL extracted from the
natural gas stream less the market value of the Btu-equivalent volume of natural gas required to replace the extracted liquids
and the related transportation and handling (including fractionation) costs and less plant fuel and shrink. Transportation and
handling costs were $24.3 million and $9.3 million higher during the years ended December 31, 2012 and 2011, respectively.
The increase in these costs was primarily the result of additional transportation costs relating to NGL sale agreements that
provide for transportation and fractionation of NGL at Mont Belvieu, Texas, and the full year operation of the Blacks Fork II
plant, which was put into service in July of 2011.
The following tables are a summary of QEP Field Services' processing financial and operating results:
Processing Margin
NGL sales (1)
Realized gains from commodity derivative
contract settlements
Processing (fee-based) revenues
Other processing revenues
Processing expense
Processing plant fuel and shrink expense
Years ended December 31,
2011
2012
Change
2012 vs. 2011
2011 vs. 2010
$
137.9
$
180.0
$
(42.1) $
85.2
2010
(in millions)
$
94.8
8.4
69.6
8.9
(16.1)
(33.3)
—
53.7
2.2
(12.2)
(49.2)
—
35.2
—
(11.9)
(32.6)
8.4
15.9
6.7
(3.9)
15.9
Natural gas, oil and NGL transportation and other
handling costs
Processing margin
Keep-whole processing margin
(33.6)
141.8
79.4
$
$
(9.3)
165.2
121.5
$
$
$
$
—
85.5
62.2
$
$
(24.3)
(23.4) $
(42.1) $
50
—
18.5
2.2
(0.3)
(16.6)
(9.3)
79.7
59.3
Years ended December 31,
2011
2012
2010
Change
2012 vs. 2011
2011 vs. 2010
Operating Statistics
Natural gas processing volumes
NGL sales (Mbbl)
Average net realized NGL sales price (per bbl)(2) $
Fee-based processing volumes (in millions of MMBtu)
3,470.3
42.18
3,376.4
53.33
2,386.1
39.73
$
$
$
93.9
(11.15) $
990.3
13.60
For unaffiliated customers
For affiliated customers
Total fee-based processing volumes
Average fee-based processing revenue (per
MMBtu)
____________________________
108.2
143.1
251.3
122.9
117.8
240.7
116.8
109.4
226.2
(14.7)
25.3
10.6
$
0.28
$
0.22
$
0.16
$
0.06
$
6.1
8.4
14.5
0.06
(1) Revenues for the years ended December 31, 2011 and 2010, reflect the impact of QEP's settled derivative contracts
which during the year ended December 31, 2012, are reflected below operating (loss) income. See Note 6 - Derivative
Contracts, in Part II, Item 8 of this Annual Report on Form 10-K for detailed information on derivative contract
settlements in the years ended December 31, 2012, 2011 and 2010.
(2) Average net realized NGL sales price per bbl is calculated as NGL sales including realized gains from commodity
derivative contracts settlements divided by NGL sales volumes.
Revenue, Volume and Price Variance Analysis
On January 1, 2012, QEP discontinued hedge accounting. During the year ended December 31, 2012, commodity derivative
realized gains and losses from derivative contract settlements are included below operating (loss) income in "Realized and
unrealized gains on derivative contracts" on the Consolidated Statement of Operations. Conversely, during the years ended
December 31, 2011 and 2010, the commodity derivative realized gains and losses on settlements were included in each
respective revenue category in conjunction with hedge accounting and the realization of the underlying contract. For additional
information regarding the discontinuance of hedge accounting and impact on the Consolidated Statement of Operations, see
Note 6 - Derivative Contracts, in Part II, Item 8 of this Annual Report on Form 10-K.
The following table is a summary of QEP's total revenues:
Years ended December 31,
2011
2012
Change
2012 vs. 2011
2011 vs. 2010
2010
(in millions)
QEP Resources Revenues
Natural gas sales
Oil sales
NGL sales
Gathering, processing and other
Purchased gas, oil and NGL sales
Total Revenues
$
667.4
532.6
322.1
181.6
646.1
$ 2,349.8
$ 1,239.1
324.2
309.8
200.8
1,085.3
$ 3,159.2
$ 1,205.3
198.1
142.6
156.6
598.0
$ 2,300.6
$
$
(571.7) $
208.4
12.3
(19.2)
(439.2)
(809.4) $
33.8
126.1
167.2
44.2
487.3
858.6
51
QEP Energy's price and volume related revenue variances are depicted in the following table:
QEP Energy Production Revenues
Year ended December 31, 2010 Revenues
Changes associated with volumes (1)
Changes associated with prices (2)
Year ended December 31, 2011 Revenues
Changes associated with volumes (1)
Changes associated with prices (2)
Changes associated with discontinuance of hedge accounting (3)
Year ended December 31, 2012 Revenues
____________________________
Natural
Gas
Oil
NGL
Total
(in millions)
$
$
1,205.3
193.2
(159.4)
1,239.1
50.7
(316.9)
(305.5)
667.4
$
$
198.1
50.7
75.4
324.2
221.0
(11.0)
(1.6)
532.6
$
$
47.9
58.1
23.7
129.7
125.8
(71.3)
—
184.2
$
$
1,451.3
302.0
(60.3)
1,693.0
397.5
(399.2)
(307.1)
1,384.2
(1) The revenue variance attributed to the change in volume is calculated by multiplying the change in volumes from the
years ended December 31, 2012 and 2011, to the years ended December 31, 2011 and 2010, by the average field-level
price for the years ended December 31, 2011 and 2010.
(2) The revenue variance attributed to the change in price is calculated by multiplying the change in field-level prices or
fee from the years ended December 31, 2012 and 2011, to the years ended December 31, 2011 and 2010, by volume
for the years ended December 31, 2011 and 2010. Pricing changes are driven by changes in the commodity field-level
prices excluding impact from commodity derivatives.
(3) During the years ended December 31, 2011 and 2010, realized gains and losses on commodity derivative contract
settlements were included in natural gas revenues on the Consolidated Statement of Operations. Conversely, during
the year ended December 31, 2012, the realized gains and losses on commodity derivative contract settlements are
recognized below operating (loss) income on the Consolidated Statement of Operations.
52
The following table presents changes in QEP Field Services' major revenue categories and the related volume and pricing
impact:
QEP Field Services
Year ended December 31, 2010 Revenues
Changes associated with volumes (1)
Changes associated with prices/fees (2)
Changes associated with other factors (3)
Year ended December 31, 2011 Revenues
Changes associated with volumes (1)
Changes associated with prices/fees (2)
Changes associated with discontinuance of hedge accounting (4)
Changes associated with other factors (3)
Year ended December 31, 2012 Revenues
$
$
____________________________
NGL
Processing Gathering
(in millions)
Total
94.8
39.3
45.9
—
180.0
5.0
(47.3)
0.2
—
137.9
$
$
35.2
2.5
16.0
2.2
55.9
2.4
13.5
—
6.7
78.5
$
$
189.2
6.6
2.0
31.8
229.6
3.6
8.2
—
(31.9)
209.5
$
$
319.2
48.4
63.9
34.0
465.5
11.0
(25.6)
0.2
(25.2)
425.9
(1) The revenue variance attributed to the change in volume is calculated by multiplying the change in volumes from the
years ended December 31, 2012 and 2011, to the years ended December 31, 2011 and 2010, by the average price or
fee for the years ended December 31, 2011 and 2010.
(2) The revenue variance attributed to the change in fees is calculated by multiplying the change in prices or fees from the
years ended December 31, 2012 and 2011, to the years ended December 31, 2011 and 2010, by volume for the year
ended December 31, 2012 and 2011.
(3) The revenue variance attributed to the change associated with other factors represents the changes in other gathering
revenues and changes in other processing revenues. These other revenues are not included in average gathering
revenue per MMBtu or average fee-based processing revenue per MMBtu in QEP Field Services' operating statistics
and thus have not been included in the price and volume variance analysis presented above.
(4) During the years ended December 31, 2011 and 2010, realized gains and losses on commodity derivative contract
settlements were included in natural gas revenues on the Consolidated Statement of Operations. Conversely, during
the year ended December 31, 2012, the realized gains and losses on commodity derivative contract settlements are
recognized below operating (loss) income on the Consolidated Statement of Operations.
Purchased gas, oil and NGL sales decreased by $439.2 million, or 40%, during the year ended December 31, 2012, from the
year ended December 31, 2011. The decrease in 2012, was due to decreased resale natural gas volumes and prices. Resale
natural gas volumes were 33% lower during 2012, and resale natural gas prices were 39% lower during 2012. Purchased gas
and oil sales increased by $487.3 million, or 81% during 2011 from 2010. The increase in 2011 was primarily due to QEP
Energy's additional revenues of $509.8 million related to gas purchases made in northwest Louisiana to utilize firm
transportation capacity and the subsequent sale of those gas purchases.
Operating Expenses
The following table presents QEP Resources' total operating expenses and the changes from the years ended December 31,
2012 and 2011, to the years ended December 31, 2011 and 2010. The narrative following the table explains the significant
variances between the comparable periods.
53
Purchased gas, oil and NGL expense
Lease operating expense
Natural gas, oil and NGL transportation and other
handling costs
Gathering, processing and other
General and administrative
Separation costs
Production and property taxes
Depreciation, depletion and amortization
Exploration expenses
Abandonment and impairment
Total operating expenses
Years ended December 31,
2011
2012
Change
2012 vs. 2011
2011 vs. 2010
$
655.6
172.3
$ 1,077.1
145.2
$
2010
(in millions)
$
589.3
125.0
148.9
88.0
266.6
—
103.4
904.9
11.2
133.4
$ 2,484.3
102.2
107.3
123.2
—
105.4
765.4
10.5
218.4
$ 2,654.7
54.2
83.2
107.2
13.5
82.5
643.4
23.0
46.1
$ 1,767.4
$
(421.5) $
27.1
46.7
(19.3)
143.4
—
(2.0)
139.5
0.7
(85.0)
(170.4) $
487.8
20.2
48.0
24.1
16.0
(13.5)
22.9
122.0
(12.5)
172.3
887.3
Purchased gas, oil and NGL expense decreased 39% in 2012. The decrease during 2012 was due to 39% lower natural gas
purchase prices and 28% lower natural gas purchased volumes. Purchased gas, oil and NGL expense increased in 2011 due to
increased purchased gas expense at QEP Energy of $506.4 million. The increased purchased gas expense at QEP Energy relates
to gas purchases made in northwest Louisiana to utilize firm transportation capacity.
Lease operating expense increased 19% during the year ended December 31, 2012, due to higher production volumes,
increased water disposal costs, higher trucking, chemical, labor and pumper costs and increases in workover costs, well
maintenance and repair expenses. Water disposal costs increased $9.3 million during 2012 primarily in the Northern Region
due to increased drilling activity and related water disposal constraints in the Williston Basin. During 2012, produced water
trucking, chemical, labor and pumper costs increased $9.8 million, respectively, primarily in the Northern Region due to
increased drilling activity and liquids production in the Williston Basin. Workover costs and maintenance and repair expenses
increased $3.8 million primarily related to the increased number of pumping oil wells located in the Northern Region. Lease
operating expense increased $20.2 million, or 16%, to $145.2 million during 2011 compared to 2010 driven by a 20% increase
in production of natural gas and oil and NGL equivalents during the period.
During the year ended December 31, 2012, natural gas, oil and NGL transportation and other handling costs increased $46.7
million when compared to the corresponding period in 2011 and increased $48.0 million during 2011, compared to the
corresponding period in 2010. The increases during the years ended December 31, 2012 and 2011, are primarily due to higher
production volumes, increased transportation costs relating to agreements that provide for transportation and fractionation of
NGL at Mont Belvieu, Texas, and the 2012 operation of the Blacks Fork II plant which was put into service in the third quarter
of 2011.
Gathering, processing and other expense decreased by $19.3 million for the year ended December 31, 2012, primarily due to a
32% reduction in the cost to purchase natural gas to replace the shrink caused by extracting natural gas liquids from the gas
stream under QEP Field Services keep-whole processing activity. The decrease in shrink gas purchases was mainly due to
QEP's processing plants running in ethane rejection (where instead of recovery, the ethane is left in the production stream and
sold as natural gas) mode during the fourth quarter of 2012. In addition, gathering expenses were 16% lower from the
elimination of a short-term interruptible processing agreement QEP Field Services entered into to process gas during the first
half of 2011 before the expansion of the Blacks Fork processing plant that was put into service during the third quarter of 2011.
Gathering, processing and other expense increased by $24.1 million in 2011 when compared to the 2010 period due to higher
gathering and processing volumes and the effect from the short-term, third-party interruptible processing agreement in place
during the first half of 2011.
During the year ended December 31, 2012, general and administrative (G&A) expense increased by $143.4 million, or 116%,
compared to 2011. The largest portion of the increase in G&A during 2012 was due to the accrual of a $115 million litigation
loss contingency (see Note 9 - Commitments and Contingencies, to the Consolidated Financial Statements of this Annual
Report on Form 10-K). Additional factors contributing to the 2012 increase were $7.0 million in restructuring costs, $2.2
million pension curtailment related to the Company's restructuring efforts (see Note 7 - Restructuring Costs, to the
Consolidated Financial Statements of this Annual Report on Form 10-K), $4.7 million in higher compensation costs due to
increased number of employees and the annual compensation program, $2.5 million increase in pension and post-retirement
54
medical expenses, $3.6 million increase in stock-based compensation expense, $1.4 million increase from the mark-to-market
of the deferred compensation wrap plan, $7.1 million increase in professional and contract services, with the remaining
increases related to various immaterial items. Total QEP G&A expense increased to $123.2 million for 2011 compared with
$107.2 million for 2010. The increase in 2011 resulted from an increase in the number of employees, increased employee
benefit plan and stock-based compensation related expenses, increased legal and outside professional services and higher
insurance costs.
Production and property taxes decreased 2% during the year ended December 31, 2012. The decrease in 2012 was due to a 14%
decrease in field-level equivalent sales prices which are used as the basis for production taxes in most states where QEP
operates. Higher field-level oil and NGL prices resulted in higher production taxes during 2011, partially offset by lower field-
level sales prices for natural gas during the same period.
During the year ended December 31, 2012, QEP's total depreciation, depletion and amortization (DD&A) expense increased
$139.5 million, or 18%, as compared to 2011. The 2012 increase in DD&A expense was the result of increased production and
increased DD&A rates at QEP Energy. Also contributing to the increase in DD&A expense during 2012 was the completion of
the Blacks Fork II plant during the third quarter of 2011 at QEP Field Services. QEP's total DD&A expense grew $122.0
million, or 19%, in 2011 from the 2010 comparable period as a result of increased production at QEP Energy combined with
plant additions at QEP Field Services.
Exploration expenses increased $0.7 million, or 7%, during the year ended December 31, 2012, compared with the 2011 period.
The 2012 increase primarily related to an increase in seismic studies of $1.8 million partially offset by a $0.7 million decrease
in exploration related labor and benefits costs as well as a $0.4 million decrease in exploration contract and consulting services.
Exploration expenses were $10.5 million in 2011 compared to $23.0 million in 2010 due to a decrease in dry hole costs of $9.3
million and reduced seismic acquisition costs of $2.5 million.
Abandonment and impairment expenses decreased $85.0 million, to $133.4 million, during the year ended December 31, 2012.
The decrease was primarily due to $195.5 million compared to $107.6 million of impairments recognized on proved properties
in 2011 and 2012, respectively. The Company's proved properties have significant reserves and are sensitive to declines in
natural gas, crude oil and NGL prices. These assets are at risk of impairment if future natural gas, crude oil or NGL prices
experience significant declines. Abandonment and impairment expenses increased to $218.4 million during 2011, compared
with $46.1 million during the 2010 period. The 2011 increase was primarily due to the recognition of a price-related
impairment charge of $195.5 million in the fourth quarter of 2011 on some of the Company's mature, dry gas, and higher cost
properties in both the Northern and Southern Regions.
CONSOLIDATED RESULTS BELOW OPERATING (LOSS) INCOME
Realized and unrealized gains on derivative contracts
Effective January 1, 2012, QEP discontinued hedge accounting, thus changes during the year ended December 31, 2012, and all
changes in the mark-to-market value are recognized in current period earnings. Gains and losses on derivative instruments
during 2012 are comprised of both realized and unrealized gains and losses on QEP's commodity derivative contracts and
interest rate swaps. During 2012, gains on commodity derivative instruments were $449.3 million, of which $380.0 million was
realized and $69.3 million was unrealized. Additionally, during 2012, losses from interest rate swaps were $7.4 million, of
which $1.3 million was realized and $6.1 million was unrealized. During the years ended December 31, 2011 and 2010, QEP
used hedge accounting and changes in the mark-to-market value of the commodity derivative contracts were reflected in
accumulated other comprehensive income (AOCI) and ultimately revenues when the commodity derivatives were settled. As a
result of discontinuing hedge accounting, the mark-to-market values at December 31, 2011, were fixed in AOCI as of the de-
designation date and are being reclassified into the Consolidated Statement of Operations as the transactions settle and affect
earnings. At December 31, 2012, AOCI consisted of $123.5 million ($77.6 million after tax) of unrealized gains. During 2012,
$171.1 million unrealized gains, after tax, were reclassified from AOCI into the Consolidated Statement of Operations as the
transactions settled. QEP expects to reclassify into earnings from AOCI the remaining fixed value related to de-designated
natural gas, oil and NGL hedges during 2013.
Interest and other income
Interest and other income are comprised primarily of interest earned on investments, gains and losses on warehouse inventory,
and other miscellaneous income. During 2012, interest and other income increased $2.5 million. The increase was primarily
due to a $1.4 million increase in interest income and variances in warehouse inventory valuations of $0.8 million for 2012.
55
During 2011, interest and other income increased by $1.8 million, primarily due to the variance in inventory valuations, offset
by lower gains on warehouse inventory sales.
Loss from early extinguishment of debt
During the year ended December 31, 2012, QEP recorded a loss from early extinguishment of debt of $0.6 million from the
retirement of a portion of QEP's senior notes. During 2011, QEP recorded a loss from early extinguishment of debt of $0.7
million due to replacing the previous $1.0 billion revolving credit facility with a new $1.5 billion revolving credit facility in
August 2011. The loss of $13.3 million during 2010 was the result of the repurchase of $638.0 million principal amount of
senior notes and the termination of a $500 million term loan related to the Spin-off from Questar, both occurring in the third
quarter of 2010.
Interest expense
Interest expense increased $32.9 million, or 37%, during the year ended December 31, 2012, compared to 2011. The increase in
interest expense during 2012 was due to average debt levels that were approximately $856.5 million higher than average debt
levels during 2011. The increase in average debt levels is related to QEP issuing 2022 Senior Notes and 2023 Senior Notes and
entering into the Term Loan. Interest expense increased 7% to $90.0 million in 2011 compared to 2010 due to December 31,
2011, average debt levels that were approximately $165 million higher than average debt levels in the comparable prior period.
Income taxes
QEP's effective combined federal and state income tax rate was 33.5% during the year ended December 31, 2012, compared to
36.3% during 2011. The 2012 combined rate was lower due to state income tax adjustments to prior year provisions based on
tax returns filed. The effective combined federal and state income tax rate was 36.3% for 2011, slightly lower than the 36.9%
effective combined rate in 2010. The decrease in the combined rate during 2011 was primarily due to the Spin-off which
increased the 2010 rate.
56
DISCUSSION BY LINE OF BUSINESS
QEP Energy
QEP Energy reported a net loss of $0.7 million during the year ended December 31, 2012, a decrease of $105.4 million from
the $104.7 million net income reported during the year ended December 31, 2011. The decrease in 2012 was primarily due to
the accrual of a $115 million litigation loss contingency, 4% lower average total equivalent net realized prices, and a 18%
increase in DD&A, partially offset by an unrealized gain from commodity derivative contracts of $68.4 million and increased
production. QEP Energy reported net income of $104.7 million in 2011, a decrease of 49% from $203.9 million in 2010. The
primary reason for the decrease in 2011 net income was the recognition of a price-related impairment charge of $195.5 million
in the fourth quarter of 2011 on some of QEP Energy's mature, dry gas, and higher cost properties in both the Northern and
Southern Regions.
The following table provides a summary of QEP Energy's financial and operating results:
Year Ended December 31,
2011
2012
Change
2012 vs. 2011
2011 vs. 2010
2010
(in millions)
Revenues
Natural gas sales
Oil sales
NGL sales
Purchased gas, oil and NGL sales
Other
Total Revenues
Operating expenses
$
667.4
$ 1,239.1
$ 1,205.3
$
532.6
184.2
222.0
9.2
324.2
129.7
509.8
10.4
198.1
47.9
—
5.0
1,615.4
2,213.2
1,456.3
Purchased gas, oil and NGL expense
Lease operating expense
Natural gas, oil and NGL transportation and other
handling costs
General and administrative
Production and property taxes
Depreciation, depletion and amortization
Exploration expenses
Abandonment and impairment
Total Operating Expenses
Net gain from asset sales
Operating (Loss) Income
Realized gain (loss) on derivative instruments
Unrealized gain on derivative instruments
Interest and other income
Income from unconsolidated affiliates
Interest expense
(Loss) Income before Income Taxes
Income tax benefit (provision)
Net (Loss) Income Attributable to QEP
$
224.7
175.8
228.1
237.6
97.2
838.0
11.2
133.4
1,946.0
1.2
(329.4)
366.5
68.4
6.2
0.1
(116.8)
(5.0)
4.3
(0.7) $
506.4
148.2
186.0
98.4
99.1
707.2
10.5
218.4
1,974.2
1.4
240.4
(117.7)
117.7
4.0
0.1
(81.9)
162.6
(57.9)
104.7
$
—
127.3
125.5
78.0
77.8
592.5
23.0
46.1
1,070.2
13.7
399.8
(121.7)
121.7
2.1
0.2
(78.5)
323.6
(119.7)
203.9
(571.7) $
208.4
54.5
(287.8)
(1.2)
(597.8)
(281.7)
27.6
42.1
139.2
(1.9)
130.8
0.7
(85.0)
(28.2)
(0.2)
(569.8)
484.2
(49.3)
2.2
—
(34.9)
(167.6)
62.2
(105.4) $
$
33.8
126.1
81.8
509.8
5.4
756.9
506.4
20.9
60.5
20.4
21.3
114.7
(12.5)
172.3
904.0
(12.3)
(159.4)
4.0
(4.0)
1.9
(0.1)
(3.4)
(161.0)
61.8
(99.2)
Operating expenses per unit
QEP Energy's total operating expenses (the sum of DD&A expense, lease operating expense, natural gas, oil and NGL
transportation and other handling costs, G&A expense, a portion of QEP's total interest expense that is allocated to QEP Energy
based on intercompany agreements and production taxes) per Mcfe of production increased 10% to $5.30 per Mcfe during
57
2012, compared to $4.81 per Mcfe during 2011. Operating expenses per Mcfe of production increased 2% to $4.81 per Mcfe
during 2011, versus $4.72 per Mcfe in 2010.
The following table presents certain QEP Energy's operating expenses on a unit of production basis:
Year Ended December 31,
2011
2012
Change
2012 vs. 2011
2011 vs. 2010
Depreciation, depletion and amortization
Lease operating expense
Natural gas, oil and NGL transportation and other
handling costs
General and administrative
Allocated interest expense
Production taxes
Total Operating Expenses
$
$
2.63
0.55
0.71
0.74
0.37
0.30
5.30
$
$
2.57
0.54
0.68
0.36
0.30
0.36
4.81
$
$
2010
(per Mcfe)
$
2.59
0.56
0.55
0.34
0.34
0.34
4.72
$
$
0.06
0.01
0.03
0.38
0.07
(0.06)
0.49
$
(0.02)
(0.02)
0.13
0.02
(0.04)
0.02
0.09
DD&A expense increased $0.06 per Mcfe during the year ended December 31, 2012, when compared to the year ended
December 31, 2011. The increase in DD&A expense per Mcfe was the result of increased production from higher-rate DD&A
pools and increases in the DD&A rates from increased drilling costs in the Midcontinent and the Williston Basin. DD&A
expense per Mcfe decreased $0.02 in 2011 from the 2010 period. QEP Energy's DD&A expense increased $114.7 million
during 2011 from 2010. While QEP Energy's total DD&A increased in 2011, the lower per unit expense in 2011 was the result
of booking NGL reserves associated with the fee-based processing agreement entered into between QEP Energy and QEP Field
Services for QEP's Pinedale production.
QEP Energy's average production costs (lease operating expense) per Mcfe were 2% higher during the year ended December
31, 2012, compared to the year ended December 31, 2011. Average production costs per Mcfe were 4% lower in the 2011
period compared to the 2010 period.
The following table presents average production cost, excluding production taxes, for QEP Energy by region on a unit of
production basis:
Year Ended December 31,
2011
2012
Change
2012 vs. 2011
2011 vs. 2010
Northern Region
Southern Region
Average production cost
$
$
0.63
0.47
0.55
$
0.58
0.50
0.54
$
0.05
(0.03)
0.01
0.02
(0.05)
(0.02)
Lease operating expense per Mcfe increased $0.01 during the year ended December 31, 2012, when compared to the year
ended December 31, 2011. The increase during 2012 in lease operating expense is primarily due to a $0.05 per Mcfe increase in
the Northern Region, which was mostly offset by a $0.03 per Mcfe decrease in the Southern Region. The Northern Region
increase was driven by a 41% increase in lease operating expenses, partially offset by a 30% increase in production. Lease
operating expense increase in the Northern Region was primarily the result of higher water injection and disposal costs,
increased trucking, chemical, labor and pumper costs and increases in workover costs and well maintenance and repair
expenses. The Southern Region decrease was a result of a 5% increase in production and a 2% decrease in lease operating
expenses. The decrease in lease operating expenses in the Southern Region was driven primarily by decreases in workover
costs and well maintenance and repair expenses. Lease operating expense per Mcfe decreased $0.02 for 2011 from the 2010
period as the result of increased production volumes in lower cost areas. Growing production from new high-rate, low-
operating cost wells in the Haynesville/Cotton Valley area and in the Pinedale Anticline, coupled with declining production
from older higher cost areas, reduced average per Mcfe lease operating expense in 2011. For additional information regarding
the variances in production and lease operating expenses, see "Production" and "Operating Expenses" discussions earlier in
Item 7 of Part II in this Annual Report on Form 10-K.
Natural gas, oil and NGL transportation and other handling costs per Mcfe were 4% higher during the year ended December 31,
2012, than in the year ended December 31, 2011. The per Mcfe increase in 2012 relates to NGL sale agreements at Mont
58
2010
(per Mcfe)
$
0.56
0.55
0.56
Belvieu, Texas, and the related transportation and processing of NGL, which were effective beginning with the startup of the
Blacks Fork II plant in the third quarter of 2011. Natural gas, oil and NGL transportation and other handling costs per Mcfe
were 24% higher in 2011 than in 2010 due primarily to processing costs associated with increased NGL production and related
transportation costs under a revised processing agreement at Pinedale.
G&A expense increased $0.38 per Mcfe during the year ended December 31, 2012. The per Mcfe increase in 2012 was the
result of higher total G&A expenses during 2012, partially offset by increased production during the same period. The
increased G&A expenses for 2012 was primarily the result of the accrual of a $115 million litigation loss contingency (See
Note 9 - Commitments and Contingencies, to the consolidated financial statements in Item 8 of Part II of this Annual Report on
Form 10-K). Excluding the litigation loss contingency accrual, G&A was $0.38 per Mcfe, an increase of $0.02 per Mcfe, or
6%, driven by expenses incurred in the current year for restructuring costs, higher compensation costs due to increased
headcount and the annual compensation program, increases in pension and post-retirement medical expenses, increases in
professional and contract services, increased stock-based compensation expense and mark-to-market changes in the Company's
deferred compensation wrap plan (See Note 7 – Restructuring Costs, to the consolidated financial statements in Item 8 of Part
II of this Annual Report on Form 10-K for additional information regarding restructuring costs). G&A expense per Mcfe
increased $0.02 during the year ended December 31, 2011, as a result of higher G&A expenses, which were primarily related to
employee benefit plan and stock-based compensation related expenses, increased legal and outside professional services and
higher insurance costs, which were partially offset by increased production in 2011.
Allocated interest expense per Mcfe increased $0.07 during the year ended December 31, 2012. The increase during 2012 was
primarily due to an increase in allocated interest expense resulting from higher debt levels. Allocated interest expense per unit
of production decreased $0.04 per Mcfe in 2011 primarily due to higher production volumes.
In most states in which QEP Energy operates, QEP pays production taxes based on a percentage of field-level revenue, except
in Louisiana, where severance taxes are volume based. Production taxes per Mcfe decreased by $0.06 during 2012 because of
lower field-level natural gas, oil and NGL prices. Production taxes per Mcfe increased by $0.02 per Mcfe during 2011 because
of higher field-level oil and NGL prices.
QEP Field Services
QEP Field Services, which provides gas gathering and processing services, generated net income of $129.0 million during the
year ended December 31, 2012, compared to $154.5 million in the same period of 2011. During 2012, lower gathering and
processing margins contributed to the 17% decrease in net income during 2012. Gathering margins were lower during 2012 as
the result of decreased other gathering revenue due to the elimination of a short-term, third-party interruptible processing
agreement. The short-term processing arrangement was in effect during the first three quarters of 2011, before the expansion of
the Blacks Fork processing complex was put into service during the third quarter of 2011. Processing margins were lower
during 2012, due to a decrease in NGL prices and the related impact of lower keep-whole processing margins. QEP Field
Services generated net income of $154.5 million in the year ended December 31, 2011, compared to $91.1 million in 2010, a
70% increase. The increase in net income in 2011 was the result of higher gathering and processing margins and increased
throughput volumes.
59
The following table provides a summary of QEP Field Services' financial and operating results:
Year Ended December 31,
Change
2012
2011
2010
2012 vs. 2011
2011 vs. 2010
(in millions)
Revenues
NGL sales
Processing (fee-based)
Other processing revenues
Gathering
Other gathering
Purchased gas, oil and NGL sales
Total Revenues
Operating expenses
Purchased gas, oil and NGL expense
Processing
Processing plant fuel and shrinkage
Gathering
Natural gas, oil and NGL transportation and other
handling costs
General and administrative
Taxes other than income taxes
Depreciation, depletion and amortization
Total Operating Expenses
Net gain from asset sales
Operating Income
Interest and other income
Income from unconsolidated affiliates
Realized gains on derivative instruments
Unrealized gains on derivative instruments
Interest expense
Income before Income Taxes
Income tax provision
Net income
Net income attributable to noncontrolling interest
Net Income Attributable to QEP
$
$
137.9
$
180.0
$
69.6
8.9
172.9
36.6
13.3
439.2
12.1
16.1
33.3
37.4
33.6
34.7
6.0
63.2
236.4
—
202.8
0.2
6.7
8.4
—
(13.6)
204.5
(71.8)
132.7
(3.7)
129.0
$
53.7
2.2
161.1
68.5
—
465.5
—
12.2
49.2
44.6
9.3
29.2
6.1
55.7
206.3
—
259.2
0.1
5.4
—
—
(13.6)
251.1
(93.4)
157.7
(3.2)
154.5
$
94.8
35.2
—
152.5
36.7
—
319.2
—
11.9
32.6
37.6
—
31.6
4.4
48.9
167.0
(1.6)
150.6
0.1
2.8
—
—
(7.6)
145.9
(51.9)
94.0
(2.9)
91.1
$
(42.1) $
15.9
6.7
11.8
(31.9)
13.3
(26.3)
12.1
3.9
(15.9)
(7.2)
24.3
5.5
(0.1)
7.5
30.1
—
(56.4)
0.1
1.3
8.4
—
—
(46.6)
21.6
(25.0)
(0.5)
(25.5) $
$
85.2
18.5
2.2
8.6
31.8
—
146.3
—
0.3
16.6
7.0
9.3
(2.4)
1.7
6.8
39.3
1.6
108.6
—
2.6
—
—
(6.0)
105.2
(41.5)
63.7
(0.3)
63.4
See "Gathering" and "Processing" sections, as appearing earlier, for additional discussion of the significant changes in QEP
Field Services' comparative financial statements.
Natural gas, oil and NGL transportation and other handling costs increased $24.3 million and $9.3 million during the years
ended December 31, 2012 and 2011, when compared to the prior year periods. The increase during the years ended December
31, 2012 and 2011, was primarily due to transportation costs related to the Blacks Fork II plant, placed into service in the third
quarter of 2011, and the related transportation of additional NGL volumes to Mont Belvieu, Texas.
General and administrative expenses increased by $5.5 million during the year ended December 31, 2012. The increase in G&A
costs during the current period was primarily due to increases in headcount and related compensation costs, increases in
pension and post-retirement medical expenses, increases in stock compensation expense, and an increase in the mark-to-market
value of the deferred compensation wrap plan. G&A expensed decreased $2.4 million in 2011 compared to 2010 primarily due
to lower outside service costs.
60
During the year ended December 31, 2012, DD&A expense grew $7.5 million, or 13%, as compared to 2011. The 2012
increase in DD&A expense was primarily due to the completion of the Blacks Fork II plant during the third quarter of 2011 at
QEP Field Services. DD&A expense grew $6.8 million, or 14%, in 2011 from the 2010 comparable period as a result of plant
additions at QEP Field Services.
See "Consolidated Results Below Operating (Loss) Income" section, as appearing earlier, for additional discussion of the
significant changes in such line items.
QEP Marketing and Other
QEP Marketing, which markets affiliate and third-party natural gas and oil and owns and operates a gas storage facility,
generated no net income during the year ended December 31, 2012, an $8.0 million decrease from the $8.0 million of income
during the year ended December 31, 2011. The decrease in net income in 2012 related to lower marketing margins and higher
unrealized losses from derivative contracts. Also contributing to the decrease was higher interest expense in 2012 compared to
2011 due to higher average debt levels in the current year. During 2012, QEP Marketing had a loss on resale gas, oil and NGL
of $8.0 million, related to fulfillment of firm transportation contract commitments. QEP Marketing generated net income from
continuing operations of $8.0 million during 2011 compared with a loss of $12.0 million during 2010. The increase in 2011 was
due to a 54% increase in marketing sales volumes, partially offset by a 5% decrease in marketing margins.
The following table provides a summary of QEP Marketing and Other's financial and operating results:
Year Ended December 31,
2011
2012
Change
2012 vs. 2011
2011 vs. 2010
2010
(in millions)
Revenues
Purchased gas, oil and NGL sales
$ 1,013.1
$ 1,149.3
$ 1,091.5
$
Other
Total Revenues
Operating expenses
6.8
7.6
7.0
1,019.9
1,156.9
1,098.5
Purchased gas, oil and NGL expense
1,021.1
1,144.5
1,082.8
Gathering, processing and other
General and administrative
Separation costs
Production and property taxes
Depreciation, depletion and amortization
Total Operating Expenses
Net gain from asset sales
Operating (Loss) Income
Realized gain on derivative instruments
Unrealized loss on derivative instruments
Interest and other income
Loss on extinguishment of debt
Interest expense
(Loss) Income before Income Taxes
Income tax benefit (provision)
Net (Loss) Income Attributable to QEP
$
1.2
0.4
—
0.2
3.7
1.3
2.1
—
0.2
2.5
1.1
3.9
13.5
0.3
2.0
1,026.6
1,150.6
1,103.6
—
(6.7)
3.8
(5.2)
132.1
(0.6)
(124.4)
(1.0)
1.0
— $
—
6.3
—
—
98.7
(0.7)
(93.2)
11.1
(3.1)
8.0
$
—
(5.1)
—
—
87.2
(13.3)
(85.4)
(16.6)
4.6
(12.0) $
(136.2) $
(0.8)
(137.0)
(123.4)
(0.1)
(1.7)
—
—
1.2
(124.0)
—
(13.0)
3.8
(5.2)
33.4
0.1
(31.2)
(12.1)
4.1
(8.0) $
57.8
0.6
58.4
61.7
0.2
(1.8)
(13.5)
(0.1)
0.5
47.0
—
11.4
—
—
11.5
12.6
(7.8)
27.7
(7.7)
20.0
Interest and other income primarily relates to intercompany debt agreements between QEP and its subsidiaries, which is
eliminated in consolidation.
61
LIQUIDITY AND CAPITAL RESOURCES
QEP seeks to fund its development projects by employing a capital structure and financing strategy to provide sufficient
liquidity to withstand commodity price swings. As part of this strategy QEP funds long-term capital intensive development
projects while maintaining the ability to employ an exploration program, execute acquisitions and maintain an appropriate debt
rating. In addition, QEP maintains a commodity price derivative strategy to reduce commodity price volatility and to provide
certainty to cash flows.
QEP funds its operations, capital expenditures and working capital requirements with cash flow from its operating activities
and borrowings under its credit facilities. Periodically, QEP's access to debt and capital markets and sales of assets will provide
additional liquidity. The Company believes cash flow from operations and availability under its credit facility will be sufficient
to fund the Company's planned capital expenditures and operating expenses during the next 12 months. To the extent actual
operating results differ from the Company's estimates, QEP's liquidity could be adversely affected.
The following table provides QEP's available liquidity and debt to total capital ratio compared to the previous period:
Cash and cash equivalents
Amount available under the revolving credit facility (1)
Total liquidity
Total debt (2)
Total common shareholders' equity
Ratio of debt to total capital (3)
____________________________
December 31,
2012
2011
(in millions, except %)
$
$
$
— $
805.9
805.9
3,206.9
3,266.0
$
$
—
889.4
889.4
1,679.4
3,301.5
50%
34%
(1) See discussion of the Company's revolving credit facility below. Includes outstanding letters of credit of $4.1 million
(2)
for both the years ended December 31, 2012 and 2011.
Includes all outstanding debt, which is discussed in detail below. At December 31, 2012, debt levels were higher than
at December 31, 2011, primarily due to the 2012 Acquisition.
(3) Defined as total debt divided by the sum of total debt plus common shareholders' equity.
Credit Facility
QEP's revolving credit facility agreement, which matures in August 2016, provides for unsecured loan commitments of $1.5
billion from a syndicate of financial institutions. The credit facility provides for borrowings at short-term interest rates and
contains customary covenants and restrictions. The credit facility agreement also contains provisions which would allow for the
amount of the facility to be increased to $2.0 billion and for the maturity to be extended for two additional one-year periods
with the agreement of the lenders. QEP's weighted-average interest rate on borrowings from its credit facility was 2.08% during
the year ended December 31, 2012. At December 31, 2012, QEP was in compliance with the debt covenants under the credit
agreement. At February 13, 2013, QEP had $731.5 million outstanding and $4.1 million of letters of credit issued under its
credit facility.
Term Loan
During the second quarter of 2012, the Company entered into a $300.0 million Term Loan with a group of financial institutions.
The Term Loan agreement provides for unsecured borrowings at short-term interest rates and contains covenants, restrictions
and interest rates that are substantially the same as the Company's revolving credit facility. The Term Loan matures in April
2017, and the maturity date may be extended one year with the agreement of the lenders. The proceeds from the Term Loan
were used to pay down the Company's credit facility and for general corporate purposes. During the year ended December 31,
2012, QEP's weighted-average interest rate on the Term Loan was 2.05%. In conjunction with the Term Loan, QEP entered into
interest rate swap contracts with a combined notional principal amount of $300.0 million which will mature in March 2017.
Under the swap contracts, QEP pays 1.07% for the life of the swaps and receives one-month LIBOR. The interest rate at
December 31, 2012, under the Term Loan is one-month LIBOR, plus 2.00% (the Applicable Margin) which, when combined
with the fixed interest rate swaps, results in a current effective rate of 3.07% for borrowings under the Term Loan. To the extent
that the Applicable Margin under the Term Loan changes, the effective fixed rate paid for borrowings under the Term Loan will
change.
62
Senior Notes
During the first quarter of 2012, the Company completed a public offering of $500.0 million in aggregate principal amount of
5.375% senior notes due in October 2022. The proceeds from the 2022 Senior Notes were used to repay indebtedness under the
Company's credit facility. In the second quarter of 2012, the Company purchased $6.7 million of its senior notes outstanding
due April 2018 and March 2020. In addition, during the third quarter of 2012, the Company completed a public offering of
$650.0 million in aggregate principal amount of 5.25% senior notes due in May 2023. The proceeds from the 2023 Senior
Notes were used to finance a portion of the 2012 Acquisition.
The Company's senior unsecured notes outstanding as of December 31, 2012, totaled $2,221.8 million principal amount and are
comprised of six issuances as follows:
•
•
•
•
•
•
$176.8 million 6.05% Senior Notes due September 2016;
$134.0 million 6.80% Senior Notes due April 2018;
$136.0 million 6.80% Senior Notes due March 2020;
$625.0 million 6.875% Senior Notes due March 2021;
$500.0 million 5.375% Senior Notes due October 2022; and
$650.0 million 5.25% Senior Notes due May 2023.
Cash Flow from Operating Activities
Cash flows from operating activities are primarily affected by natural gas, oil and NGL production volumes and commodity
prices (including the effects of settlements of the Company's derivative contracts) and by changes in working capital. QEP
enters into commodity derivative transactions covering a substantial, but varying, portion of its anticipated future gas, oil and
NGL production for the next 12 to 24 months.
Net cash provided by operating activities increased $3.4 million during the year ended December 31, 2012, when compared to
the year ended December 31, 2011, due to an increase in cash from operating assets and liabilities, offset by lower net income
and reduced non-cash adjustment to net income. Non-cash adjustments to net income consisted primarily of DD&A;
abandonment and impairment charges; unrealized gains on derivative contracts; and changes in deferred income taxes. Changes
in operating assets and liabilities were a source of cash during 2012, primarily due to a decrease in accounts receivable and an
increase in accrued expenses from the accrual of $115 million for litigation loss contingency. Changes in operating assets and
liabilities driving a use of cash during 2011, were increases in accounts receivable, offset by increases in accounts payable.
Net cash provided from operating activities is presented below:
Year Ended December 31,
Change
Net income (1)
Non-cash adjustments to net income
Changes in operating assets and liabilities
Net cash provided from operating activities
2012
$
132.0
1,038.0
126.0
$ 1,296.0
2011
(in millions)
$
270.4
1,050.9
$
(28.7 )
$ 1,292.6
$
2010
2012 vs. 2011 2011 vs. 2010
$
285.9
784.5
(72.9 )
997.5
$
(138.4 ) $
(12.9 )
154.7
3.4
$
(15.5 )
266.4
44.2
295.1
___________________________
(1) The net income for the year ended December 31, 2010, excludes discontinued operations, net of income tax, of $43.2
million.
63
Cash Flow from Investing Activities
A comparison of capital expenditures for the years ended December 31, 2012, 2011 and 2010, and a forecast for calendar year
2013 are presented in the table below:
2013
Forecast(1)
Year Ended December 31,
2012
2011
2010
Change
2012 vs. 2011 2011 vs. 2010
QEP Energy
QEP Field Services
QEP Marketing
Corporate
Total accrued capital expenditures
Change in accruals
Total cash capital expenditures
$ 1,530.0
120.0
1.0
25.0
1,676.0
—
$ 1,676.0
(in millions)
$
$ 2,702.4
171.2
1.0
13.6
2,888.2
$ 1,338.8
101.6
0.4
5.0
1,445.8
$ 1,215.8
268.2
1.9
—
1,485.9
$
1,363.6
69.6
0.6
8.6
1,442.4
(88.5)
(14.7 )
(16.9)
(73.8)
$ 2,799.7
$ 1,431.1
$ 1,469.0
$
1,368.6
$
123.0
(166.6)
(1.5)
5.0
(40.1)
2.2
(37.9)
___________________________
(1) Represents the mid-point end of the most recent guidance.
During the year ended December 31, 2012, capital expenditures on a cash basis increased 96% to $2,799.7 million, compared
to $1,431.1 million during the year ended December 31, 2011. The increase of $1,368.6 million cash capital expenditures
during 2012 was primarily the result of QEP Energy's $1,388.7 million 2012 Acquisition. Excluding the 2012 Acquisition,
QEP's capital expenditures were $20.1 million lower than in 2011. Capital expenditures on a cash basis decreased in 2011
compared to 2010 due to completion in 2010 of capital projects for QEP Field Services.
QEP Energy's capital investment, on an accrual basis, during the year ended December 31, 2012, increased $1,363.6 million
over the year ending December 31, 2011, due to increased capital expenditures in the Williston Basin (primarily due to the
2012 Acquisition), partially offset by lower capital expenditures in Haynesville (approximately 81% lower) due to the reduced
drilling program as capital was allocated out of the dry-gas Haynesville play into higher-return oil and liquids-rich natural gas
drilling programs. QEP Energy's capital investments for 2011 were higher than 2010 due to increased company operated well
completions combined with acquisitions of additional working interests.
QEP Field Services' capital investment increased $69.6 million, on an accrual basis, during the year ended December 31, 2012,
compared to 2011, due to projects directed to grow the midstream business. These projects include the construction of a 150
MMcfd fee-based cryogenic gas processing plant in the Uinta Basin (Iron Horse II) and the 10,000 Bbl/d expansion to the NGL
fractionation facilities located at the Blacks Fork processing complex. QEP Field Services' capital investments decreased in
2011 compared to 2010 due to the completion of major capital projects in eastern Utah and northwest Louisiana in late 2010
and the completion of the Black Forks II plant early in the third quarter of 2011.
At December 31, 2012, forecasted capital investment for 2013 is expected to be approximately $1,676.0 million, comprised of
$1,530.0 million allocated to QEP Energy, $120.0 million to QEP Field Services, and $26.0 million between QEP Resources
and QEP Marketing. During 2013, QEP intends to fund capital expenditures with cash flow from operating activities and, if
needed, borrowings under its credit facility. As a result of the continued low natural gas prices, QEP plans to decrease capital
expenditures for the Haynesville Shale and other dry-gas development areas and increase capital expenditures for higher return
projects, including Pinedale, Uinta Basin Red Wash Mesaverde, and oil-directed horizontal drilling in the Williston Basin,
Powder River Basin and Midcontinent during 2013. QEP Energy has allocated approximately 98% of its 2013 total forecasted
capital expenditure budget to crude oil and liquids-rich natural gas plays. QEP plans to invest a total of approximately $120.0
million in capital expenditures during 2013 to grow its midstream business, including the expansion of its gathering system in
the Uinta Basin as well as the completion of a 10,000 Bbl/d expansion of the NGL fractionation facility located at the Blacks
Fork processing complex (expected to be completed in the second half of 2013). QEP Resources plans to invest approximately
$25.0 million in capital expenditures related to corporate activities, primarily the implementation of a new Enterprise Resource
Planning system. The aggregate levels of capital expenditures for 2013 and the allocation of those expenditures are dependent
on a variety of factors, including drilling results, natural gas and oil prices, industry conditions, the extent to which properties
or working interests are acquired, the availability of capital resources to fund the expenditures and changes in management's
business assessments as to where QEP's capital can be most profitably deployed. Accordingly, the actual levels of capital
expenditures and the allocation of those expenditures may vary materially from QEP's estimates.
64
Cash Flow from Financing Activities
During the year ended December 31, 2012, net cash proceeds from financing activities was $1,498.5 million compared to
$130.3 million during the year ended December 31, 2011. During 2012, QEP completed public offerings of $650.0 million and
$500.0 million of senior notes and entered into a $300.0 million Term Loan. QEP had borrowings from its credit facility of
$1,234.5 million and repayments on its credit facility of $1,151.0 million. In addition, QEP retired $6.7 million of its
outstanding senior notes. During the years ended December 31, 2012, 2011 and 2010, QEP paid dividends of $14.2 million,
$14.1 million and $7.0 million, respectively. In 2012, 2011 and 2010, QEP paid long-term debt issuance costs of $17.8 million,
$10.6 million and $16.6 million, respectively. At December 31, 2012, long-term debt consisted of $690.0 million outstanding
under its credit facility, $300.0 million under the Term Loan and $2,221.8 million in senior notes (excluding $4.9 million of net
original issue discount).
During the year ended December 31, 2011, net cash used in investing activities of $1,422.9 million exceeded net cash provided
by operating activities of $1,292.6 million by $130.3 million. For 2011, long-term debt increased by a net change of $207.1
million while short-term debt decreased by $58.5 million. All intercompany loans between Questar and QEP, which were
historically reported as notes payable in the Consolidated Balance Sheets, were repaid on June 30, 2010, in conjunction with
the Spin-off.
Off-Balance Sheet Arrangements
QEP may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations.
At December 31, 2012, the Company's material off-balance sheet arrangements and transactions included operating lease
arrangements, drilling and transportation contracts and undrawn letters of credit. There are no other transactions, arrangements,
or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect QEP's liquidity
or availability of, or requirements for capital resources. See "Contractual Cash Obligations and Other Commitments" below for
more information regarding off-balance sheet arrangements.
Settlement Agreement
On February 13, 2013, QEP executed the Chieftain Settlement Agreement, which provides for a cash settlement payment from
QEP in the amount of $115 million in exchange for a full release of all claims regarding the calculation, reporting and payment
of royalties from the sale of natural gas and its constituents for all periods prior to February 28, 2013. At December 31, 2012,
QEP has recorded an accrual of $115.0 million based on the January 2013 mediation and resulting Chieftain Settlement
Agreement. The Court has entered a Preliminary Order Approving Class Action Settlement. The payment of the $115 million
settlement amount will be made into escrow before the end of February 2013.
65
Contractual Cash Obligations and Other Commitments
In the course of ordinary business activities, QEP enters into a variety of contractual cash obligations and other commitments.
The following table summarizes the significant contractual cash obligations as of December 31, 2012:
Total
2013
Payments Due by Year (3)
2015
2016
2014
2017
After 2017
(in millions)
Long-term debt
$ 3,211.8
$
— $
— $
— $
866.8
$
300.0
$ 2,045.0
Interest on fixed-rate, long-term
debt (1)
Drilling contracts
Firm transportation and storage
NGL transportation
Fractionation
Asset Retirement Obligations (2)
Operating leases
Total
1,122.7
133.0
133.0
133.0
129.5
122.3
109.6
347.5
376.1
186.7
193.1
69.7
45.2
32.4
14.0
1.7
37.0
44.2
44.8
20.2
3.7
2.9
44.1
44.8
20.2
2.6
—
42.6
44.8
20.2
2.9
—
42.0
44.8
20.2
2.2
471.9
—
129.4
164.5
91.9
180.0
62.1
$ 5,609.6
$
6.7
302.7
$
6.5
289.4
$
6.6
254.2
6.5
$ 1,113.3
$
6.7
538.2
29.1
$ 3,111.8
____________________________
(1) Excludes variable rate debt interest payments related to the Company's credit facility and Term Loan.
(2) These future obligations are discounted estimates of future expenditures based on expected settlement dates. See Item 8 of
Part II of this Annual Report on Form 10-K, Note 4 - Asset Retirement Obligations, for additional information.
(3) This table excludes the Company's benefit plan liabilities as future payment dates are unknown. See Item 8 of Part II of this
Annual Report on Form 10-K, Note 11 - Employee Benefits, for additional information.
Impact of Inflation and Pricing
QEP deals in U.S. dollars. Inflation in the context of oil field services and goods has been significant in primary areas in which
QEP operates. Typically, as prices for oil and natural gas increase, associated costs rise. Conversely, cost declines are likely to
lag and may not adjust downward in proportion to declining prices. Changes in prices impact QEP's revenues, estimates of
reserves, assessments of any impairment of oil and natural gas properties, as well as values of properties being acquired or
sold. Price changes have the potential to affect QEP's ability to raise capital, borrow money, and retain personnel. While QEP
does not presently expect business costs to materially rise from where they are today, higher prices for oil and natural gas could
result in increases in the costs of materials, services and personnel.
Critical Accounting Policies, and Estimates
QEP's significant accounting policies are described in Note 1 to the consolidated financial statements included in Item 8 of Part
II of this Annual Report on Form 10-K. The Company's consolidated financial statements are prepared in accordance with U.S.
Generally Accepted Accounting Principles. The preparation of consolidated financial statements requires management to make
assumptions and estimates that affect the reported results of operations and financial position. The following accounting
policies may involve a higher degree of complexity and judgment on the part of management.
Gas and Oil Reserves
One of the most significant estimates the Company makes is the estimate of crude oil, natural gas and NGL reserves. Crude oil,
natural gas and NGL reserve estimates require significant judgments in the evaluation of all available geological, geophysical,
engineering and economic data. The data for a given field may change substantially over time as a result of numerous factors
including, but not limited to, additional development activity, production history, projected future production, economic
assumptions relating to commodity prices, operating expenses, severance and other taxes, capital expenditures and remediation
costs. The subjective judgments and variances in data for various fields make these estimates less precise than other estimates
included in the financial statement disclosures.
Estimates of proved gas and oil reserves significantly affect the Company's DD&A expense. For example, if estimates of
proved reserves decline, the DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved
66
reserves could also cause QEP to perform an impairment analysis to determine if the carrying amount of crude oil and natural
gas properties exceeds fair value and could result in an impairment charge, which would reduce earnings.
QEP Energy engages an independent reservoir engineering consultant to prepare estimates of the proved gas and oil reserves.
Reserve estimates are based on a complex and highly interpretive process that is subject to continuous revision as additional
production and development drilling information becomes available.
See Note 17 - Supplemental Oil and Gas Information (Unaudited), of Item 8 of this Annual Report on Form 10-K.
Successful Efforts Accounting for Gas and Oil Operations
The Company follows the successful efforts method of accounting for gas and oil property acquisitions, exploration,
development and production activities. Under this method, the acquisition costs of proved and unproved properties, successful
exploratory wells and development wells are capitalized. Other exploration costs, including geological and geophysical costs,
the delay rental and administrative costs associated with unproved property and unsuccessful exploratory well costs are
expensed. Costs to operate and maintain wells and field equipment are expensed as incurred. Capitalized costs of unproved
properties are reclassified as proved property when related proved reserves are determined or charged against the impairment
allowance when abandoned.
Capitalized proved property acquisition costs are amortized by field using the unit-of-production method based on proved
reserves. Capitalized exploratory well and development costs are amortized similarly by field based on proved developed
reserves. The calculation takes into consideration estimated future equipment dismantlement, surface restoration and property
abandonment costs, net of estimated equipment salvage values. Other property and equipment are generally depreciated using
the straight-line method over estimated useful lives or the unit-of-production method for certain processing plants. A gain or
loss is generally recognized only when an entire field is sold or abandoned, or if the unit-of-production amortization rate would
be significantly affected.
Impairment of Oil and Gas Properties
Proved gas and oil properties are evaluated on a field-by-field basis for potential impairment. Other properties are evaluated on
a specific-asset basis or in groups of similar assets, as applicable. Impairment is indicated when a triggering event occurs and
the sum of the estimated undiscounted future net cash flows of an evaluated asset is less than the asset's carrying value.
Triggering events could include, but are not limited to, an impairment of gas and oil reserves caused by mechanical problems,
faster-than-expected decline of reserves, lease-ownership issues, other-than-temporary decline in natural gas, NGL and crude
oil prices and changes in the utilization of midstream gathering and processing assets. If impairment is indicated, fair value is
calculated using a discounted-cash flow approach. Cash flow estimates require forecasts and assumptions for many years into
the future for a variety of factors, including commodity prices, operating costs and estimates of proved, probable and possible
reserves. Management's assessment of the results of exploration activities and availability of funds for future activities also
impact the amounts and timing of impairment provisions. During the years ended December 31, 2012, 2011 and 2010, QEP
recorded impairment charges of $107.6 million, $195.5 million and $0.7 million, respectively, on some of its higher cost,
proven properties in both Regions. The impairment charge related to the reduced value of these areas resulting from lower spot
prices and lower forward curve prices.
Unproved properties are evaluated on a specific-asset basis or in groups of similar assets, as applicable. The Company performs
periodic assessments of unproved oil and gas properties for impairment and recognizes a loss at the time of impairment. In
determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to,
current development and exploration drilling plans, favorable or unfavorable exploration activity on adjacent leaseholds, in-
house geologists' evaluation of the lease, future reserve cash flows and the remaining lease term. During the years ended
December 31, 2012, 2011 and 2010, QEP recorded impairment charges of $23.7 million, $20.3 million and $40.7 million,
respectively, on its unproved properties.
Asset Retirement Obligations
QEP is obligated to fund the costs of disposing of long-lived assets upon their abandonment. The majority of QEP's asset
retirement obligations (ARO) relate to the plugging of wells and the related abandonment of oil and gas properties. QEP's ARO
are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the
retirement obligation discounted at QEP's credit-adjusted risk-free interest rate. Revisions to estimated ARO can result from
changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimate timing of abandonment.
QEP's ARO liability at December 31, 2012 was $193.1 million.
67
Accounting for Derivative Contracts
The Company uses derivative contracts, typically fixed-price swaps and costless collars, to protect against a decline in the price
it receives from its natural gas, oil and NGL production. Accounting rules for derivatives require marking these instruments to
fair value at the balance sheet reporting date. The change in fair value is reported either in net income or AOCI depending on
the structure of the derivative. Prior to 2012, the Company structured the majority of its energy derivative instruments as cash
flow hedges as defined in ASC 815, Derivatives and Hedging. Changes in the fair value of cash flow hedges are recorded on
the balance sheet and in AOCI until the underlying gas or oil is produced. When a derivative is terminated before its contract
expires, the associated gain or loss is recognized in income over the life of the previously hedged production. Changes in the
fair value of derivative contracts that do not qualify for hedge accountings are included as part of operating income in the
Consolidated Statements of Operations.
Effective January 1, 2012, the Company elected to de-designate all of its natural gas, oil and NGL derivative contracts that had
previously been designated as cash flow hedges at December 31, 2011, and elected to discontinue hedge accounting
prospectively. Accordingly, changes in the fair value of commodity derivative contracts are reported in earnings as unrealized
gains (losses). See Part II, Item 8, Note 1 - Summary of Significant Accounting Policies, of this Annual Report on Form 10-K
for additional information.
Revenue Recognition
Revenues are recognized in the period that services are provided or products are delivered. QEP Energy uses the sales method
of accounting whereby revenue is recognized for all gas, oil and NGL sold to purchasers. Revenues include estimates for the
two most recent months using published commodity-price indexes and volumes supplied by field operators. A liability is
recorded to the extent that QEP Energy has an imbalance in excess of its share of remaining reserves in an underlying property.
QEP Marketing presents revenues on a gross revenue basis. QEP Marketing does not engage in speculative hedging
transactions, nor does it buy and sell energy contracts with the objective of generating profits on short-term differences in
prices.
Litigation and Other Contingencies
In accordance with ASC 450, Contingencies, an accrual is recorded for a loss contingency when its occurrence is probable and
damages can be reasonably estimated based on the anticipated most likely outcome or the minimum amount within a range of
possible outcomes. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing
contingencies is highly subjective and requires judgments about future events. When evaluating contingencies, QEP may be
unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question,
the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the
matters. QEP regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. The amount of
ultimate loss may differ from these estimates.
Environmental Obligations
Management makes judgments and estimates in accordance with applicable accounting rules when it establishes reserves for
environmental remediation, litigation and other contingent matters. Provisions for such matters are charged to expense when it
is probable that a liability has been incurred and reasonable estimates of the liability can be made. Estimates of environmental
liabilities are based on a variety of matters, including, but not limited to, the stage of investigation, the stage of the remedial
design, evaluation of existing remediation technologies, and presently enacted laws and regulations. In future periods, a number
of factors could significantly change QEP's estimate of environmental remediation costs, such as changes in laws and
regulations, changes in the interpretation or administration of laws and regulations, revisions to the remedial design,
unanticipated construction problems, identification of additional areas or volumes of contaminated soil and groundwater, and
changes in costs of labor, equipment and technology. Consequently, it is not possible for management to reliably estimate the
amount and timing of all future expenditures related to environmental matters and actual costs may vary significantly. See Part
II, Item 8, Note 9 - Commitments and Contingencies, of this Annual Report on form 10-K for additional information regarding
current environmental claims.
Benefit Plan Obligations
QEP maintains closed, non-contributory defined-benefit pension plans, including both a qualified and a supplemental plan.
QEP also provides certain health care and life insurance benefits for certain retired employees. Determination of the benefit
obligations for QEP's defined-benefit pension and postretirement plans impacts the recorded amounts for such obligations on
the Consolidated Balance Sheets and the amount of benefit expense recorded to the Consolidated Income Statement.
Accounting for pension and other postretirement benefit obligations involves many assumptions, the most significant of which
are the discount rate used to measure the present value of plan benefit obligations, the expected long-term rates of return on
68
plan assets, the rate of future increases in compensation levels of participating employees and the future level of health care
costs.
Share-Based Compensation
QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock options for accounting purposes.
The use of this model requires significant judgment with respect to the risk-free interest rate, expected price volatility, expected
dividend yield, and expected life.
Income Taxes
The amount of income taxes recorded by QEP requires interpretations of complex rules and regulations of various tax
jurisdictions throughout the United States. QEP has recognized deferred tax assets and liabilities for temporary differences,
operating losses and tax credit carryforwards. QEP routinely assesses the realizability of its deferred tax assets and reduces such
assets by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be
realized. QEP routinely assesses potential uncertain tax positions and, if required, establishes accruals for such amounts. The
accruals for deferred tax assets and liabilities, including deferred state income tax assets and liabilities, are subject to significant
judgment by management and are reviewed and adjusted routinely based on changes in facts and circumstances. Although
management considers its tax accruals adequate, material changes in these accruals may occur in the future, based on the
impact of tax audits, changes in legislation and resolution of pending or future tax matters.
Purchase Price Allocations
QEP occasionally acquires assets and assumes liabilities in transactions accounted for as business combinations, such as the
2012 Acquisition in the Williston Basin. In connection with a purchase business combination, the acquiring company must
allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Any
excess or shortage of amounts assigned to assets and liabilities over or under the purchase price is recorded as a gain on bargain
purchase or goodwill. The amount of goodwill or gain on bargain purchase recorded in any particular business combination can
vary significantly depending upon the values attributed to assets acquired and liabilities assumed.
In estimating the fair values of assets acquired and liabilities assumed in a business combination, QEP makes various
assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved crude oil
and natural gas properties. If sufficient market data is not available regarding the fair values of proved and unproved properties,
QEP must prepare estimates. To estimate the fair values of these properties, QEP prepares estimates of crude oil, NGL and
natural gas reserves. QEP estimates future prices to apply to the estimated reserves quantities acquired and estimates future
operating and development costs to arrive at estimates of future net cash flows. For estimated proved reserves, the future net
cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the
acquisition. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. To
compensate for the inherent risk of estimating and valuing unproved reserves, the discounted future net cash flows of probable
and possible reserves are reduced by additional risk-weighting factors.
Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future. A higher fair
value assigned to a property results in higher DD&A expense, which results in lower net earnings. Fair values are based on
estimates of future commodity prices, reserves quantities, operating expenses and development costs. This increases the
likelihood of impairment if future commodity prices or reserves quantities are lower than those originally used to determine fair
value, or if future operating expenses or development costs are higher than those originally used to determine fair value.
Impairment would have no effect on cash flows but would result in a decrease in net income for the period in which the
impairment is recorded. See Part II, Item 8, Note 2 - Acquisition, of this Annual Report on Form 10-K for additional
information regarding the 2012 Acquisition.
Recent Accounting Developments
See Recent Accounting Developments in Note 1 to the consolidated financial statements in Item 8 of Part II of this Annual
Report on Form 10-K.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
QEP's primary market risk exposures arise from changes in the market price for natural gas, oil and NGL, and to volatility in
interest rates. These risks can affect revenues and cash flows from operating, investing and financing activities. Commodity
prices have historically been volatile and are subject to wide fluctuations in response to relatively minor changes in supply and
demand. If commodity prices fluctuate significantly, revenues and cash flow may significantly decrease or increase. QEP
Energy and QEP Marketing also have long-term contracts for pipeline capacity and are obligated to pay for transportation
69
services with no guarantee that QEP will be able to fully utilize the contractual capacity of these transportation commitments.
In addition, a write-down of the Company's oil and gas properties may be required if future oil and natural gas commodity
prices experience a sustained, significant decline. Furthermore, the Company's credit facility and Term Loan have floating
interest rates which expose QEP to interest rate risk. To manage the Company's exposure to these risks, QEP enters into
commodity derivative contracts in the form of costless collars and fixed-price swaps to manage commodity price risk and
periodically interest rate swaps to manage interest rate risk.
Commodity Price Risk Management
QEP's subsidiaries use commodity price derivative instruments in the normal course of business to reduce the risk of adverse
commodity price movements. The Company's risk management policies provide for the use of derivative instruments to
manage this risk. However, these same arrangements typically limit future gains from favorable price movements. The types of
commodity derivative instruments utilized by the Company include fixed-price swaps and costless collars. The volume of
commodity derivative instruments utilized by the Company may vary from year to year. The derivative instruments currently
utilized by the Company do not have margin requirements or collateral provisions that would require payments prior to the
scheduled cash settlement dates. The Company does not enter into derivative contracts for speculative or trading purposes. As
of December 31, 2012, QEP held commodity price derivative contracts totaling 139.4 million MMBtu of natural gas, and 6.9
million barrels of oil. At December 31, 2011, the QEP derivative contracts consisted of 213.0 million MMBtu of natural gas,
2.0 million barrels of oil, and 53.9 million gallons of NGL.
70
The following table presents open 2013 derivative positions as of February 13, 2013:
QEP Energy Commodity Derivative Positions
Year
Type of Contract
Index
Natural gas sales
2013
2013
2014
2014
Oil sales
2013
2013
2014
Swap
Swap
Swap
Swap
Swap
Swap
Swap
NYMEX
IFNPCR
NYMEX
IFNPCR
NYMEX WTI
BRENTICE
NYMEX WTI
QEP Marketing Commodity Derivative Positions
Year
Type of Contract
Index
Natural gas sales
2013
Natural gas purchases
2013
2014
Swap
Swap
Swap
IFNPCR
IFNPCR
IFNPCR
Total
Volumes
(in millions)
(MMBtu)
51.1
65.7
18.3
7.3
(Bbls)
5.7
0.3
4.7
$
$
$
$
$
$
Swaps
Average price
per unit
3.79
5.66
4.21
4.00
98.35
107.80
92.99
Total
Volumes
(in millions)
(MMBtu)
4.0
(MMBtu)
0.2
0.1
Average Swaps
price
per MMBtu
$
$
$
3.78
2.88
3.02
Changes in the fair value of derivative contracts from December 31, 2011, to December 31, 2012, are presented below:
Commodity
derivative contracts
(in millions)
Net fair value of gas, oil and NGL derivative contracts outstanding at December 31, 2011
Contracts settled
Change in gas and oil prices on futures markets
Contracts added
Net fair value of gas, oil and NGL derivative contracts outstanding at December 31, 2012
$
$
395.9
(380.0)
139.4
37.5
192.8
The following table shows the sensitivity of the fair value of gas, oil and NGL derivative contracts to changes in the market
price of gas, oil and NGL and basis differentials:
Net fair value - asset (liability)
Fair value if market prices of gas, oil and NGL and basis differentials decline by 10%
Fair value if market prices of gas, oil and NGL and basis differentials increase by 10%
December 31, 2012
(in millions)
$
192.8
304.7
80.9
Utilizing the actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value
of these instruments by $111.9 million, while a 10% decrease in underlying commodity prices would increase the fair value of
71
these instruments by $111.9 million as of December 31, 2012. However, a gain or loss eventually would be substantially offset
by the actual sales value of the physical production covered by the derivative instruments. For additional information regarding
the Company's commodity derivative transactions, see Note 8 – Derivative Contracts, under Part II, Item 8 of this Annual
Report on Form 10-K.
Interest-Rate Risk Management
The Company's ability to borrow and the rates offered by lenders can be adversely affected by illiquid credit markets as
described in the Risk Factors in Item 1A of Part I of this Annual Report on Form 10-K. The Company's credit facility has a
floating interest rate which expose QEP to interest rate risk. At December 31, 2012, the Company had $690.0 million
outstanding under its credit facility. If interest rates were to increase or decrease 10% during the year ended December 31,
2012, at our average level of borrowing for those same periods, our interest expense would increase or decrease by $0.8 million
for the year ended December 31, 2012, or less than 1% of total interest expense. The remaining $2,221.8 million of the
Company's debt is fixed rate senior notes that are not subject to interest rate movements.
The Company's Term Loan has a floating interest rate which exposes QEP to interest rate risk. At December 31, 2012, the
Company had $300.0 million outstanding under the Term Loan. During the second quarter of 2012, QEP entered into interest
rate swap contracts with an aggregate notional amount of $300.0 million, to minimize the interest rate volatility risk associated
with its $300.0 million Term Loan. QEP pays a fixed interest rate and receives a floating interest rate indexed to the one-month
LIBOR. At December 31, 2012, the fair value of the interest rate swaps was a derivative liability balance of $6.2 million. A 50
basis point decrease in the one-month LIBOR rate would cause the fair value of the interest rate swaps to decrease by $5.5
million while a 50 basis point increase in the one-month LIBOR rate would cause the fair value of the interest rate swaps to
increase by $6.1 million. For additional information regarding the Company's debt instruments, see Note 8 – Debt, under Part
II, Item 8 of this Annual Report on Form 10-K.
72
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Financial Statements:
Report of Independent Registered Public Accounting Firm as of and for the year ended December 31, 2012
Page No.
74
Report of Independent Registered Public Accounting Firm as of December 31, 2011 and for the years ended
December 31, 2011 and 2010
Consolidated Statements of Operations, three years ended December 31, 2012
Consolidated Statements of Comprehensive Income (Loss), three years ended December 31, 2012
Consolidated Balance Sheets at December 31, 2012 and 2011
Consolidated Statements of Equity, three years ended December 31, 2012
Consolidated Statements of Cash Flows, three years ended December 31, 2012
Notes Accompanying the Consolidated Financial Statements
Financial Statement Schedule:
Valuation and Qualifying Accounts, for the three years ended December 31, 2012
75
76
77
78
79
80
81
124
All other schedules are omitted because they are not applicable or the required information is shown in the consolidated
financial statements or Notes thereto.
73
Report of Independent Registered Public Accounting Firm
To Board of Directors and Shareholders of QEP Resources, Inc.:
In our opinion, the accompanying consolidated balance sheet and the related consolidated statement of operations,
comprehensive income, equity, and cash flows present fairly, in all material respects, the financial position of QEP Resources,
Inc. at December 31, 2012 and the results of their operations and their cash flows for the year then ended in conformity with
accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement
schedule for the year ended December 31, 2012 appearing under Item 15(c) presents fairly, in all material respects, the
information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion,
the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012,
based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations
of the Treadway Commission (COSO). The Company's management is responsible for these financial statements and financial
statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness
of internal control over financial reporting, included in Management's Assessment of Internal Control Over Financial Reporting
under Item 9A. Our responsibility is to express opinions on these financial statements, financial statement schedule and on the
Company's internal control over financial reporting based on our integrated audit. We conducted our audits in accordance with
the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and
perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and
whether effective internal control over financial reporting was maintained in all material respects. Our audit of the financial
statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial
statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and
operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other
procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our
opinions.
As discussed in Note 1 to the financial statements, the Company discontinued hedge accounting effective January 1, 2012.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures
that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 21, 2013
74
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholder of
QEP Resources, Inc.
We have audited the accompanying consolidated balance sheets of QEP Resources, Inc. as of December 31, 2011, and the
related consolidated statements of operations, comprehensive income (loss), equity, and cash flows for each of the two years in
the period ended December 31, 2011. Our audits also included the financial statement schedule listed in the Index at Item 8 for
each of the two years in the period ended December 31, 2011. These financial statements and schedule are the responsibility of
the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on
our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial
position of QEP Resources, Inc. at December 31, 2011, and the consolidated results of its operations and its cash flows for each
of the two years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.
Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements
taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ Ernst & Young LLP
Denver, Colorado
February 24, 2012
75
QEP RESOURCES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
REVENUES
Natural gas sales
Oil sales
NGL sales
Gathering, processing and other
Purchased gas, oil and NGL sales
Total Revenues
OPERATING EXPENSES
Purchased gas, oil and NGL expense
Lease operating expense
Natural gas, oil and NGL transport & other handling costs
Gathering, processing and other
General and administrative
Separation costs
Production and property taxes
Depreciation, depletion and amortization
Exploration expenses
Abandonment and impairment
Total Operating Expenses
Net gain from asset sales
OPERATING (LOSS) INCOME
Realized and unrealized gains on derivative contracts (See Note 6)
Interest and other income
Income from unconsolidated affiliates
Loss from early extinguishment of debt
Interest expense
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME
TAXES
Income taxes
INCOME FROM CONTINUING OPERATIONS
Discontinued operations, net of income tax
NET INCOME
Net income attributable to noncontrolling interest
NET INCOME ATTRIBUTABLE TO QEP
Earnings Per Common Share Attributable to QEP
Basic from continuing operations
Basic from discontinued operations
Basic total
Diluted from continuing operations
Diluted from discontinued operations
Diluted total
Weighted-average common shares outstanding
Used in basic calculation
Used in diluted calculation
$
$
$
$
$
$
Year Ended December 31,
2012
2010
2011
(in millions, except per share amounts)
$
$
$
$
$
$
667.4
532.6
322.1
181.6
646.1
2,349.8
655.6
172.3
148.9
88.0
266.6
—
103.4
904.9
11.2
133.4
2,484.3
1.2
(133.3)
441.9
6.6
6.8
(0.6)
(122.9)
198.5
(66.5)
132.0
—
132.0
(3.7)
128.3
0.72
—
0.72
0.72
—
0.72
177.8
178.7
$
$
$
$
$
$
1,239.1
324.2
309.8
200.8
1,085.3
3,159.2
1,077.1
145.2
102.2
107.3
123.2
—
105.4
765.4
10.5
218.4
2,654.7
1.4
505.9
—
4.1
5.5
(0.7)
(90.0)
424.8
(154.4)
270.4
—
270.4
(3.2)
267.2
1.51
—
1.51
1.50
—
1.50
176.5
178.4
1,205.3
198.1
142.6
156.6
598.0
2,300.6
589.3
125.0
54.2
83.2
107.2
13.5
82.5
643.4
23.0
46.1
1,767.4
12.1
545.3
—
2.3
3.0
(13.3)
(84.4)
452.9
(167.0)
285.9
43.2
329.1
(2.9)
326.2
1.61
0.25
1.86
1.60
0.24
1.84
175.3
177.3
See notes accompanying the consolidated financial statements.
76
QEP RESOURCES, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
2012
Net income
Other comprehensive (loss) income, net of tax:
Effect of derivative financial instruments (1)
Pension and other postretirement plans adjustments:
Current year net actuarial gain (loss) (2)
Amortization of net actuarial loss (3)
Net prior service cost incurred (4)
Amortization of net prior service cost (5)
Net curtailment cost incurred (6)
Total pension and other postretirement plans adjustments
Other comprehensive (loss) income
Comprehensive (loss) income
Comprehensive income attributable to noncontrolling interests
Comprehensive (loss) income attributable to QEP
____________________________
$
$
Year Ended December 31,
2011
(in millions)
270.4
$
$
132.0
(171.1)
24.8
(10.0)
1.1
—
3.5
1.4
(4.0)
(175.1)
(43.1)
(3.7)
(46.8) $
(14.7)
—
—
3.5
—
(11.2)
13.6
284.0
(3.2)
280.8
$
2010
329.1
136.7
2.6
—
(33.8)
1.7
—
(29.5)
107.2
436.3
(2.9)
433.4
(1) Presented net of income tax benefit of $101.3 million during the year ended December 31, 2012, and net of income
tax expense of $14.7 million and $81.0 million during the years ended December 31, 2011 and 2010, respectively.
(2) Presented net of income tax benefit of $6.3 million and $9.2 million during the years ended December 31, 2012 and
2011, respectively, and net of income tax expense of $1.6 million for the year ended December 31, 2010.
(3) Presented net of income tax expense of $0.9 million during the year ended December 31, 2012.
(4) Presented net of income tax benefit of $20.9 million during the year ended December 31, 2010.
(5) Presented net of income tax expense of $2.2 million, $2.1 million and $1.0 million during the years ended
December 31, 2012, 2011 and 2010, respectively.
(6) Presented net of income tax expense of $0.8 million during the year ended December 31, 2012.
See notes accompanying the consolidated financial statements.
77
QEP RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
ASSETS
Current Assets
Cash and cash equivalents
Accounts receivable, net
Fair value of derivative contracts
Gas, oil and NGL inventories, at lower of average cost or market
Prepaid expenses and other
Total Current Assets
Property, Plant and Equipment (successful efforts method for gas and oil properties)
Proved properties
Unproved properties, net
Midstream field services
Marketing and other
Material and supplies
Total Property, Plant and Equipment
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production
Midstream field services
Marketing and other
Total Accumulated Depreciation, Depletion and Amortization
Net Property, Plant and Equipment
Investment in unconsolidated affiliates
Goodwill
Fair value of derivative contracts
Other noncurrent assets
TOTAL ASSETS
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances
Accounts payable and accrued expenses
Production and property taxes
Interest payable
Fair value of derivative contracts
Deferred income taxes
Total Current Liabilities
Long-term debt
Deferred income taxes
Asset retirement obligations
Fair value of derivative contracts
Other long-term liabilities
Commitments and contingencies (see Note 9)
EQUITY
Common stock - par value $0.01 per share; 500.0 million shares authorized; 178.5 million
and 177.2 million shares issued, respectively
Treasury stock - 0.1 million and 0.4 million shares, respectively
Additional paid-in capital
Retained earnings
Accumulated other comprehensive income
Total Common Shareholders' Equity
Noncontrolling interest
Total Equity
TOTAL LIABILITIES AND EQUITY
$
$
$
See notes accompanying the consolidated financial statements.
78
December 31,
2012
December 31,
2011
(in millions)
$
— $
387.5
188.7
13.1
60.4
649.7
10,234.3
937.9
1,634.9
64.6
61.9
12,933.6
4,258.1
357.9
18.1
4,634.1
8,299.5
41.2
59.5
4.1
54.5
9,108.5
39.7
635.9
41.8
36.9
2.6
5.0
761.9
3,206.9
1,493.5
191.4
3.6
137.5
$
$
—
397.4
273.7
16.2
43.7
731.0
8,172.4
326.8
1,463.6
49.8
87.6
10,100.2
3,339.2
297.5
14.6
3,651.3
6,448.9
42.2
59.5
123.5
37.6
7,442.7
29.4
457.3
40.0
24.4
1.3
85.4
637.8
1,679.4
1,484.7
163.9
—
124.8
1.8
(3.7)
462.1
2,773.0
32.8
3,266.0
47.7
3,313.7
9,108.5
$
1.8
(13.1)
431.4
2,673.5
207.9
3,301.5
50.6
3,352.1
7,442.7
QEP RESOURCES, INC.
CONSOLIDATED STATEMENTS OF EQUITY
Common Stock
Treasury Stock
Shares
Amount
Shares
Amount
Additional
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income(Loss)
Non-
controlling
Interest
Total
(in millions)
— $ — $
126.8 $ 2,538.2 $
87.1 $
54.9 $ 2,808.7
—
Balance at December 31, 2009
Questar common stock issued, net of repurchases
2010 net income
Dividends paid
Share-based compensation
Equity from Questar
Transfer Wexpro to Questar
Distribution of noncontrolling interest
Change in unrealized fair value of derivatives, net of tax
Change in pension and postretirement liability, net of tax
Balance at December 31. 2010
2011 net income
Dividends paid
Share-based compensation
Distribution from Questar and other
Distribution of noncontrolling interest
Change in unrealized fair value of derivatives, net of tax
Change in pension and postretirement liability, net of tax
Balance at December 31. 2011
2012 net income
Dividends paid
Share-based compensation
Distribution to QEP Education Foundation
Distribution of noncontrolling interest
174.6 $
0.4
—
—
0.9
—
—
—
—
—
175.9
—
—
1.3
—
—
—
—
177.2
—
—
1.3
—
—
Reclassification of previously deferred derivative gains
in OCI, net of tax
Change in pension and postretirement liability, net of tax
Balance at December 31. 2012
—
—
178.5 $
1.7
—
—
—
—
—
—
—
—
—
0.1
(0.1 )
(3.9 )
—
—
—
—
—
1.8
—
—
—
—
—
—
—
1.8
—
—
—
—
—
—
—
1.8
—
—
—
—
—
(0.1 )
—
—
(0.3 )
—
—
—
—
(0.4 )
—
—
0.2
0.1
—
—
—
—
—
—
(3.9 )
—
—
(9.2 )
—
—
—
—
(13.1 )
—
—
7.1
2.3
—
—
—
(0.1 ) $
—
—
(3.7 ) $
—
—
—
23.3
250.0
—
326.2
(15.9 )
—
—
(2.0 )
(428.5 )
—
—
—
—
—
—
398.1
2,420.0
—
—
33.3
—
—
—
—
431.4
—
—
30.7
—
—
—
—
267.2
(14.1 )
—
0.4
—
—
—
2,673.5
128.3
(14.2 )
(14.6 )
—
—
—
—
462.1 $ 2,773.0 $
—
—
—
—
—
—
—
136.7
(29.5 )
194.3
—
—
—
—
—
24.8
(11.2 )
207.9
—
—
—
—
—
(171.1 )
(4.0 )
32.8 $
—
2.9
—
—
—
—
(5.0 )
—
—
52.8
3.2
—
—
—
(5.4 )
—
—
50.6
3.7
—
—
—
(6.6 )
—
—
329.1
(15.9 )
19.5
250.0
(430.5 )
(5.0 )
136.7
(29.5 )
3,063.1
270.4
(14.1 )
24.1
0.4
(5.4 )
24.8
(11.2 )
3,352.1
132.0
(14.2 )
23.2
2.3
(6.6 )
(171.1 )
(4.0 )
47.7 $ 3,313.7
See notes accompanying the consolidated financial statements.
79
QEP RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
OPERATING ACTIVITIES
Net income
Discontinued operations, net of income tax
Adjustments to reconcile net income to net cash provided by operating activities:
$
Depreciation, depletion and amortization
Deferred income taxes
Abandonment and impairment
Share-based compensation
Amortization of debt issuance costs and discounts
Net gain from asset sales
Income from unconsolidated affiliates
Distributions from unconsolidated affiliates and dry exploratory well expense
Non-cash loss on early extinguishment of debt
Unrealized gain on derivative contracts
Changes in operating assets and liabilities
Accounts receivable
Inventories
Prepaid expenses
Accounts payable and accrued expenses
Federal income taxes
Other
Net Cash Provided by Operating Activities of Continuing Operations
INVESTING ACTIVITIES
Property acquisitions
Property, plant and equipment, including dry hole exploratory well expense
Proceeds from disposition of assets
Change in notes receivable
Net Cash Used in Investing Activities of Continuing Operations
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances
Long-term debt issued
Long-term debt issuance costs paid
Long-term debt repaid
Repayments of notes payable
Long-term debt extinguishment costs
Proceeds from credit facility
Repayments of credit facility
Other capital contributions
Equity contribution
Dividends paid
Excess tax benefit on share-based compensation
Distribution from Questar
Distribution to noncontrolling interest
Net Cash Provided by Financing Activities of Continuing Operations
CASH USED IN CONTINUING OPERATIONS
Cash provided by operating activities of discontinued operations
Cash used in investing activities of discontinued operations
Cash used in financing activities of discontinued operations
Effect of change in cash and cash equivalents of discontinued operations
Change in cash and cash equivalents
Beginning cash and cash equivalents
Ending cash and cash equivalents
$
Year Ended December 31,
2012
2011
2010
(in millions)
132.0
—
$
$
270.4
—
329.1
(43.2)
904.9
32.1
133.4
25.6
5.3
(1.2)
(6.8)
7.9
—
(63.2)
9.6
28.7
(16.8)
101.3
3.5
(0.3)
1,296.0
(1,401.0)
(1,398.7)
5.2
—
(2,794.5)
10.3
1,450.0
(17.8)
(6.7)
—
—
1,234.5
(1,151.0)
(2.2)
—
(14.2)
2.2
—
(6.6)
1,498.5
—
—
—
—
—
—
—
— $
765.4
156.8
218.4
22.0
4.1
(1.4)
(5.5)
8.1
0.7
(117.7)
(144.6)
(22.0)
1.6
127.8
17.0
(8.5)
1,292.6
(48.0)
(1,383.1)
8.2
—
(1,422.9)
9.9
—
(10.6)
(58.5)
—
—
591.5
(385.0)
0.7
—
(14.1)
1.6
0.2
(5.4)
130.3
—
—
—
—
—
—
—
— $
643.4
188.2
46.1
16.1
2.4
(12.1)
(3.0)
11.8
13.3
(121.7)
(32.6)
10.1
(16.2)
4.2
(30.9)
(7.5)
997.5
(109.3)
(1,359.7)
25.6
52.9
(1,390.5)
19.5
1,034.4
(16.6)
(91.5)
(39.3)
(4.9)
—
(761.5)
2.8
250.0
(7.0)
—
(7.2)
(5.0)
373.7
(19.3)
68.6
(39.9)
(26.9)
1.8
(19.3)
19.3
—
See notes accompanying the consolidated financial statements.
80
QEP RESOURCES, INC.
NOTES ACCOMPANYING THE CONSOLIDATED FINANCIAL STATEMENTS
Note 1 – Summary of Significant Accounting Policies
Nature of Business
QEP Resources, Inc. (QEP or the Company) is a holding company with three major lines of business: natural gas and crude oil
exploration and production; midstream field services; and energy marketing. These businesses are conducted through the
Company's three principal subsidiaries:
• QEP Energy Company (QEP Energy) acquires, explores for, develops, and produces natural gas, oil, and natural gas liquids
(NGL);
• QEP Field Services Company (QEP Field Services) provides midstream field services, including natural gas gathering,
processing, compression, and treating services, for affiliates and third parties; and
• QEP Marketing Company (QEP Marketing) markets affiliate and third-party natural gas and oil, and owns and operates an
underground gas-storage reservoir.
Operations are focused in two major regions: the Northern Region (primarily in North Dakota, Wyoming and Utah) and the
Southern Region (primarily Oklahoma, Louisiana, and the Texas Panhandle) of the United States. QEP's corporate headquarters
are located in Denver, Colorado.
Shares of QEP Resources' common stock trade on the New York Stock Exchange under the ticker symbol "QEP".
Principles of Consolidation
The consolidated financial statements contain the accounts of QEP and its majority-owned or controlled subsidiaries. The
consolidated financial statements were prepared in accordance with U.S. Generally Accepted Accounting Principles (GAAP)
and with the instructions for annual reports on Form 10-K and Regulations S-X and S-K. All significant intercompany accounts
and transactions have been eliminated in consolidation.
Effective May 18, 2010, Questar Market Resources, Inc., (Market Resources) then a wholly owned subsidiary of Questar
Corporation (Questar), merged with and into a newly-formed, wholly owned subsidiary, QEP, a Delaware corporation in order
to reincorporate in the State of Delaware (Reincorporation Merger). The Reincorporation Merger was affected pursuant to an
Agreement and Plan of Merger entered into between Market Resources and QEP. The Reincorporation Merger was approved
by the boards of directors of Market Resources and QEP and submitted to a vote of, and approved by, the Board of Directors of
Questar, as sole shareholder of Market Resources, and by Market Resources, as sole shareholder of QEP on May 18, 2010.
On June 30, 2010, Questar distributed all of the shares of common stock of QEP held by Questar to Questar shareholders in a
tax-free, pro rata dividend (the Spin-off). Each Questar shareholder received one share of QEP common stock for each one
share of Questar common stock held (including fractional shares) at the close of business on the record date. In connection
therewith, QEP distributed Wexpro Company (Wexpro), a wholly owned subsidiary of QEP at the time, to Questar. In addition,
Questar contributed $250.0 million of equity to QEP prior to the Spin-off.
The financial information presented in this Annual Report on Form 10-K presents QEP's financial results as an independent
company separate from Questar and reflects Wexpro's financial condition and operating results as discontinued operations for
all periods presented. A summary of discontinued operations can be found in Note 13 to the consolidated financial statements.
All dollar and share amounts in this Form 10-K are in millions, except per-share information and where otherwise noted.
Investment in Unconsolidated Affiliates
QEP uses the equity method to account for investment in unconsolidated affiliates where it does not have control, but has
significant influence. The investment in unconsolidated affiliates on the Company's consolidated balance sheets equals the
Company's proportionate share of equity reported by the unconsolidated affiliates. Investment is assessed for possible
impairment when events indicate that the fair value of the investment may be below the Company's carrying value. When such
81
a condition is deemed to be other than temporary, the carrying value of the investment is written down to its fair value, and the
amount of the write-down is included in the determination of net income.
The principal unconsolidated affiliates and QEP's ownership percentage as of December 31, 2012 and 2011, were Uintah Basin
Field Services, LLC, (38%) and and Three Rivers Gathering, LLC, (50%), both limited liability companies engaged in
gathering and compressing natural gas.
Reclassifications
In 2011, "Gathering, processing and other" revenues included "NGL" which were reclassified to conform with the current
period presentation on the Consolidated Statement of Operations. The NGL reclassification is all within "Revenues" and has no
effect on income from continuing operations, net income or earnings per share. Additionally, QEP reclassified "Materials and
supplies" as of December 31, 2011, from current to long-term on the Consolidated Balance Sheet for consistency with current
period presentation.
Use of Estimates
The preparation of the consolidated financial statements and notes in conformity with GAAP requires that management
formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent assets
and liabilities. A significant item that requires management's estimates and assumptions is the estimate of proved natural gas,
oil and NGL reserves which are used in the calculation of depreciation, depletion and amortization rates of its gas and oil
properties, impairment of proved properties and asset retirement obligations. Changes in estimated quantities of its reserves
could impact the Company's reported financial results as well as disclosures regarding the quantities and value of proved gas
and oil reserves. Other items subject to estimates and assumptions include the carrying amount of property, plant and
equipment and goodwill, assigning fair value and allocating purchase price in connection with business combinations, valuation
allowances for receivables, income taxes, valuation of derivatives instruments, accrued liabilities, accrued revenue and related
receivables and obligations related to employee benefits, among others. Although management believes these estimates are
reasonable, actual results could differ from these estimates.
Revenue Recognition
QEP subsidiaries recognize revenues in the period that services are provided or products are delivered. Revenues associated
with the sale of natural gas and oil are accounted for using the sales method, whereby revenue is recognized as gas and oil is
sold to purchasers. A liability is recorded to the extent that the Company has sold volumes in excess of its share of remaining
gas and oil reserves in an underlying property. QEP's imbalance obligations at December 31, 2012 and 2011, were $13.2
million and $13.3 million, respectively.
QEP Marketing reports revenues on a gross basis because, in the judgment of management, the nature and circumstances of its
marketing transactions are consistent with guidance for gross revenue reporting. QEP Marketing markets affiliate and third-
party natural gas, oil and NGL volumes. QEP Marketing uses derivatives to secure a known price for a specific volume over a
specific time period. QEP Marketing does not engage in speculative hedging transactions, nor does it buy and sell energy
contracts with the objective of generating profits on short-term differences in price. QEP Marketing has not engaged in buy/sell
arrangements, as described in ASC 845-10-25-4, Accounting for Purchases and Sales of Inventory with the Same Counterparty.
Cash and Cash Equivalents
Cash equivalents consist principally of repurchase agreements with maturities of three months or less. The repurchase
agreements are highly liquid investments in overnight securities made through commercial-bank accounts that result in
available funds the next business day.
82
Supplemental cash flow information is shown in the below table:
Supplemental Disclosures:
Cash paid for interest, net of capitalized interest
Cash paid (received) for income taxes
Non-cash investing activities
Change in capital expenditure accrual balance
Accounts Receivable Trade
Year Ended December 31,
2012
105.1
30.0
2011
(in millions)
$
90.5
(28.5)
$
2010
80.2
14.0
88.5
$
14.7
$
16.9
$
$
Accounts receivable trade consists mainly of receivables from oil and gas purchasers and joint interest owners on properties the
Company operates. For receivables from joint interest owners, the Company has the ability to withhold future revenue
disbursements to recover any non-payment of joint interest billings. Generally, the Company's oil and gas receivables are
collected and bad-debts are minimal. Bad-debt expense associated with accounts receivable for the years ended December 31,
2012 and 2011 was $1.4 million and $0.2 million, respectively, and a credit of $0.3 million in 2010. The Company routinely
assesses the recoverability of all material trade and other receivables to determine their collectability. The allowance for bad-
debt expenses was $2.8 million at December 31, 2012, and $1.7 million at December 31, 2011.
Property, Plant and Equipment
Property, plant and equipment balances are stated at historical cost. Material and supplies inventories are valued at the lower of
cost or market. Maintenance and repair costs are expensed as incurred with the exception of compressor maintenance costs,
which are capitalized and depreciated. Significant accounting policies for our property, plant and equipment are as follows:
Gas and oil properties
QEP Energy uses the successful efforts method to account for gas and oil properties. The costs of acquiring leaseholds, drilling
development wells, drilling successful exploratory wells, purchasing related support equipment and facilities are capitalized.
Geological and geophysical studies and other exploratory activities are expensed as incurred. Costs of production and general-
corporate activities are expensed in the period incurred. A gain or loss is generally recognized only when an entire field is sold or
abandoned, or if the unit-of-production depreciation, depletion and amortization rate would be significantly affected.
Capitalized costs of unproved properties are reclassified as proved property when related proved reserves are determined or
charged against the impairment allowance when abandoned.
Capitalized exploratory well costs
The Company capitalizes exploratory well costs until it determines whether an exploratory well is commercial or
noncommercial. If the Company deems the well commercial, capitalized costs are depreciated on a field basis using the unit-of-
production method and the estimated proved developed gas and oil reserves. If the Company concludes that the well is
noncommercial, well costs are immediately charged to exploration expense. Exploratory-well costs capitalized for a period
greater than one year since the completion of drilling are expensed unless the Company remains engaged in substantial
activities to assess whether the well is commercial.
Depreciation, depletion and amortization
Capitalized proved leasehold costs are depleted on a field-by-field basis using the unit-of-production method and the estimated
proved gas and oil reserves. Oil and NGL volumes are converted to natural gas equivalents using the ratio of one barrel of
crude oil, condensate or NGL to 6,000 cubic feet of natural gas. Capitalized costs of exploratory wells that have found proved
gas and oil reserves and capitalized development costs are depreciated using the unit-of-production method based on estimated
proved developed reserves for a successful effort field pool. The Company capitalizes an estimate of the fair value of future
abandonment costs.
Depreciation, depletion and amortization for the remaining Company properties is based upon rates that will systematically
charge the costs of assets against income over the estimated useful lives of those assets using either a straight-line or unit-of-
production method. Investment in gas gathering and processing fixed assets is charged to expense using either the straight-line
or unit-of-production method depending upon the facility. The estimated useful lives of those assets depreciated under the
straight-line basis generally range as follows:
83
Buildings
Leasehold improvements
Service, transportation and field service equipment
Furniture and office equipment
10 to 30 years
3 to 10 years
3 to 7 years
3 to 7 years
Impairment of Long-Lived Assets
Proved gas and oil properties are evaluated on a field-by-field basis for potential impairment. Impairment is indicated when a
triggering event occurs and/or the sum of the estimated undiscounted future net cash flows of an evaluated asset is less than the
asset's carrying value. Triggering events could include, but are not limited to, an impairment of gas and oil reserves caused by
mechanical problems, faster-than-expected decline of reserves, lease-ownership issues, declines in natural gas, NGL and crude
oil prices and changes in the utilization of midstream gathering and processing assets. If impairment is indicated, fair value is
calculated using a discounted-cash flow approach. Cash flow estimates require forecasts and assumptions for many years into
the future for a variety of factors, including commodity prices, operating costs, and estimates of proved, probable and possible
reserves. Cash flow estimates relating to future cash flows from probable and possible reserves are reduced by additional risk-
weighting factors.
Unproved properties are evaluated on a specific-asset basis or in groups of similar assets, as applicable. The Company performs
periodic assessments of unproved oil and gas properties for impairment and recognizes a loss at the time of impairment. In
determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to,
current development and exploration drilling plans, favorable or unfavorable exploration activity on adjacent leaseholds, in-
house geologists' evaluation of the lease, future reserve cash flows and the remaining lease term.
During the year ended December 31, 2012, QEP recorded abandonment and impairment charges of $133.4 million on its oil
and gas properties. Of the $133.4 million abandonment and impairment charges during the year ended December 31, 2012,
$107.6 million related to price-related impairment charges on proved properties and $23.7 million related to impairment on
unproved properties. The impairment charges were related to the reduced value of certain fields resulting from lower natural
gas, crude oil and NGL prices and impairments of unproven leasehold acquisition costs. Of the $133.4 million abandonment
and impairment charges during the year ended December 31, 2012, $104.8 million was related to oil and gas properties in the
Southern Region and $28.6 million was related to oil and gas properties in the Northern Region. During the year ended
December 31, 2011, QEP recorded abandonment and impairment charges of $218.4 million, $173.1 million were related to
properties in the Northern Region with the remaining $45.3 million related to properties in the Southern Region. Of the $218.4
million abandonment and impairment charges during the year ended December 31, 2011, $195.5 million related to the
impairment charges on proved properties and $20.3 million related to impairment on unproved properties. During the year
ended December 31, 2010, QEP recorded abandonment and impairment charges of $46.1 million, of which $0.7 million related
to proved property impairments and $40.7 million related to impairment on unproved properties.
Asset Retirement Obligations
Asset retirement obligations (ARO) associated with the retirement of tangible long-lived assets are recognized as liabilities
with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the tangible asset,
including the asset retirement costs, is depreciated over the useful life of the asset. ARO are recorded at estimated fair value,
measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the
Company's credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are
accreted to their expected settlement value. If estimated future costs of ARO change, an adjustment is recorded to both the asset
retirement obligation and the long-lived asset. Revisions to estimated ARO can result from changes in retirement cost
estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.
Capitalized Interest
The Company capitalizes interest costs during the construction phase of large capital projects that meet certain criteria.
Capitalized interest was $3.4 million, $3.0 million and $3.1 million during the years ended December 31, 2012, 2011 and 2010,
respectively.
Litigation and Other Contingencies
In accordance with ASC 450, Contingencies, an accrual is recorded for a loss contingency when its occurrence is probable and
damages can be reasonably estimated based on the anticipated most likely outcome or the minimum amount within a range of
possible outcomes. QEP regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. The
amount of ultimate loss may differ from these estimates. See Note 9 - Commitments and Contingencies, for additional
information.
84
Except for environmental contingencies acquired in a business combination, which are recorded at fair value, QEP accrues
losses associated with environmental obligations when such losses are probable and can be reasonably estimated. Accruals for
estimated environmental losses are recognized no later than at the time the remediation feasibility study, or the evaluation of
response options, is complete. These accruals are adjusted as additional information becomes available or as circumstances
change. Future environmental expenditures are not discounted to their present value. Recoveries of environmental costs from
other parties are recorded separately as assets at their undiscounted value when receipt of such recoveries is probable.
Goodwill
Goodwill represents the excess of the amount paid over the fair value of net assets acquired in a business combination and is
not subject to amortization. As of December 31, 2012 and 2011, goodwill was $59.5 million and related to the Uinta Basin
reporting unit within QEP Energy. Goodwill is tested for impairment at a minimum of once a year or when a triggering event
occurs using the income approach. Under the income approach, the fair value is estimated based on the value of expected future
cash flows. Key assumptions used in the cash flow model consider estimated quantities of crude oil, NGL and natural gas
reserves, including both proved reserves and risk-adjusted unproved reserves; estimates of market prices considering forward
commodity price curves as of the measurement date; and estimates of operating, administrative and capital costs adjusted for
inflation. The undiscounted net cash flows of the reporting unit to which the goodwill relates are evaluated. Impairment is
indicated if undiscounted cash flows are less than the carrying value of the assets. The amount of the impairment is measured
using a discounted, cash flow model considering future revenues, operating costs, a risk-adjusted discount rate and other
factors. There have been no goodwill impairments.
Derivative Instruments
Effective January 1, 2012, the Company elected to de-designate all of its natural gas, oil and NGL derivative contracts that had
previously been designated as cash flow hedges and has elected to discontinue hedge accounting prospectively. Accordingly, all
realized and unrealized gains and losses are recognized in earnings immediately as derivative contracts are settled and marked-
to-market. For the year ended December 31, 2012, unrealized gains of $63.2 million were included in income that, prior to
January 1, 2012, would have been deferred in Accumulated Other Comprehensive Income (AOCI) under hedge accounting
(Refer to Note 6 – Derivative Contracts, for additional information). At December 31, 2011, AOCI consisted of $395.9 million
($248.6 million after tax) of unrealized gains, representing the mark-to-market value of the Company's cash flow hedges as of
the balance sheet date, less any ineffectiveness recognized. As a result of discontinuing hedge accounting, such mark-to-market
values at December 31, 2011, were frozen in AOCI as of the de-designation date and are being reclassified into earnings as the
original hedged transactions occur and effect earnings. QEP expects to reclassify into earnings from AOCI the remaining frozen
value, $123.5 million ($77.6 million after tax), related to de-designated natural gas, oil and NGL hedges during 2013.
All of QEP's derivative contracts are net settled in cash without delivery of product. These contracts also have a nominal
quantity and exchange an index price for a fixed price, and are net settled with the brokers as the price bulletins become
available. These derivative contracts are recorded in revenues or cost of sales in the month of settlement. Basis-only swaps are
used to manage the risk of widening basis differentials. These contracts are marked to market monthly with any change in the
valuation recognized in the determination of income.
Credit Risk
The Northern and Southern Regions constitute the Company's primary market areas. Exposure to credit risk may be affected by
the concentration of customers in these regions due to changes in economic or other conditions. Customers include individuals
and numerous commercial and industrial enterprises that may react differently to changing conditions. Management believes
that its credit-review procedures, loss reserves, customer deposits and collection procedures have adequately provided for usual
and customary credit-related losses. Commodity-based hedging arrangements also expose the Company to credit risk. The
Company monitors the creditworthiness of its counterparties, which generally are major financial institutions and energy
companies. Loss reserves are periodically reviewed for adequacy and may be established on a specific case basis. QEP requests
credit support and, in some cases, fungible collateral, financial guarantees, letters of credit or prepayment from companies with
unacceptable credit risks. The Company has master-netting agreements with some counterparties that allow the offsetting of
receivables and payables in a default situation.
The Company's five largest customers accounted for 37%, 32%, and 27% in aggregate, of QEP revenues during the years ended
December 31, 2012, 2011 and 2010, respectively. During the year ended December 31, 2012, Chevron U.S.A. Inc. and
Enterprise Products Operating, L.P. accounted for 13% and 10%, respectively, of the Company's total revenues. Management
believes that the loss of either customer, or any other customer, would not have a material effect on the financial position or
85
results of operations of QEP since there are numerous potential purchasers of its production. During the years ended December
31, 2011 and 2010, each of the five largest customers sales were below 10% of QEP's total revenues.
Income Taxes
Deferred income taxes are provided for the temporary differences arising between the book and tax carrying amounts of assets
and liabilities. These differences create taxable or tax-deductible amounts for future periods. The Company records interest
earned on income tax refunds in interest and other income and records penalties and interest charged on tax deficiencies in
interest expense.
ASC 740, Income Taxes, specifies the accounting for uncertainty in income taxes by prescribing a minimum recognition
threshold for a tax position to be reflected in the financial statements. If recognized, the tax benefit is measured as the largest
amount of tax benefit that is more-likely-than-not to be realized upon ultimate settlement. Management has considered the
amounts and the probabilities of the outcomes that could be realized upon ultimate settlement and believes that it is more-
likely-than-not that the Company's recorded income tax benefits will be fully realized. There were no unrecognized tax benefits
at the beginning or at the end of the twelve-month periods ended December 31, 2012, 2011 and 2010. The federal income tax
returns for 2011 and 2010 are currently under examination by the Internal Revenue Service. Income tax returns for 2012 have
not yet been filed. Most state tax returns for 2009 and subsequent years remain subject to examination.
Treasury Stock
We record treasury stock purchases at costs, which includes incremental direct transaction costs. Amounts are recorded as a
reduction in shareholders' equity in the consolidated balance sheets. Acquired treasury stock is used for stock grants to
employees; refer to Note 10 - Share-Based Compensation for additional information.
Earnings Per Share
Basic earnings per share (EPS) are computed by dividing net income attributable to QEP by the weighted-average number of
common shares outstanding during the reporting period. Diluted EPS includes the potential increase in the number of
outstanding shares that could result from the exercise of in-the-money stock options. QEP's unvested restricted shares are
considered issued and outstanding, the historical forfeiture rate is minimal and the restricted shares receive dividends.
Unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents are considered
participating securities and are included in the computation of earnings per share pursuant to the two-class method. The
Company's unvested restricted stock awards contain nonforfeitable dividend rights and participate equally with common stock
with respect to dividends issued or declared. However, the Company's unvested restricted stock does not have a contractual
obligation to share in losses of the Company. The Company's unexercised stock options do not contain rights to dividends.
Under the two-class method, the earnings used to determine basic earnings per common share are reduced by an amount
allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating
securities since the securities are not obligated to share in Company losses. Use of the two-class method has an insignificant
impact on the calculation of basic and diluted earnings per common share. A reconciliation of the components of basic and
diluted shares used in the EPS calculation follows:
Weighted-average basic common shares outstanding
Potential number of shares issuable under the Long-Term Stock Incentive Plan
Average diluted common shares outstanding
Share-Based Compensation
2012
177.8
0.9
178.7
December 31,
2011
(in millions)
176.5
1.9
178.4
2010
175.3
2.0
177.3
QEP issues stock options and restricted shares to certain officers, employees and non-employee directors under its Long-Term
Stock Incentive Plan (LTSIP). QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock
options for accounting purposes. The granting of restricted shares results in recognition of compensation cost measured at the
grant-date market price. QEP uses an accelerated method in recognizing share-based compensation costs with graded-vesting
periods. Stock options held by employees generally vest in three equal, annual installments and primarily have terms of seven
86
years. Restricted shares vest in equal installments over a specified number of years after the grant date with the majority vesting
in three years. Non-vested restricted shares have voting and dividend rights; however, sale or transfer is restricted. At the time
of the Spin-off, all outstanding options and restricted stock were bifurcated. The Company also awards performance share units
which are paid out in cash that is dependent upon the Company's total shareholder return compared to a group of its peers over
a three-year period. The performance share unit's compensation cost is equal to its fair value as of the period end and is
classified as a liability. For a summary of LTSIP transactions see Note 10—Share-Based Compensation.
Pension Plans, Other Postretirement Benefits and Defined-Contribution Plans
QEP measures pension plan assets at fair value. Defined-benefit plan obligations and costs are actuarially determined,
incorporating the use of various assumptions. Critical assumptions for pension and other postretirement plans include the
discount rate, the expected rate of return on plan assets (for funded pension plans), the rate of future compensation increases
and the health care cost trend rate. Other assumptions involve demographic factors such as retirement, mortality and turnover.
QEP evaluates and updates its actuarial assumptions at least annually.
Comprehensive Income
Comprehensive income is the sum of net income attributable to QEP as reported in the Consolidated Statements of Operations
and changes in the components of other comprehensive income. Other comprehensive income includes certain items that are
recorded directly to equity and classified as AOCI. One component of other comprehensive income is changes in the market
value of commodity-based derivative instruments that qualified for hedge accounting. Income or loss associated with
commodity-based derivative instruments that qualified for hedge accounting is realized when the natural gas, oil or NGL
underlying the derivative instrument is sold. Comprehensive income also includes changes in the under-funded portion of the
defined benefit pension plans and other postretirement benefits plans and changes in deferred income taxes on such amounts.
These transactions are not the culmination of the earnings process but result from periodically adjusting historical balances to
fair value.
Business Segments
Line of business information is presented according to senior management's basis for evaluating performance considering
differences in the nature of products, services and regulation. QEP's lines of business are QEP Energy, QEP Field Services, and
QEP Marketing and other corporate activities not attributable to a line of business.
Recent Accounting Developments
In December of 2011, the FASB issued ASU 2011-11, Disclosures about Offsetting Assets and Liabilities, which enhances
disclosure requirements regarding an entity's financial instruments and derivative instruments that are offset or subject to a
master netting arrangement. This information about offsetting and related netting arrangements will enable users of financial
statements to understand the effect of those arrangements on the entity's financial position, including the effect of rights of
setoff. The amendments are required for annual reporting periods beginning after January 1, 2013, and interim periods within
those annual periods. QEP is evaluating the impact of this ASU on its disclosure requirements.
In July of 2012, the FASB issued ASU 2012-02, Intangibles - Goodwill and Other: Testing Indefinite-Lived Intangible Assets
for Impairment, which revises the way an entity can test indefinite-lived intangible assets for impairment by allowing an entity
to first assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely
than not that the indefinite-lived intangible asset is impaired. If there is no indication of impairment from the qualitative
impairment test, the entity is not required to complete a quantitative impairment test of determining and comparing the fair
value with the carrying amount of the indefinite-lived asset. Under the guidance in this ASU, an entity also has the option to
bypass the qualitative assessment in any period and proceed directly in performing the quantitative impairment test and can
resume performing the qualitative assessment in any subsequent period. The amendments are effective for annual and interim
impairment tests performed for fiscal years beginning after September 15, 2012. The adoption of this standard will allow the
Company to more efficiently complete the annual goodwill impairment test but will not have a significant impact on the
Company's consolidated financial statements.
87
Note 2 - Acquisition
On September 27, 2012, QEP Energy completed an acquisition of oil and gas properties in the Williston Basin for an aggregate
purchase price of approximately $1.4 billion, subject to post-closing adjustments (the 2012 Acquisition). The properties are
located in Williams and McKenzie counties of North Dakota, approximately 12 miles west of QEP's existing core acreage in
the Williston Basin.
The 2012 Acquisition meets the definition of a business combination under ASC 805, Business Combinations, as it included
proved properties. QEP allocated the cost of the 2012 Acquisition to assets acquired and liabilities assumed based on fair values
as of the acquisition date. Revenues of $63.7 million and net income of $14.9 million generated from the acquired properties
for the fourth quarter of 2012 and have been included in QEP's Consolidated Statements of Operations for the year ended
December 31, 2012. During the year ended December 31, 2012, QEP Energy's acquisition-related costs of $1.1 million are
included in "General and administrative" on the Consolidated Statements of Operations.
QEP Energy recorded the 2012 Acquisition on its Consolidated Balance Sheets; however, the final purchase price is subject to
revision based on the settlement of post-closing adjustments. The following table presents a summary of the preliminary
purchase accounting entries:
Consideration given:
Cash consideration
Amounts recognized for preliminary fair value of assets acquired and liabilities assumed:
Proved properties
Unproved properties
Asset retirement obligations
Liabilities assumed
Other assets acquired
Total fair value
As of December 31, 2012
(in millions)
$
$
$
1,388.7
713.8
679.4
(0.9)
(4.4)
0.8
1,388.7
The following unaudited, pro forma results of operations are provided for the years ended December 31, 2012 and 2011, as
though the 2012 Acquisition had been completed as of the beginning of January 1, 2011. These supplemental pro forma results
of operations are provided for illustrative purposes only and may not be indicative of the actual results that would have been
achieved by the properties for the periods presented or that may be achieved by the properties in the future. Future results may
vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as
well as other factors. The pro forma information is based on QEP's consolidated results of operations for the years ended
December 31, 2012 and 2011, on the acquired properties historical results of operations and on estimates of the effect of the
transaction on the combined results. The pro forma results of operations have been prepared by adjusting the historical results
of QEP to include the historical results of the acquired properties based on information provided by the seller and the impact of
the preliminary purchase price allocation. The pro forma results of operations do not include any cost savings or other synergies
that may result from the 2012 Acquisition or any estimated costs that have been or will be incurred by the Company to integrate
the properties.
Year ended December 31,
2012
2011
Actual
Pro forma
Actual
Pro forma
(in millions, except per share data)
Revenues
Net income attributable to QEP
Earnings per common share attributable to QEP
Basic
Diluted
$
$
2,349.8
$
2,485.3
$
3,159.2
$
128.3
143.0
267.2
$
0.72
0.72
88
$
0.80
0.80
$
1.51
1.50
3,236.7
259.8
1.47
1.46
Note 3 - Capitalized Exploratory Well Costs
Net changes in capitalized exploratory well costs are presented in the table below and exclude amounts that were capitalized
and subsequently expensed in the period. The balance at December 31, 2012, 2011 and 2010, represents the amount of
capitalized exploratory well costs that are pending the determination of proved reserves.
Balance at January 1,
Additions to capitalized exploratory well costs pending the determination of proved
reserves
Reclassifications to proved properties after the determination of proved reserves
Capitalized exploratory well costs charged to expense
Balance at December 31,
Note 4 – Asset Retirement Obligations
2012
2011
2010
(in millions)
$
5.0 $ 13.6 $ 51.7
12.7
(15.6)
—
2.1 $
12.2
—
(50.3)
(8.3)
(0.3)
—
5.0 $ 13.6
$
QEP records asset retirement obligations (ARO) when there are legal obligations associated with the retirement of tangible
long-lived assets. The Company's ARO liability applies primarily to abandonment costs associated with gas and oil wells,
production facilities and certain other properties. The fair values of such costs are estimated by Company personnel based on
abandonment costs of similar assets and depreciated over the life of the related assets. Revisions to the ARO liability occur due
to changes in estimated abandonment costs and well economic lives. The ARO liability is adjusted to present value each period
through an accretion calculation using a credit-adjusted risk-free interest rate. Of the $193.1 million ARO liability, $1.7 million
was included as a liability in "Accounts payable and accrued expenses" on the Consolidated Balance Sheet.
The following is a reconciliation of the changes in the asset retirement obligation for the periods specified below:
ARO liability at January 1,
Accretion
Liabilities incurred
Revisions
Liabilities settled
ARO liability at December 31,
Note 5 – Fair Value Measurements
Asset Retirement Obligations
2012
2011
(in millions)
$
163.9
10.5
8.5
11.1
(0.9)
193.1
$
148.3
9.7
7.9
—
(2.0)
163.9
$
$
QEP measures and discloses fair values in accordance with the provisions of ASC 820, Fair Value Measurements. This
guidance defines fair value in applying GAAP, establishes a framework for measuring fair value and expands disclosures about
fair-value measurements, but does not change existing guidance as to whether or not an instrument is carried at fair value. ASC
820 also establishes a fair-value hierarchy. Level 1 inputs are quoted prices (unadjusted) for identical assets or liabilities in
active markets that the Company has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted
prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are
unobservable inputs for the asset or liability.
QEP has determined that its commodity derivative instruments are Level 2. The Level 2 fair value of commodity derivative
contracts (see Note 6 - Derivative Contracts) is based on market prices posted on the NYMEX on the last trading day of the
reporting period and industry standard discounted cash flow models. QEP primarily applies the market approach for recurring
fair value measurements and maximizes its use of observable inputs and minimizes its use of unobservable inputs. QEP
considers bid and ask prices for valuing the majority of its assets and liabilities measured and reported at fair value. In addition
to using market data, QEP makes assumptions in valuing its assets and liabilities, including assumptions about risk and the
89
risks inherent in the inputs to the valuation technique. The Company's policy is to recognize significant transfers between levels
at the end of the reporting period.
However, certain of the Company's commodity derivative instruments are valued using industry standard models that consider
various inputs, including quoted forward prices for commodities, time value, volatility, and current market and contractual
prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are
observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are
supported by observable prices at which transactions are executed in the marketplace. The determination of fair value for
derivative assets and liabilities also incorporates nonperformance risk for counterparties and for QEP. Derivative contract fair
values are reported on a net basis to the extent a legal right of offset with the counterparty exists.
In addition, QEP has interest rate swaps that it has determined are Level 2. The fair values of the interest rate swaps are
determined using the market standard methodology of discounting the future expected cash flows that would occur under the
contractual terms of the swap. The variable interest rates used in the calculation of projected cash flows are based on an
expectation of future interest rates derived from observable market interest rate curves. QEP incorporates credit valuation
adjustments to reflect both its nonperformance risk and the respective counterparty's nonperformance risk in the fair value
measurements. While the credit valuation adjustments are not observable inputs, they are not significant to the overall valuation
and the other inputs used to value the interest rate swaps are observable Level 2 inputs.
The fair value of financial assets and liabilities at December 31, 2012 and 2011, is shown in the tables below:
Fair Value Measurements
December 31, 2012
Level 1
Level 2
Level 3
Netting
Adjustments
Total
(in millions)
Financial Assets
Commodity derivative instruments - short-term
Commodity derivative instruments - long-term
Total financial assets
Financial Liabilities
Commodity derivative instruments - short-term
Interest rate swaps - short-term
Commodity derivative instruments - long-term
Interest rate swaps - long-term
Total financial liabilities
$
$
$
$
— $
—
— $
189.7
4.2
193.9
— $
—
—
—
— $
1.0
2.6
0.1
3.6
7.3
$
$
$
$
— $
—
— $
— $
—
—
—
— $
(1.0) $
(0.1) $
(1.1) $
188.7
4.1
192.8
(1.0) $
— $
(0.1) $
— $
(1.1) $
—
2.6
—
3.6
6.2
90
Fair Value Measurements
December 31, 2011
Level 1
Level 2
Level 3
Netting
Adjustments
Total
(in millions)
Financial Assets
Commodity derivative instruments - short-term
Commodity derivative instruments - long-term
Total financial assets
Financial Liabilities
Commodity derivative instruments - short-term
Commodity derivative instruments - long-term
Total financial liabilities
$
$
$
$
— $
—
— $
— $
—
— $
284.1
123.5
407.6
11.7
—
11.7
$
$
$
$
— $
—
— $
— $
—
— $
(10.4) $
— $
(10.4) $
273.7
123.5
397.2
(10.4) $
— $
(10.4) $
1.3
—
1.3
Fair values related to the Company's crude oil costless collars were transferred from Level 3 to Level 2 in the second quarter of
2012, due to the enhancements to the Company's internal valuation process, including the use of observable inputs to assess the
fair value. There were no other significant transfers in or out of Levels 1, 2 or 3 for the periods presented herein.
The change in the fair value of Level 3 commodity derivative instruments assets and liabilities for the years ended
December 31, 2012 and 2011, are shown below:
Balance at January 1,
Realized gains and losses
Unrealized gains and losses
Settlements
Transfers out of Level 3
Balance at December 31,
Change in Level 3 Fair
Value Measurements
2012
2011
(in millions)
— $
0.6
3.8
(0.6)
(3.8)
— $
36.3
25.3
(36.3)
(25.3)
—
—
$
$
The following table discloses the fair value and related carrying amount of certain financial instruments not disclosed in other
notes to the consolidated financial statements in this Annual Report on Form 10-K:
Financial liabilities
Checks outstanding in excess of cash balances
Long-term debt
Carrying
Amount
Level 1
Fair Value
Carrying
Amount
Level 1
Fair Value
December 31, 2012
December 31, 2011
(in millions)
$
$
39.7
3,206.9
$
$
39.7
3,420.7
$
$
29.4
1,679.4
$
$
29.4
1,754.9
The carrying amount of checks outstanding in excess of cash balances approximates fair value. The fair value of fixed-rate
long-term debt is based on the trading levels and dollar prices for the Company's debt at the end of the quarter. The carrying
amount of variable-rate long-term debt approximates fair value because the floating interest rate paid on such debt was set for
periods of one month.
The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and
based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs
are used in the calculation of asset retirement obligations include plugging costs and reserve lives. A reconciliation of the
Company's asset retirement obligations is presented in Note 4 – Asset Retirement Obligations.
91
Nonrecurring Fair Value Measurements
The provisions of the fair value measurement standard are also applied to the Company's nonrecurring, non-financial
measurements. The Company utilizes fair value on a non-recurring basis to review its proved oil and gas properties and
goodwill for potential impairment when events and circumstances indicate a possible decline in the recoverability of the
carrying value of such property. During the years ended December 31, 2012 and 2011, the Company recorded impairments on
certain oil and gas properties resulting in a write down of the associated carrying value to fair value. The fair value of the
property was measured utilizing the income approach and utilizing inputs which are primarily based upon internally developed
cash flow models. Given the unobservable nature of the inputs, proved oil and gas property impairments are considered Level 3
within the fair value hierarchy. During the years ended December 31, 2012 and 2011, the Company recorded $107.6 million
and $195.5 million, respectively, of impairments related to some of its proved properties. The proved properties were written
down to their estimated fair values of $71.9 million and $157.2 million at the time of the impairments during 2012 and 2011,
respectively.
Acquisitions of proved and unproved properties are also measured at fair value on a nonrecurring basis. The Company utilized a
discounted cash flow model to estimates the fair value of acquired property as of the acquisition date which utilized the following
inputs to estimate future net cash flows: estimated quantities of crude oil, natural gas and NGL reserves; estimates of future
commodity prices; and estimated production rates, future operating and development costs which were based on the Company's
historic experience with similar properties. Due to the unobservable characteristics of the inputs, the fair value of the properties
are considered Level 3 within the fair value hierarchy. Refer to Note 2 - Acquisition, for additional information on the fair value
of acquired properties.
92
Note 6 – Derivative Contracts
QEP has established policies and procedures for managing commodity price volatility through the use of derivative
instruments. In the normal course of business, QEP uses commodity derivative instruments to reduce the impact of downward
movements in commodity prices on cash flow, returns on capital, and other financial results. However, these instruments
typically limit gains from favorable price movements. The volume of production subject to commodity derivative instruments
and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market
conditions. QEP may enter into commodity derivative contracts for up to 100% of forecasted production from proved reserves.
In addition, QEP may enter into commodity derivative contracts on a portion of its extracted NGL volumes in its midstream
business and a portion of its natural gas sales and purchases for marketing transactions. QEP does not enter into commodity
derivative instruments for speculative purposes.
QEP uses commodity derivative instruments known as fixed-price swaps and costless collars to realize a known price or range
of prices for a specific volume of production delivered into a regional sales point. Costless collars are combinations of put and
call options that have a floor price and a ceiling price and payments are made or received only if the settlement price is outside
the range between the floor and ceiling prices. QEP's commodity derivative instruments do not require the physical delivery of
natural gas, crude oil, or NGL between the parties at settlement. Swap and costless collar transactions are settled in cash with
one party paying the other for the net difference in prices, multiplied by the contract volume, for the settlement period. Natural
gas price derivative instruments are typically structured as fixed-price swaps at regional price indices. Oil price derivative
instruments are typically structured as NYMEX fixed-price swaps based at Cushing, Oklahoma. NGL price derivative
instruments are typically structured as Mont Belvieu, Texas fixed-price swaps.
QEP enters into commodity derivative transactions that do not have commodity margin requirements or collateral provisions
that would require payments prior to the scheduled settlement dates. Commodity derivative contract counterparties are
normally financial institutions and energy trading firms with investment-grade credit ratings. QEP routinely monitors and
manages its exposure to counterparty risk by requiring specific minimum credit standards for all counterparties and avoids
concentration of credit exposure by transacting with multiple counterparties.
Effective January 1, 2012, QEP elected to de-designate all of its natural gas, crude oil and NGL derivative contracts that were
previously designated as cash flow hedges and discontinue hedge accounting prospectively. As a result of discontinuing hedge
accounting, the mark-to-market values at December 31, 2011, were fixed in AOCI as of the de-designation date and are being
reclassified into the Consolidated Statement of Operations as the transactions settle and affect earnings. At December 31, 2012,
AOCI consisted of $123.5 million ($77.6 million after tax) of unrealized gains. During 2012, $171.1 million unrealized gains,
after tax, were reclassified from AOCI into the Consolidated Statement of Operations in "Realized and unrealized gains on
derivative contracts" as the transactions settled. QEP expects to reclassify into earnings from AOCI the remaining fixed value
related to de-designated natural gas, oil and NGL hedges during 2013. Currently, QEP recognizes all gains and losses from
changes in the fair value of natural gas, oil and NGL derivative contracts immediately in earnings rather than deferring any
such amounts in AOCI. All commodity derivative instruments are recorded on the Consolidated Balance Sheets as either assets
or liabilities measured at their fair values. All realized and unrealized gains and losses from derivative instruments incurred
after January 1, 2012, are presented in the Consolidated Statement of Operations in "Realized and unrealized gains on
derivative contracts" below operating income.
QEP also uses interest rate swaps to mitigate a portion of its exposure to interest rate volatility risk. During the second quarter
of 2012, QEP entered into variable-to-fixed interest rate swap agreements having a combined notional principal amount of
$300.0 million to minimize the interest rate volatility risk associated with its $300.0 million term loan. QEP locked in a fixed
interest rate in exchange for a variable interest rate indexed to the one-month LIBOR rate. The interest rate swaps are valued at
mark-to-market, settle monthly and will mature in March of 2017.
93
QEP Energy Derivative Contracts
The following table sets forth QEP Energy's quantities and average prices for its commodity derivative contracts as of
December 31, 2012:
Year
Type of Contract
Index
Natural gas sales
2013
2013
2014
Oil sales
2013
2014
Swap
Swap
Swap
Swap
Swap
NYMEX
IFNPCR
NYMEX
NYMEX WTI
NYMEX WTI
Swaps
Average price per
unit
Total
Volumes
(in millions)
(MMBtu)
$
$
$
$
51.1
65.7
18.3
(Bbls)
5.1
1.8
3.79
5.66
4.21
98.48
92.72
QEP Marketing Derivative Contracts
QEP Marketing enters into commodity derivative transactions to lock in a margin on natural gas volumes placed into storage
and for marketing transactions in which QEP Marketing is required to sell gas volumes at a fixed price. The following table sets
forth QEP Marketing's volumes and swap prices for its commodity derivative contracts as of December 31, 2012:
Year
Type of Contract
Index
Natural gas sales
2013
Natural gas purchases
2013
2014
Swap
Swap
Swap
IFNPCR
IFNPCR
IFNPCR
Total
Volumes
(in millions)
(MMBtu)
4.0
(MMBtu)
0.2
0.1
Average
Swap price
per MMBtu
$
$
$
3.78
2.88
3.02
QEP Resources Derivative Contracts
In the second quarter of 2012, QEP Resources entered into interest rate swap agreements to effectively lock in a fixed interest
rate on debt outstanding under its Term Loan. The following table sets forth QEP Resources' notional amounts and interest rates
for its interest rate swaps outstanding as of December 31, 2012:
Notional amount
(in millions)
$300.0
Type of Contract
Maturity
Fixed Rate
Paid
Variable Rate
Received
Swap
March 2017
1.07%
One month LIBOR
94
QEP Derivative Financial Statement Presentation
The following table presents the balance sheet location of QEP's outstanding derivative contracts on a gross contract basis as
opposed to the net contract basis presentation in the Consolidated Balance Sheets and the related fair values at the balance sheet
dates:
Gross asset derivative
instruments fair value
Gross liability derivative
instruments fair value
December 31,
Balance Sheet line item
2012
2011
2012
2011
(in millions)
(in millions)
Current:
Commodity
Interest rate swaps
Long-term:
Commodity
Interest rate swaps
Fair value of derivative
contracts
Fair value of derivative
contracts
Fair value of derivative
contracts
Fair value of derivative
contracts
$
189.7
$
284.1
$
1.0
$
11.7
—
4.2
—
—
123.5
—
2.6
0.1
3.6
7.3
—
—
—
$
11.7
Total derivative instruments
$
193.9
$
407.6
$
95
The effects and location of the change in fair value and settlement of QEP's derivative contracts on the Consolidated Statements
of Operations are summarized in the following tables:
Derivative instruments not designated as cash flow hedges (1)
Realized gain (loss) on commodity derivative contracts
QEP Energy
Natural gas derivative contracts
Oil derivative contracts
NGL derivative contracts
QEP Field Services
NGL derivative contracts
QEP Marketing
Natural gas derivative contracts
Total realized gain (loss) on commodity derivative contracts
Unrealized gain (loss) on commodity derivative contracts
QEP Energy
Natural gas derivative contracts
Oil derivative contracts
NGL derivative contracts
QEP Field Services
NGL derivative contracts
QEP Marketing
Natural gas derivative contracts
Total unrealized gain on commodity derivative contracts
Total realized and unrealized gain on commodity derivative contracts
Realized gain (loss) on interest rate swaps
Realized loss on interest rate swaps
Unrealized gain (loss) on interest rate swaps
Unrealized loss on interest rate swaps
Total realized and unrealized loss on interest rate swaps
Total net realized gain on derivative contracts
Total net unrealized gain on derivative contracts
Grand Total
Year Ended December 31,
2012
2011
2010
$
341.9
14.4
10.2
8.4
$ (117.7) $ (121.7)
—
—
—
—
—
—
5.1
380.0
—
(117.7)
—
(121.7)
37.8
29.0
1.6
—
0.9
69.3
117.7
121.7
—
—
—
—
—
—
—
—
117.7
121.7
449.3
$
— $
(1.3) $
— $
—
—
—
—
(6.1)
(7.4) $
378.7
63.2
— $
—
$ (117.7) $ (121.7)
121.7
$
117.7
$
441.9
$
— $
—
$
$
$
$
$
$
____________________________
(1) Gains and losses on derivatives not designated as cash flow hedges, are included in earnings in "Realized and unrealized
gains on derivative contracts" on the Consolidated Statement of Operations.
96
The following table presents the change in the fair value and settlement of QEP's derivative contracts that were designated as
cash flow hedges in 2011 and 2010:
Derivative instruments classified as cash flow hedges
Commodity derivatives
Location of gain (loss)
recognized in earnings
December 31,
2012
2011
2010
Gain on derivative instruments for the effective portion of
hedge recognized in AOCI
Accumulated other
comprehensive income
$
— $
350.8
$
565.8
Gain reclassified from AOCI into income for effective
portion of hedge
Gain reclassified from AOCI into income for effective
portion of hedge
Gain reclassified from AOCI into income for effective
portion of hedge
Gain reclassified from AOCI into income for effective
portion of hedge
Natural gas sales
Oil sales
NGL sales
Marketing purchases
Gain recognized in income for the ineffective portion of
hedges
Interest and other income
—
—
—
—
—
305.5
353.8
1.6
(8.7)
(0.2)
4.3
0.1
—
3.1
0.2
The Company estimates that the remaining derivative contracts that were outstanding in AOCI at December 31, 2012, with a fixed
fair value of $77.6 million after tax, will be settled and reclassified from AOCI to the Consolidated Statements of Operations
during the next twelve months.
Note 7 – Restructuring Costs
During the first quarter 2012, QEP began incurring costs related to the closure of its Oklahoma City office and the subsequent
consolidation of its Southern Region operations into a single regional office located in Tulsa. During the second half of 2012,
QEP incurred additional restructuring and reorganization costs related to consolidating various corporate and accounting
functions to the Denver corporate headquarters. The creation of one office for QEP's Southern Region as well as consolidation
of corporate and accounting functions is intended to increase efficiency, team-based collaboration and organizational
productivity over the long term. As part of the reorganization, QEP incurred and will continue to incur costs associated with the
severance, retention and relocation of employees, additional pension expenses, exit costs associated with the termination of
operating leases arising from office space that will no longer be utilized by the Company and other expenses. The Company
currently estimates that the remaining restructuring costs will be incurred during 2013.
The following table summarizes, by line of business, each major type of costs expected to be incurred and the total amounts
recorded in "General and administrative" expense on the Consolidated Statement of Operations the respective periods
indicated:
QEP
Energy
QEP
Field
Services
QEP
Marketing
Total
Restructuring costs expected to be incurred
One-time termination benefits
Retention and relocation expense
Lease termination costs and other expenses
Total restructuring costs expected to be incurred
$
$
3.3
5.4
0.6
9.3
$
$
(in millions)
— $
0.2
—
0.2
$
0.2
0.2
—
0.4
$
$
Total restructuring costs recognized in income for the year ended December 31, 2012
One-time termination benefits
Retention and relocation expense
Lease termination costs and other expenses
Total restructuring costs incurred during the year
ended December 31, 2012
2.9
3.4
0.6
$
— $
0.1
$
—
—
—
—
6.9
$
— $
0.1
$
$
$
97
3.5
5.8
0.6
9.9
3.0
3.4
0.6
7.0
In addition to the costs incurred above, during the year ended December 31, 2012, the Company recognized a curtailment loss of
$2.2 million as part of its pension plan's net periodic benefit cost. The curtailment loss was a result of the Company's restructuring
efforts and termination benefits and is included on the Consolidated Balance Sheet as part of the Company's pension liability. For
additional information related to the Company's pension plans, see Note 11 - Employee Benefits. The following is a reconciliation
of the restructuring liability, by line of business, which is included within "Accounts payable and accrued expenses" on the
Consolidated Balance Sheets:
Balance at December 31, 2011
Costs incurred and charged to expense
Costs paid or otherwise settled
Balance at December 31, 2012
Note 8 – Debt
QEP
Energy
QEP Field
Services
QEP
Marketing
Total
$
$
— $
6.9
(5.9)
1.0
(in millions)
— $
—
—
—
— $
0.1
(0.1)
— $
—
7.0
(6.0)
1.0
As of the indicated dates, the principal amount of QEP's debt, including amounts outstanding under its revolving credit facility
and term loan agreement, consisted of the following:
December 31,
2012
2011
Revolving credit facility due 2016
Term loan due 2017
6.05% Senior Notes due 2016
6.80% Senior Notes due 2018
6.80% Senior Notes due 2020
6.875% Senior Notes due 2021
5.375% Senior Notes due 2022
5.25% Senior Notes due 2023
Total principal amount of debt
Less unamortized discount
Total long-term debt outstanding
$
$
$
(in millions)
690.0
300.0
176.8
134.0
136.0
625.0
500.0
650.0
3,211.8
(4.9)
3,206.9
$
606.5
—
176.8
138.6
138.0
625.0
—
—
1,684.9
(5.5)
1,679.4
Of the total debt outstanding on December 31, 2012, the revolving credit facility due August 25, 2016, the term loan due April
18, 2017, and the 6.05% Senior Notes due September 1, 2016, will mature within the next five years.
Credit Facility
QEP's revolving credit facility agreement, which matures in August 2016, provides for loan commitments of $1.5 billion from a
group of financial institutions. The credit facility provides for borrowings at short-term interest rates and contains customary
covenants and restrictions. The credit facility agreement also contains an accordion provision that would allow for the amount
of the facility to be increased to $2.0 billion and for the maturity to be extended for two additional one-year periods, with the
agreement of the lenders.
During the year ended December 31, 2012, QEP's weighted-average interest rate on borrowings from its credit facility was
2.08%. At December 31, 2012 and 2011, QEP was in compliance with the covenants under the credit agreement. At
December 31, 2012, there was $690.0 million outstanding and QEP had $4.1 million in letters of credit outstanding under the
credit facility.
98
Term Loan
During the second quarter of 2012, QEP entered into a $300.0 million senior, unsecured term loan agreement with a group of
financial institutions. The term loan provides for borrowings at short-term interest rates and contains covenants, restrictions and
interest rates that are substantially the same as the Company's credit facility. The term loan matures in April 2017, and the
maturity date may be extended one year with the agreement of the lenders. The proceeds from the term loan were used to pay
down the credit facility and for general corporate purposes. During the year ended December 31, 2012, QEP's weighted-
average interest rate on borrowings from the term loan was 2.05%. At December 31, 2012, QEP was in compliance with the
covenants under the term loan credit agreement.
Senior Notes
During the first quarter of 2012, QEP completed a public offering of $500.0 million in aggregate principal amount of 5.375%
senior notes due in October 2022. The 2022 senior notes were issued at par. Interest on the notes will be paid semi-annually, in
April and October of each year. The net proceeds of $493.1 million were used to repay indebtedness under QEP's credit facility.
The finance costs associated with the offering were $6.9 million and were deferred and are being amortized over the life of the
notes.
During the second quarter of 2012, QEP repurchased $6.7 million of its senior notes outstanding. QEP recognized a loss on
extinguishment of debt from those repurchases and associated write-offs of debt issuance costs, discounts and premiums paid of
$0.6 million.
During the third quarter of 2012, QEP completed a public offering of $650.0 million in aggregate principal amount of 5.25%
senior notes due in May 2023. The notes were issued at par. Interest on the notes will be paid semi-annually, in May and
November of each year. The net proceeds of $641.0 million were used to fund a portion of the 2012 Acquisition, as described in
Note 2 - Acquisition. The costs associated with the offering were $9.0 million and were deferred and are being amortized over
the life of the notes. The amortization expense related to all of the Company's deferred finance costs is included in "Interest
expense" on the Consolidated Statement of Operations.
At December 31, 2012, the Company had $2,221.8 million principal amount of senior notes outstanding with maturities
ranging from September 2016 to May 2023 and coupons ranging from 5.25% to 6.875%. The senior notes pay interest semi-
annually, are unsecured senior obligations and rank equally with all of our other existing and future unsecured and senior
obligations. QEP may redeem some or all of its senior notes at any time before their maturity at a redemption price based on a
make-whole amount plus accrued and unpaid interest to the date of redemption. The indenture governing QEP's senior notes
contains customary events of default and covenants that may limit QEP's ability to, among other things, place liens on its
property or assets.
Note 9 – Commitments and Contingencies
QEP is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary
course of its business. QEP assesses these claims in an effort to determine the degree of probability and range of possible loss
for potential accrual in its consolidated financial statements. In accordance with ASC 450, Contingencies, an accrual is
recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the
anticipated most likely outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are
inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires
judgments about uncertain future events. When evaluating contingencies, QEP may be unable to provide a meaningful estimate
due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal
theories, and/or the ongoing discovery and development of information important to the matters. QEP regularly reviews
contingencies to determine the adequacy of its accruals and related disclosures. The following discussion describes the nature
of QEP's material loss contingencies.
99
Environmental Claims
United States of America v. QEP Field Services, Civil No. 208CV167, U.S. District Court for Utah filed on February 28, 2008.
The U.S. Environmental Protection Agency (EPA) alleged that QEP Field Services (f/k/a Questar Gas Management) violated
the Clean Air Act (CAA) and sought substantial penalties and a permanent injunction involving the manner of operation of five
compressor stations located in the Uinta Basin of eastern Utah. On May 16, 2012, QEP Field Services settled this matter and
the parties executed a consent decree which was subsequently approved by court order. The civil penalty paid to the
government during the third quarter of 2012 was $3.7 million. A contribution of $0.4 million was paid to a trust created by the
Ute Indian Tribe of the Uintah and Ouray Reservation for the implementation of environmental programs for the benefit of
Tribal members. The settlement also requires the Company to reduce its emissions by removing certain equipment, installing
additional pollution controls and replacing the natural gas powered instrument control systems with compressed air control
systems, all of which will require capital expenditures of approximately $2.4 million, of which $1.2 million had been spent as
of December 31, 2012. QEP Field Services will have continuing operational compliance obligations under the consent decree at
the affected facilities.
In October 2009, the Company received a cease and desist order from the U.S. Army Corps of Engineers (COE) to refrain from
unpermitted work resulting in the discharge of dredged and/or fill material into waters of the United States at three sites located
in Caddo and Red River Parishes, Louisiana. EPA Region 6 has assumed lead responsibility for enforcement of the cease and
desist order and any possible future orders for the removal of unauthorized fills and/or civil penalties under the Clean Water
Act. In 2012, the Company completed a field audit, which identified 112 additional instances affecting approximately 90 acres
where work may have been conducted in violation of the Clean Water Act. The Company has disclosed each of these instances
to the EPA under the EPA's Audit Policy (to reduce penalties) and to the COE. The Company is working with the EPA and the
COE to resolve these matters, which will require the Company to undertake certain mitigation and permitting activities, and
may require the Company to pay a monetary penalty. At this time, QEP is unable to estimate the potential loss related to this
matter, but believes it exceeds the $100,000 threshold for disclosure of environmental matters.
Litigation
Chieftain Royalty Company v. QEP Energy Company, Case No CJ2011-1, U. S. District Court for the Western District of
Oklahoma. This statewide class action was filed on January 20, 2011, on behalf of QEP's Oklahoma royalty owners asserting
various claims for damages related to royalty valuation on all of QEP's Oklahoma wells operated by QEP or from which QEP
marketed gas. These claims include breach of contract, breach of fiduciary duty, fraud, unjust enrichment, tortious breach of
contract, conspiracy, and conversion, based generally on asserted improper deduction of post-production costs. The Court
certified the class as to the breach of contract, breach of fiduciary duty and unjust enrichment claims. The parties successfully
mediated the case in January 2013. On February 13, 2013, the parties executed a Stipulation and Agreement of Settlement (the
Chieftain Settlement Agreement) providing for a cash payment from QEP to the class in the amount of $115.0 million. In
consideration for the settlement payment, QEP will receive a full release of all claims regarding the calculation, reporting and
payment of royalties from the sale of natural gas and its constituents for all periods prior to February 28, 2013, and all class
members are enjoined from asserting claims related to such royalties. As part of the Chieftain Settlement Agreement, the parties
also agreed on the methodology for the calculation and payment of future royalties payable by QEP, or its successors and
assigns, under all class leases for the life of such leases. The Court has entered a Preliminary Order Approving Class Action
Settlement. During the year ended December 31, 2012, QEP recorded a loss contingency accrual of $115.0 million, which is
included in "General and administrative" expense on the Consolidated Statement of Operations. The accrual is included in
"Accounts payable and accrued expenses" on the Consolidated Balance Sheet.
Questar Gas Company v. QEP Field Services Company, Civil No. 120902969, Third Judicial District Court, State of Utah. QEP
Field Services' former affiliate Questar Gas Company (QGC) filed this complaint in state court in Utah on May 1, 2012,
asserting claims for breach of contract, breach of implied covenant of good faith and fair dealing, for an accounting and
declaratory judgment related to a 1993 gathering agreement (1993 Agreement) entered when the parties were affiliates. Under
the 1993 Agreement, QEP Field Services provides gathering services for producing properties developed by former affiliate
Wexpro Company on behalf of QGC's utility ratepayers. The core dispute pertains to the annual calculation of the gathering
rate, which is based on a cost of service concept expressed in the 1993 Agreement and in a 1998 amendment. The annual
gathering rate has been calculated in the same manner under the contract since it was amended in 1998, without any prior
objection or challenge by QGC. Specific monetary damages are not asserted. Also, on May 1, 2012, QEP Field Services
Company filed a legal action against Questar Gas entitled QEP Field Services Company v. Questar Gas Company, in the
Second District Court in Denver County, Colorado, seeking declaratory judgment relating to its gathering service and charges
under the same agreement.
100
Commitments
Subsidiaries of QEP have contracted for firm-transportation services with various third-party pipelines. Market conditions,
drilling activity and competition may prevent full utilization of the contractual capacity. In addition, QEP has contracts with
third parties who provide drilling services and fractionation contracts. Annual payments and the corresponding years for
transportation contracts, drilling contracts and fractionation contracts are as follows (in millions):
Year
2013
2014
2015
2016
2017
After 2017
Amount
161.3
146.2
112.0
107.7
107.0
385.7
$
$
$
$
$
$
QEP rents office space throughout its scope of operations from third-party lessors. Rental expense from operating leases
amounted to $7.3 million, $5.0 million and $4.5 million during the years ended December 31, 2012, 2011 and 2010,
respectively. Minimum future payments under the terms of long-term operating leases for the Company's primary office
locations are as follows (in millions):
Year
2013
2014
2015
2016
2017
After 2017
Amount
6.7
6.5
6.6
6.5
6.7
29.1
$
$
$
$
$
$
Note 10 – Share-Based Compensation
QEP issues stock options and restricted shares under its Long-Term Stock Incentive Plan (LTSIP) and awards performance-
based share units under its Cash Incentive Plan (CIP) to certain officers, employees, and non-employee directors. QEP
recognizes expense over time as the stock options, restricted shares, and performance-based share units vest. Deferred share-
based compensation is included in additional paid-in capital in the Consolidated Balance Sheets. There were 13.1 million
shares available for future grants under the LTSIP at December 31, 2012. Share-based compensation expense is recognized in
"General and administrative" on the Consolidated Statements of Operations. During the year ended December 31, 2012, QEP
recognized $25.6 million in total compensation expense related to share-based compensation compared to $22.0 million and
$16.1 million during the years ended December 31, 2011 and 2010, respectively.
Stock Options
QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock options awards at the date of the
grant. Fair-value calculations rely upon subjective assumptions used in the mathematical model and may not be representative
of future results. The Black-Scholes-Merton model is intended for measuring the value of options traded on an exchange. The
Company utilizes the "simplified" method to estimate the expected term of the stock options granted as there is limited
historical exercise data available in estimating the expected term of the stock options. QEP uses a historical volatility method to
estimate the fair value of stock options awards and the risk-free interest rate is based on the yield on U.S. Treasury strips with
maturities similar to those of the expected term of the stock options. The stock options typically vest in equal installments over
a three-year period from the grant date and are exercisable immediately upon vesting through the seventh anniversary of the
grant date.
The calculated fair value of options granted and major assumptions used in the model at the date of grant are listed below:
101
Stock Option Variables
Year Ended December 31,
2011
2012
2010
Weighted-average grant-date fair value of awards granted during
the period
Risk-free interest rate range
Weighted-average risk-free interest rate
Expected price volatility range
Weighted-average expected price volatility
Expected dividend yield
Expected term in years at the date of grant
$
14.29
$
18.80
$
27.55
0.63% - 1.04%
0.8%
55.9% - 56.5%
55.9%
0.26%
5.0
n/a
2.1%
n/a
54.7%
0.21%
5.0
n/a
2.3%
n/a
30.3%
1.18%
5.2
Stock option transactions under the terms of the LTSIP are summarized below:
Outstanding at December 31, 2011
Granted
Exercised
Forfeited
Outstanding at December 31, 2012
Options Exercisable at December 31, 2012
Unvested Options at December 31, 2012
Options
Outstanding
Weighted-
Average
Exercise Price
(per share)
2,003,694
304,660
(610,883)
—
1,697,471
1,230,843
466,628
$
$
$
$
21.23
30.75
14.87
—
25.23
22.50
32.40
Weighted-
Average
Remaining
Contractual
Term
(in years)
Aggregate
Intrinsic Value
(in millions)
—
$
$
$
3.64
2.88
5.65
10.5
10.3
0.2
The total intrinsic value (the difference between the market price at the exercise date and the exercise price) of options
exercised was $9.6 million, $2.7 million and $0.3 million during the years ended December 31, 2012, 2011 and 2010,
respectively. The Company realized $4.6 million and $0.4 million of income tax benefits for the years ended December 31,
2012 and 2011 (no income tax benefit realized in 2010), which increased its Additional Paid-in-Capital (APIC) pool by $5.1
million as of December 31, 2012. As of December 31, 2012, $2.7 million of unrecognized compensation cost related to stock
options granted under the LTSIP is expected to be recognized over a weighted-average period of 1.99 years. During the year
ended December 31, 2012, QEP issued shares for stock option exercises from its treasury stock. During the year end
December 31, 2012, QEP received $2.6 million in cash in relation to the exercise of stock options.
Restricted Shares
Restricted share grants typically vest in equal installments over a three-year period from the grant date. The grant date fair
value is determined based on the closing bid price of the Company's common stock on the grant date. The total fair value of
restricted stock that vested during the years ended December 31, 2012 and 2011, was $16.7 million and $11.7 million,
respectively, with minimal vestings in 2010. The Company realized $0.3 million income tax expense and $1.0 million income
tax benefit for the years ended December 31, 2012 and 2011, respectively, and increased the Company's APIC pool by $0.9
million as of December 31, 2012. The weighted average grant-date fair value of restricted stock granted during the years was
$30.54 per share, $38.50 per share and $28.70 per share for the years ended December 31, 2012, 2011 and 2010, respectively.
As of December 31, 2012, $16.5 million of unrecognized compensation cost related to restricted shares granted under the
LTSIP is expected to be recognized over a weighted-average vesting period of 2.09 years.
102
Transactions involving restricted shares under the terms of the LTSIP are summarized below:
Restricted
Shares
Outstanding
$
Weighted-
Average Grant-
Date Fair Value
(per share)
32.80
30.54
31.90
32.30
31.78
1,099,752
827,986
(541,230 )
(85,920 )
Unvested balance at December 31, 2011
Granted
Vested
Forfeited
Unvested balance at December 31, 2012
1,300,588
$
Performance Share Units
The performance share units' cash payouts are dependent upon the Company's total shareholder return compared to a group of
its peers over a three-year period. The awards are denominated in share units but delivered in cash at the end of the
performance period. The weighted average grant-date fair value of the performance share units granted during the period was
$30.90 per unit and $39.07 per unit for the years ended December 31, 2012 and 2011, respectively. As of December 31, 2012,
$3.2 million of unrecognized compensation cost classified as a liability, or the fair market value, related to performance shares
granted under the CIP is expected to be recognized over a weighted-average vesting period of 1.90 years.
Transactions involving performance share units under the terms of the CIP are summarized below:
Unvested balance at December 31, 2011
Granted
Vested
Forfeited
Unvested balance at December 31, 2012
Note 11 – Employee Benefits
Performance
Share
Units
Outstanding
115,274
180,923
—
(12,713 )
283,484
$
Weighted-
Average Grant-
Date Fair Value
$
39.07
30.90
—
35.69
34.01
Defined Benefit Pension Plans and Other Postretirement Benefits
The Company maintains closed, defined-benefit pension and postretirement medical plans providing coverage to 145, or 16%,
of QEP's active employees and to 70 participants that are retired, terminated and vested, or suspended. Pension-plan benefits
are based on the employee's age at retirement, years of service and highest earnings in a consecutive 72 semi-monthly pay
period during the 10 years preceding retirement. QEP pension plans include a qualified and a nonqualified retirement plan.
Postretirement health care benefits and life insurance are provided only to employees hired before January 1, 1997. The
Company pays a portion of the costs of health-care benefits determined by an employee's years of service. The Company has
capped its exposure to increasing medical care and life insurance costs by paying a fixed dollar monthly contribution toward
these retiree benefits. The Company contribution is prorated based on an employee's years of service at retirement; only those
employees with 25 or more years of service receive the maximum Company contribution. At December 31, 2012 and 2011,
QEP's accumulated benefit obligation exceeded the fair value of plan assets as the plan is unfunded.
During the year ended December 31, 2012, the Company recognized a $2.2 million loss on curtailment as part of its
restructuring efforts and related termination benefits. A curtailment is recognized immediately when there is a significant
reduction in, or an elimination of, defined benefit accruals for present employees' future services. For additional information
regarding the Company's restructuring efforts see Note 7 - Restructuring Costs. During the year ended December 31, 2012, the
Company made contributions of $5.6 million to its funded pension plan, and $1.3 million to its unfunded pension plan.
Contributions to funded plans increase plan assets while contributions to unfunded plans are used to fund current benefit
payments. During 2013, the Company expects to contribute approximately $8.1 million to its funded pension plan,
approximately $3.2 million to its unfunded pension plan and approximately $0.2 million for retiree health care and life
insurance benefits. The accumulated postretirement benefit obligation for all defined-benefit pension plans was $106.9 million
and $78.3 million at December 31, 2012 and 2011, respectively.
103
The following table sets forth changes in the benefit obligations and fair value of plan assets for the Company's pension and
other postretirement benefit plans for the years ended December 31, 2012 and 2011, as well as the funded status of the plans
and amounts recognized in the financial statements at December 31, 2012 and 2011:
Pension benefits
Other postretirement benefits
2012
2011
2012
2011
(in millions)
Change in benefit obligation
Benefit obligation at January 1,
Service cost
Interest cost
Change in plan assumptions
Benefit payments
Actuarial loss (gain)
Benefit obligation at December 31,
Change in plan assets
Fair value of plan assets at January 1,
Actual gain (loss) on plan assets
Company contributions to the plan
Benefit payments
Fair value of plan assets at December 31,
Underfunded status (current and long-term)
Amounts recognized in balance sheets
Accounts payable and accrued expenses
Other long-term liabilities
Total amount recognized in balance sheet
Amounts recognized in AOCI
Net actuarial loss (gain)
Prior service cost
Total amount recognized in AOCI
5.9
0.1
0.3
—
—
0.4
6.7
$
$
— $
—
—
—
—
(6.7) $
(0.2) $
(6.5)
(6.7) $
1.3
3.4
4.7
$
$
4.5
0.1
0.3
—
—
1.0
5.9
—
—
—
—
—
(5.9)
—
(5.9)
(5.9)
1.0
3.8
4.8
$
104.1
$
78.0
$
4.0
5.1
8.4
(2.7)
10.8
129.7
44.2
6.9
$
$
6.9
(2.7)
55.3
(74.4) $
(3.2) $
(71.2)
(74.4) $
32.6
35.1
67.7
$
$
2.9
4.5
19.6
(0.2)
(0.7)
104.1
$
$
30.9
(1.3)
14.8
(0.2)
44.2
(59.9) $
(1.3) $
(58.6)
(59.9) $
18.6
42.6
61.2
$
$
$
$
$
$
$
$
$
104
The following table sets forth the Company's pension and other postretirement benefit cost and amounts recognized in other
comprehensive income (before tax) for the respective years ended December 31:
Pension benefits
2012
2011
2010
Other postretirement benefits
2012
2011
2010
Components of net periodic benefit cost
Service cost
Interest cost
Expected return on plan assets
Curtailment loss
Amortization of prior service costs
Amortization of actuarial loss
Periodic expense
Components recognized in accumulated other
comprehensive income
Current period actuarial loss (gain)
Amortization of actuarial loss
Current period prior service cost
Amortization of prior service cost
Loss on curtailment in current period
Total amount recognized in accumulated other
comprehensive income
$
$
$
$
$
$
4.0
5.1
(3.6)
2.2
5.3
1.9
14.9
15.9
(1.9)
—
(5.3)
(2.2)
$
$
$
2.9
4.5
(2.6)
—
5.3
—
10.1
22.9
—
—
(5.3)
—
1.3
2.1
(1.1)
—
2.6
—
4.9
$
$
(4.2) $
—
50.4
(2.6)
—
$
$
$
0.1
0.3
—
—
0.3
0.1
0.8
0.4
(0.1)
—
(0.4)
—
$
$
$
0.1
0.3
—
—
0.3
—
0.7
1.0
—
—
(0.3)
—
0.1
0.1
—
—
0.2
—
0.4
—
—
4.3
(0.1)
—
$
6.5
$
17.6
$
43.6
$
(0.1) $
0.7
$
4.2
The estimated portion of net actuarial loss and net prior service cost for the pension plans that will be amortized from AOCI
into net periodic benefit cost in 2013 is $7.3 million, of which $5.0 million represents amortization of prior service cost
recognition and the remaining $2.3 million represents amortization of net actuarial losses. The estimated portion to be
recognized in net periodic cost for other postretirement benefits from AOCI in 2013 is $0.5 million, of which $0.4 million
represents amortization of prior service cost recognition and the remaining $0.1 million represents amortization of net actuarial
losses.
Following are the weighted-average assumptions (weighted by the plan level benefit obligation for pension benefits) used by
the Company to calculate pension and other postretirement benefit obligations at December 31, 2012 and 2011:
Discount rate
Rate of increase in compensation
Pension benefits
Other postretirement benefits
2012
2011
2012
2011
3.88%
3.60%
4.54%
3.60%
4.10%
3.60%
4.70%
4.00%
The discount rate assumptions used by the Company represents an estimate of the interest rate at which the pension and other
postretirement obligations could effectively be settled on the measurement date.
Following are the weighted-average assumptions (weighted by the net period benefit cost for pension benefits) used by the
Company in determining the net periodic pension and other postretirement benefit cost for the years ended December 31:
Discount rate
Expected long-term return on plan assets
Rate of increase in compensation
Pension benefits
2011
2012
2010
Other postretirement benefits
2012
2010
2011
4.38%
7.25%
3.60%
5.80%
7.50%
3.60%
5.70%
7.50%
3.60%
4.70%
n/a
4.00%
5.80%
n/a
n/a
5.70%
n/a
n/a
In selecting the assumption for expected long-term rate of return on assets, the Company considers the average rate of return
expected on the funds to be invested to provide benefits. This includes considering the plan's asset allocation, historical returns
on these types of assets, the current economic environment and the expected returns likely to be earned over the life of the plan.
No plan assets are expected to be returned to the Company in 2013. Historical heath care cost trend rates are not applicable to
105
the Company because the Company's medical costs are capped at a fixed amount. As the Company's medical costs are capped
at a fixed amount, the sensitivity to increase and decreases in the health-care inflation rate is not applicable.
Plan Assets
The Company's Employee Benefits Committee (EBC) oversees investment of pension plan assets. The EBC uses a third-party
asset manager to assist in setting targeted-policy ranges for the allocation of assets among various investment categories. The
EBC allocates pension-plan assets among broad asset categories and reviews the asset allocation at least annually. Asset-
allocation decisions consider risk and return, future-benefit requirements, participant growth and other expected cash flows.
These characteristics affect the level, risk and expected growth of postretirement-benefit assets. The EBC uses asset-mix
guidelines that include targets for each asset category, return objectives for each asset group and the desired level of
diversification and liquidity. These guidelines may change from time to time based on the committee's ongoing evaluation of
each plan's risk tolerance. The EBC estimates an expected overall long-term rate of return on assets by weighting expected
returns of each asset class by its targeted asset allocation percentage. Expected return estimates are developed from analysis of
past performance and forecasts of long-term return expectations by third-parties. Responsibility for individual security selection
rests with each investment manager, who is subject to guidelines specified by the EBC. The EBC sets performance objectives
for each investment manager that are expected to be met over a three-year period or a complete market cycle, whichever is
shorter. Performance and risk levels are regularly monitored to confirm policy compliance and that results are within
expectations. Performance for each investment is measured relative to the appropriate index benchmark for its category. QEP
securities may be considered for purchase at an investment manager's discretion, but within limitations prescribed by ERISA
and other laws. There was no direct investment in QEP shares for the periods disclosed. The majority of retirement-benefit
assets were invested as follows:
Equity securities: Domestic equity assets were mostly invested in a stock index fund, and a smaller portion was invested in an
actively managed product, with a diversification goal representative of the whole U.S. stock market. Foreign equity securities
consisted of developed and emerging market foreign equity assets that were invested in funds that hold diversified portfolio of
common stocks of corporations in developed and emerging foreign countries.
Debt securities: Investment grade intermediate-term debt assets are invested in funds holding a diversified portfolio of debt of
governments, corporations and mortgage borrowers with average maturities of 5 to 10 years and investment grade credit
ratings. Investment grade long-term debt assets are invested in a diversified portfolio of debt of corporate and non-corporate
issuers, with an average maturity of more than ten years and investment grade credit ratings.
Although the actual allocation to cash and short-term investments is minimal (less than 1%), larger cash allocations may be
held from time to time if deemed necessary for operational aspects of the retirement plan. Cash is invested in a high-quality,
short-term temporary investment fund that purchases investment-grade quality short-term debt issued by governments and
corporations.
Commingled funds: The EBC made the decision to invest all of the retirement plan assets in commingled funds as these funds
typically have lower expense ratios and are more tax efficient than mutual funds. While commingled funds are classified as
Level 3 assets because there are calculations involved in determining the net asset value of the funds, the underlying assets can
be traced back to observable asset values and these commingled funds are audited annually by an independent accounting firm.
The fair value measurement provision of ASC 820, Fair Value Measurements, defines fair value in applying generally accepted
accounting principles as well as establishes a framework for measuring fair value and for making disclosures about fair-value
measurements. Fair value measurement establishes a fair-value hierarchy. Level 1 inputs are unadjusted quoted prices in active
markets for identical assets or liabilities that are accessible at the measurement date. Level 2 inputs are inputs other than quoted
prices included within Level 1 that are observable for an asset, either directly or indirectly. Level 3 inputs are unobservable
inputs for an asset. The Company's Level 3 investments are public investment vehicles valued using the net asset value (NAV)
of the fund, but are considered Level 3 because they are commingled funds. The NAV is based on the value of the underlying
assets owned by the fund excluding transaction costs, and minus liabilities.
The following table sets forth by level, within the fair value hierarchy, the fair value of pension and postretirement benefit
assets.:
106
Level 1
As of December 31, 2012
Level 2
Level 3
(in millions except percentages)
Total
Percentage
of total
Cash and short-term investments
Equity securities:
Domestic
International
Fixed income
Total investments
Cash and short-term investments
Equity securities:
Domestic
International
Fixed income
Total investments
$
— $
— $
0.2
$
0.2
—%
—
—
—
—
—
—
—
— $
22.2
16.7
16.2
55.3
$
22.2
16.7
16.2
55.3
40%
30%
30%
100%
Level 1
As of December 31, 2011
Level 3
Level 2
(in millions except percentages)
Total
Percentage
of total
$
— $
— $
— $
— $
—
—
—
—
—
—
—
—
— $
17.6
13
13.6
44.2
$
17.6
13.0
13.6
44.2
40 %
29 %
31 %
100 %
The following table presents a summary of changes in the fair value of QEP's Level 3 investments:
Balance at January 1,
Employer contributions
Unrealized gains (losses)
Realized gains
Administrative fees
Benefits paid
Balance at December 31,
Year ended December 31,
2012
2011
(in millions)
44.2
5.6
6.3
0.7
(0.2)
(1.3)
55.3
$
30.9
14.8
(1.4)
0.3
(0.2)
(0.2)
44.2
$
$
Expected Benefit Payments
As of December 31, 2012, the following future benefit payments are expected to be paid:
2013
2014
2015
2016
2017
2018 through 2021
Pension
(in millions)
Postretirement
benefits
$
$
5.7
5.3
4.9
5.6
5.2
40.9
0.2
0.2
0.2
0.3
0.3
1.8
Employee Investment Plan
QEP employees may participate in the QEP Employee Investment Plan (EIP), a defined-contribution plan. The EIP allows
eligible employees to purchase shares of QEP common stock or other investments through payroll deduction at the current fair
market value on the transaction date. The Company currently contributes an overall match of 100% of employees' contribution
up to a maximum of 6% of their qualifying earnings. In addition, from time-to-time at the discretion of management, the
107
Company may contribute a discretionary portion beyond the company match to employees not in the Company's closed defined
benefit plan. The Company recognizes expense equal to its yearly contributions, which amounted to $6.4 million, $5.8 million
and $4.2 million during the years ended December 31, 2012, 2011 and 2010.
Note 12 - Income Taxes
Details of income tax expenses and deferred income taxes from continuing operations are provided in the following tables. The
components of income tax expenses were as follows:
2012
Year Ended December 31,
2011
(in millions)
2010
Federal income tax expense (benefit)
Current
Deferred
State income tax expense (benefit)
Current
Deferred
Total income tax expense
$
$
33.7 $
36.5
(5.3 ) $
153.0
0.7
(4.4 )
66.5 $
2.9
3.8
154.4 $
(16.6 )
172.9
(4.7 )
15.4
167.0
The difference between the statutory federal income tax rate and the Company's effective income tax rate is explained as
follows:
Federal income taxes statutory rate
Increase (decrease) in rate as a result of:
State income taxes, net of federal income tax benefit
Penalties
Return to provision adjustment
Noncontrolling interest
Non-deductible Spin-off costs
Other
Effective income tax rate
Year Ended December 31,
2012
35.0 %
2011
2010
35.0 %
35.0 %
(1.2 )%
(0.6 )%
0.4 %
(0.7 )%
—
0.6 %
33.5 %
1.0 %
—
1.3 %
(0.3 )%
—
(0.7 )%
36.3 %
1.5 %
—
0.2 %
(0.2 )%
0.5 %
(0.1 )%
36.9 %
108
Significant components of the Company's deferred income taxes were as follows:
Deferred tax liabilities
Property, plant and equipment
Commodity price and interest rate derivatives
Total deferred tax liabilities
Deferred tax assets
NOL and tax credit carryforwards
Employee benefits and compensation costs
Accrued litigation loss contingency
Bonus and vacation accrual
Other
Total deferred tax assets
Net deferred income tax liability
Balance sheet classification
Deferred income tax liability - current
Deferred income tax liability - non-current
Net deferred income tax liability
December 31,
2012
2011
(in millions)
$
1,606.6
$
1,714.6
69.4
1,676.0
65.6
47.7
42.8
11.8
9.6
177.5
1,498.5
5.0
1,493.5
1,498.5
$
$
$
147.2
1,861.8
232.9
42.9
—
10.7
5.2
291.7
1,570.1
85.4
1,484.7
1,570.1
$
$
$
Federal and state income tax NOLs and credits declined significantly at December 31, 2012, compared to December 31, 2011,
due to an election to capitalize and amortize certain intangible drilling costs in order to minimize alternative minimum tax. The
amounts and expiration dates of operating loss and tax credit carryforwards at December 31, 2012:
State net operating loss and credit carryforwards
U.S. alternative minimum tax credit
Total
Note 13 - Discontinued Operations
Expiration Dates
2014-2032
Indefinite
Amounts
(in millions)
$
$
21.2
44.4
65.6
Wexpro's operating results prior to the Spin-off are reflected in this Annual Report on Form 10-K as discontinued operations
and summarized in the table below:
2012
Year Ended December 31,
2011
(in millions, except per share amounts)
2010
Revenues
Income before income taxes
Income taxes
Discontinued operations, net of income taxes
Earnings per common share attributable to QEP
Basic from discontinued operations
Diluted from discontinued operations
$
$
$
— $
—
—
— $
— $
—
— $
—
—
— $
— $
—
131.2
67.4
(24.2)
43.2
0.25
0.24
109
Note 14 – Operations by Line of Business
QEP's lines of business include natural gas and oil exploration and production (QEP Energy), midstream field services (QEP
Field Services) and marketing (QEP Marketing and other). The lines of business are managed separately and therefore the
financial information is presented separately due to the distinct differences in the nature of operations of each line of business,
among other factors.
The following table is a summary of operating results for the year ended December 31, 2012, by line of business:
QEP
Energy
QEP Field
Services
QEP
Marketing
& Other
(in millions)
Eliminations
QEP
Consolidated
Revenues (1)
From unaffiliated customers
From affiliated customers
Total Revenues
Operating expenses
Purchased gas, oil and NGL expense
Lease operating expense
Natural gas, oil and NGL transportation and
other handling costs
Gathering, processing and other
General and administrative
Production and property taxes
Depreciation, depletion and amortization
Abandonment, impairment and exploration
expenses
Total operating expenses
Net gain from asset sales
Operating (loss) income (1)
Realized and unrealized gains (losses) on
derivative contracts
Interest and other income
Income from unconsolidated affiliates
Loss on early extinguishment of debt
Interest expense
Income (loss) before income taxes
Income tax (provision) benefit
Net income (loss)
Net income attributable to noncontrolling
interest
Net income (loss) attributable to QEP (2)
Identifiable total assets
Investment in unconsolidated affiliates
Cash capital expenditures
Accrued capital expenditures
Goodwill
____________________________
$
$
1,615.4
—
1,615.4
$
320.2
119.0
439.2
224.7
175.8
228.1
—
237.6
97.2
838.0
144.6
1,946.0
1.2
(329.4)
434.9
6.2
0.1
—
(116.8)
(5.0)
4.3
(0.7)
—
(0.7) $
12.1
—
33.6
86.8
34.7
6.0
63.2
—
236.4
—
202.8
8.4
0.2
6.7
—
(13.6)
204.5
(71.8)
132.7
(3.7)
129.0
7,436.5
$
1,399.7
—
2,621.1
2,702.4
59.5
41.2
164.0
171.2
—
$
$
$
$
414.2
605.7
1,019.9
1,021.1
—
—
1.2
0.4
0.2
3.7
—
1,026.6
—
(6.7)
(1.4)
132.1
—
(0.6)
(124.4)
(1.0)
1.0
—
$
— $
(724.7)
(724.7)
(602.3)
(3.5)
(112.8)
—
(6.1)
—
—
—
(724.7)
—
—
—
(131.9)
—
—
131.9
—
—
—
—
— $
2,349.8
—
2,349.8
655.6
172.3
148.9
88.0
266.6
103.4
904.9
144.6
2,484.3
1.2
(133.3)
441.9
6.6
6.8
(0.6)
(122.9)
198.5
(66.5)
132.0
(3.7)
128.3
—
— $
272.3
$
— $
9,108.5
—
14.6
14.6
—
—
—
—
—
41.2
2,799.7
2,888.2
59.5
(1) The impact of QEP's settled derivative contracts, for the year ended December 31, 2012, are reflected below operating
(loss) income.
(2) Net (loss) income attributable to QEP for the year ended December 31, 2012, includes the impact of unrealized gains
and losses from changes in the fair value of the commodity derivative contracts.
110
The following table is a summary of operating results for the year ended December 31, 2011, by line of business:
Revenues (1)
From unaffiliated customers
From affiliated customers
Total Revenues
Operating expenses
Purchased gas, oil and NGL expense
Lease operating expense
Natural gas, oil and NGL transportation and
other handling costs
Gathering, processing and other
General and administrative
Production and property taxes
Depreciation, depletion and amortization
Abandonment, impairment and exploration
expenses
Total operating expenses
Net gain (loss) from asset sales
Operating income (2)
Interest and other income
Income from unconsolidated affiliates
Loss on extinguishment of debt
Interest expense
Income before income taxes
Income taxes
Net income
Net income attributable to noncontrolling
interest
Net income attributable to QEP (3)
Identifiable assets
Investment in unconsolidated affiliates
Cash capital expenditures
Accrued capital expenditures
Goodwill
____________________________
QEP
Energy
QEP Field
Services
QEP
Marketing
& Other
(in millions)
Eliminations
QEP
Consolidated
$
2,213.2
$
369.3
$
576.7
$
— $
3,159.2
—
2,213.2
506.4
148.2
186.0
—
98.4
99.1
707.2
228.9
1,974.2
1.4
240.4
4.0
0.1
—
(81.9)
162.6
(57.9)
104.7
—
104.7
5,815.7
—
1,295.5
1,338.7
59.5
$
$
96.2
465.5
—
—
9.3
106.0
29.2
6.1
55.7
—
206.3
—
259.2
0.1
5.4
—
(13.6)
251.1
(93.4)
157.7
(3.2)
154.5
1,312.7
42.2
130.1
101.6
—
$
$
580.2
1,156.9
1,144.5
—
—
1.3
2.1
0.2
2.5
—
1,150.6
—
6.3
98.7
—
(0.7)
(93.2)
11.1
(3.1)
8.0
—
8.0
314.3
—
5.5
5.5
—
$
$
$
$
(676.4)
(676.4)
(573.8)
(3.0)
(93.1)
—
(6.5)
—
—
—
(676.4)
—
—
(98.7)
—
—
98.7
—
—
—
—
— $
— $
—
—
—
—
—
3,159.2
1,077.1
145.2
102.2
107.3
123.2
105.4
765.4
228.9
2,654.7
1.4
505.9
4.1
5.5
(0.7)
(90.0)
424.8
(154.4)
270.4
(3.2)
267.2
7,442.7
42.2
1,431.1
1,445.8
59.5
(1) Revenues for the year ended December 31, 2011, reflect the impact of QEP's settled derivative contracts. See Note 6 -
Derivative Contracts, for additional information on derivative contract settlements in the year ended December 31,
2011.
(2) Under hedge accounting, realized gains and losses from realized commodity derivative contract settlements were
included in revenues and operating income during the year ended December 31, 2011.
(3) Under hedge accounting, unrealized gains and losses from changes in the fair value were deferred in AOCI during the
year ended December 31, 2011.
111
The following table is a summary of operating results for the year ended December 31, 2010, by line of business:
Revenues (1)
From unaffiliated customers
From affiliated customers
Total Revenues
Operating expenses
Purchased gas, oil and NGL expense
Lease operating expense
Natural gas, oil and NGL transportation and
other handling costs
Gathering, processing and other
General and administrative
Separation costs
Production and property taxes
Depreciation, depletion and amortization
Abandonment, impairment and exploration
expenses
Total operating expenses
Net gain (loss) from asset sales
Operating income (2)
Interest and other income
Income from unconsolidated affiliates
Loss on extinguishment of debt
Interest expense
Income before income taxes
Income taxes
Net income from continuing operations
Discontinued operations, net of income tax
Net Income
Net income attributable to noncontrolling
interest
Net income attributable to QEP (3)
Identifiable assets
Investment in unconsolidated affiliates
Cash capital expenditures
Accrued capital expenditures
Goodwill
____________________________
QEP
Energy
QEP Field
Services
QEP
Marketing
& Other
(in millions)
Eliminations
QEP
Consolidated
$
1,456.3
$
245.5
$
598.8
$
— $
2,300.6
—
1,456.3
73.7
319.2
—
127.3
125.5
—
78.0
—
77.8
592.5
69.1
1,070.2
13.7
399.8
2.1
0.2
—
(78.5)
323.6
(119.7)
203.9
—
203.9
—
203.9
5,391.9
—
1,205.0
1,215.8
59.6
$
$
—
—
—
82.1
31.6
—
4.4
48.9
—
167.0
(1.6)
150.6
0.1
2.8
—
(7.6)
145.9
(51.9)
94.0
—
94.0
(2.9)
91.1
1,197.5
44.5
262.1
268.2
—
$
$
499.7
1,098.5
1,082.8
—
—
1.1
3.9
13.5
0.3
2.0
—
1,103.6
—
(5.1)
87.2
—
(13.3)
(85.4)
(16.6)
4.6
(12.0)
43.2
31.2
—
31.2
195.9
$
$
$
$
—
1.9
1.9
—
(573.4)
(573.4)
(493.5)
(2.3)
(71.3)
—
(6.3)
—
—
—
—
(573.4)
—
—
(87.1)
—
—
87.1
—
—
—
—
—
—
— $
—
2,300.6
589.3
125.0
54.2
83.2
107.2
13.5
82.5
643.4
69.1
1,767.4
12.1
545.3
2.3
3.0
(13.3)
(84.4)
452.9
(167.0)
285.9
43.2
329.1
(2.9)
326.2
— $
6,785.3
—
—
—
—
44.5
1,469.0
1,485.9
59.6
(1) Revenues for the year ended December 31, 2010, reflect the impact of QEP's settled derivative contracts. See Note 6 -
Derivative Contracts, for detailed information on derivative contract settlements in the year ended December 31,
2010.
(2) Under hedge accounting, realized gains and losses from realized commodity derivative contract settlements were
included in revenues and operating income during the year ended December 31, 2010.
(3) Under hedge accounting, unrealized gains and losses from changes in the fair value were deferred in AOCI during the
year ended December 31, 2010.
112
Note 15 – Subsequent Event
On January 7, 2013, QEP announced that its Board of Directors had authorized the formation of a midstream Master Limited
Partnership (MLP) accompanied by the preparation and filing of a registration statement with the SEC for an initial public
offering (IPO) of common units of the MLP. The Company expects to file a registration statement with the SEC in the second
quarter of 2013. The MLP is intended to support the growth of QEP's midstream business and is consistent with the Company's
focus on maximizing shareholder value and maintaining balance sheet strength. The Company expects to initially contribute a
majority share of its gathering assets in Wyoming, North Dakota and Utah to the MLP. Subject to final board approval and
market conditions, QEP expects to sell a minority interest in the MLP in the IPO and raise approximately $300 million to $400
million in gross proceeds. Proceeds from the offering would be used to fund ongoing operations, to repay debt under the
Company's credit facility and for general corporate purposes. Additional detail will be included in the registration statement.
See Note 9 (Commitments and Contingencies) to these consolidated financial statements for a discussion of the mediation and
resulting execution of the Chieftain Settlement Agreement in February 2013.
Note 16 – Quarterly Financial Information (unaudited)
The following table provides a summary of unaudited quarterly financial information:
2012
Revenues
Operating income (loss)
Income (loss) before income taxes
Net income (loss) attributable to QEP
Per share information attributable to QEP
First
Quarter
Second
Quarter
Third
Quarter
(in millions)
Fourth
Quarter
Year
$
603.2
$
49.5
244.7
155.2
$
499.3
(55.5)
0.3
(0.7)
$
542.4
(12.6)
(4.4)
(3.1)
704.9
(114.7)
(42.1)
(23.1)
$ 2,349.8
(133.3)
198.5
128.3
Basic EPS attributable to QEP
Diluted EPS attributable to QEP
$
$
0.87
0.87
— $
—
(0.02) $
(0.02)
(0.13) $
(0.13)
0.72
0.72
2011
Revenues
Operating income
Income (loss) before income taxes
Net income (loss) attributable to QEP
Per share information attributable to QEP
$
617.9
$
808.1
$
879.9
$
853.3
$ 3,159.2
137.1
116.5
73.2
168.9
147.7
92.8
183.4
161.5
101.5
16.5
(0.9)
(0.3)
505.9
424.8
267.2
Basic EPS from continuing operations
$
Basic EPS attributable to QEP
$
0.42
0.41
$
0.52
0.52
$
0.58
0.57
(0.01) $
—
1.51
1.50
Note 17 – Supplemental Gas and Oil Information (Unaudited)
The Company is making the following supplemental disclosures of gas and oil producing activities, in accordance with ASC
932, Extractive Activities - Oil and Gas, as amended by ASU 2010-03, Oil and Gas Reserve Estimation and Disclosures, and
SEC Regulation S-X. The Company uses the successful efforts accounting method for its gas and oil exploration and
development activities. All properties are located in the United States.
Capitalized Costs
The aggregate amounts of costs capitalized for gas and oil exploration and development activities and the related amounts of
accumulated depreciation, depletion and amortization are shown below:
113
Proved properties
Unproved properties, net
Total proved and unproved properties
Accumulated depreciation, depletion and amortization
Net capitalized costs
December 31,
2012
2011
(in millions)
10,234.3
$
937.9
11,172.2
(4,258.1)
6,914.1
$
8,172.4
326.8
8,499.2
(3,339.2)
5,160.0
$
$
Costs Incurred
The costs incurred in gas and oil exploration and development activities are displayed in the table below. Development costs
incurred reflect accrued capital costs of $81.3 million and ARO additions and revisions of $17.7 million during the year ended
December 31, 2012. The costs incurred to advance the development of reserves that were classified as proved undeveloped
were approximately $513.0 million in 2012, $533.6 million in 2011 and $434.2 million in 2010.
Property acquisitions
Unproved
Proved
Total property acquisitions
Exploration (capitalized and expensed)
Development
Total costs incurred
Year Ended December 31,
2012
2011
(in millions)
2010
$
$
692.6
$
48.0
$
714.4
1,407.0
14.3
1,310.0
0.1
48.1
36.5
1,267.8
109.1
0.2
109.3
146.4
988.8
2,731.3
$
1,352.4
$
1,244.5
Results of Operations
Following are the results of operations of QEP Energy gas and oil exploration and development activities, before allocated
corporate overhead and interest expenses.
Revenues (1)
Production costs
Exploration expenses
Depreciation, depletion and amortization
Abandonment and impairment
Total expenses
Income (loss) before income taxes
Income tax benefit (expense)
Year Ended December 31,
2012
2011
(in millions)
2010
$
1,393.4
$
1,703.4
$
1,456.3
501.1
11.2
838.0
133.4
1,483.7
(90.3)
33.6
433.3
10.5
707.2
218.4
1,369.4
334.0
(119.0)
330.6
23.0
592.5
46.1
992.2
464.1
(171.8)
Results of operations from producing activities excluding
allocated corporate overhead and interest expenses
___________________________
$
(56.7) $
215.0
$
292.3
(1) Revenue for the years ended December 31, 2011 and 2010, reflect the impact of QEP's settled derivative contracts
which during the year ended December 31, 2012, are reflected below operating (loss) income. See Note 6 - Derivative
Contracts.
114
Estimated Quantities of Proved Gas and Oil Reserves
Estimates of proved gas and oil reserves have been completed in accordance with professional engineering standards and the
Company's established internal controls, which includes the compliance oversight of a multi-functional reserves review
committee responsible to the Company's Board of Directors. QEP Energy's estimated proved reserves have been prepared by
Ryder Scott Company, L.P., independent reservoir engineering consultants, in accordance with the SEC's Regulation S-X and
ASC 932 as amended. The individuals performing reserves estimates possess professional qualifications and demonstrate
competency in reserves estimation and evaluation. The estimates of proved reserves are inherently imprecise and are
continually subject to revision based on production history, results of additional exploration and development, price changes
and other factors.
All of QEP Energy's proved undeveloped reserves at December 31, 2012, are scheduled to be developed within five years from
the date such locations were initially disclosed as proved undeveloped reserves, except for 200 Bcfe located within the northern
portion of the Company's Pinedale Anticline leasehold in western Wyoming. Long-term development of natural gas reserves in
the Pinedale Anticline Project Area (PAPA) is governed by the Bureau of Land Management's September 2008, Record of
Decision (ROD) on the Final Supplemental Environmental Impact Statements. Under the ROD, QEP Energy is allowed to drill
and complete wells year-round in designated concentrated development areas defined in the PAPA. The ROD contains
additional requirements and restrictions on the sequence of development of the PAPA, which requires the Company to develop
its leasehold from the south to the north. These restrictions result in protracted, phased development of the PAPA that is beyond
the control of the Company. The Company has an ongoing development plan for the PAPA and the financial capability to
continue development in the manner estimated.
115
As of December 31, 2012, all of the Company's oil and gas reserves are attributable to properties within the United Sates. A
summary of the Company's change in quantities of proved oil and gas reserves for the years ended December 31, 2010, 2011
and 2012 are as follows:
Natural Gas
(Bcf)
Oil
(MMbbl)
NGL
(MMbbl)
Natural Gas
Equivalents
(Bcfe)
Proved reserves
Balance at December 31, 2009
Revisions of previous estimates
Extensions and discoveries
Purchase of reserves in place
Sale of reserves in place
Production
Balance at December 31, 2010
Revisions of previous estimates (4)
Extensions and discoveries (5)
Purchase of reserves in place
Sale of reserves in place
Production
Balance at December 31, 2011
Revisions of previous estimates (1)
Extensions and discoveries (2)
Purchase of reserves in place (3)
Sale of reserves in place
Production
Balance at December 31, 2012
Proved developed reserves
Balance at December 31, 2009
Balance at December 31, 2010
Balance at December 31, 2011
Balance at December 31, 2012
Proved undeveloped reserves
Balance at December 31, 2009
Balance at December 31, 2010
Balance at December 31, 2011
Balance at December 31, 2012
____________________________
2,525.0
46.3
248.4
0.2
(3.2)
(203.8)
2,612.9
(270.1)
641.9
1.9
(0.8)
(236.4)
2,749.4
(240.6)
330.6
32.3
—
(249.3)
2,622.4
1,178.7
1,404.8
1,538.3
1,531.7
1,346.3
1,208.1
1,211.1
1,090.7
29.3
0.7
26.1
—
(0.8)
(3.0)
52.3
1.7
17.4
—
(0.2)
(3.7)
67.5
(1.5)
17.3
42.0
—
(6.3)
119.0
22.4
25.1
33.0
47.4
6.9
27.2
34.6
71.6
7.7
4.8
6.1
—
—
(1.2)
17.4
39.3
22.6
—
—
(2.7)
76.6
0.7
23.0
4.9
—
(5.3)
99.9
4.9
9.3
38.4
49.3
2.8
8.0
38.2
50.6
2,746.9
78.6
441.8
0.2
(7.8)
(229.0)
3,030.7
(23.5)
881.6
2.1
(1.9)
(275.2)
3,613.8
(244.8)
572.5
313.8
—
(319.2)
3,936.1
1,342.8
1,611.5
1,966.3
2,111.9
1,404.1
1,419.2
1,647.5
1,824.2
(1)
(2)
Revisions of previous estimates in 2012 include negative impacts due to 152.4 Bcfe pricing revisions, 35.6 Bcfe
performance revisions, 27.6 Bcfe operating cost revisions and 29.1 Bcfe other revisions. The 152.4 Bcfe pricing revisions
were due to lower natural gas prices which reduced natural gas reserve volumes by 147.7 Bcf. Negative performance
revisions were driven by a 56.0 Bcfe decrease in Pinedale reserves. Pinedale reserve adjustments are based on additional
production history, well performance and current pricing causing a revised future development plan which includes lower
density drilling in some flank areas, resulting in 25 proved undeveloped (PUD) locations being eliminated. Reserve
decreases are partially offset by a 35.9 Bcfe positive impact from revisions in the Uinta Basin, due to the installation of
the Iron Horse Cryogenic plant to increase liquid recoveries and improved well performance in the Red Wash Mesaverde
field.
Extensions and discoveries in 2012 increased proved reserves by 572.5 Bcfe, primarily related to extensions and
discoveries in the Uinta Basin of 258.3 Bcfe, in Pinedale of 151.6 Bcfe, and 162.6 Bcfe in the Williston Basin,
116
(3)
(4)
(5)
Midcontinent and other Legacy areas of operation combined. All of these extensions and discoveries related to new well
completions and the associated new PUD locations as part of the Company's development drilling plans.
Purchase of reserves in place primarily relate to the Company's $1.4 billion 2012 Acquisition as discussed in Note 2 -
Acquisition.
Revisions of previous estimates in 2011 include 173.7 Bcfe negative impact due to performance revisions offset by 150.2
Bcfe positive impact from other revisions. The 173.7 Bcfe performance revisions were due to the reduction of natural gas
volumes of 209.8 Bcf, partially offset by an increase in NGL volumes of 33.2 MMbbls, which is included in other
revisions. The primary reason for the increase in the NGL volumes, or 31.8 MMbbls, relates to the completion of the
Blacks Fork II plant and the fee-based processing agreement entered into between QEP Energy and QEP Field Services
for QEP Energy's Pinedale production, offset by a reduction in the dry natural gas reserve related to shrink of about 59.6
Bcf. The remaining performance related reduction in the natural gas reserves was primarily related to the removal of
certain PUD locations in the Haynesville/Cotton Valley area to recognize the 80-acre increased density development plan.
Extensions and discoveries increased proved reserves by 881.6 Bcfe, primarily related to extensions and discoveries at
the Haynesville/Cotton Valley area (358.8 Bcfe), Uinta Basin area (189.1 Bcfe) and Pinedale Anticline area (161.2 Bcfe).
All of these extensions and discoveries related to new well completions and associated new PUD locations. Estimates of
the quantity of proved reserves from the Company's Pinedale Anticline leasehold in western Wyoming have changed
substantially over time as a result of numerous factors including, but not limited to, additional development drilling
activity, producing well performance and the development and application of reliable technologies. The continued
analysis of new data has led to progressive increases in estimates of original gas-in-place at Pinedale and to a better
understanding of the appropriate well density to maximize the economic recovery of the in-place volumes. With the
application of the amendments of ASC 932 in ASU 2010-03, reserves associated with Pinedale increased density drilling
are included in extensions and discoveries for the years ended December 31, 2011 and 2010, because each new well
drilled recovers incremental reserves that would otherwise be unrecoverable.
Standardized Measure of Future Net Cash Flows Relating to Proved Reserves
Future net cash flows were calculated at December 31, 2012, 2011 and 2010, by applying prices, which were the simple
average of the first-of-the-month commodity prices, adjusted for location and quality differentials, for the 12-months of 2012,
2011 and 2010 with consideration of known contractual price changes. The prices used do not include any impact of QEP's
commodity derivatives portfolio. The following table provides the average benchmark prices per unit, before location and
quality differential adjustments, used to calculate the related reserve category:
For the year ended December 31,
2012
2011
2010
Average benchmark price per unit:
Natural gas price (per MMbtu)
$
2.76
$
4.12
$
Crude oil price (per Bbl)
94.71
96.19
4.38
79.43
Year-end operating expenses, development costs and appropriate statutory income tax rates, with consideration of future tax
rates, were used to compute the future net cash flows. All cash flows were discounted at 10% to reflect the time value of cash
flows, without regard to the risk of specific properties. The estimated future costs to develop booked proved undeveloped
reserves are approximately $1,042.5 million in 2013, $871.1 million in 2014 and $814.5 million in 2015.
The assumptions used to derive the standardized measure of future net cash flows are those required by accounting standards
and do not necessarily reflect the Company's expectations. The information may be useful for certain comparative purposes, but
should not be solely relied upon in evaluating QEP or its performance. Furthermore, information contained in the following
table may not represent realistic assessments of future cash flows, nor should the standardized measure of future net cash flows
be viewed as representative of the current value of the Company's reserves. Management believes that the following factors
should be considered when reviewing the information below:
117
•
•
•
Future commodity prices received for selling the Company's net production will probably differ from those required to
be used in these calculations.
Future operating and capital costs will probably differ from those required to be used in these calculations.
Future market conditions, government regulations and reservoir conditions may cause production rates in future years
to vary significantly from those rates used in the calculations.
Future revenues may be subject to different production, severance and property taxation rates.
•
• The selection of a 10% discount rate is arbitrary and may not be a reasonable factor in adjusting for future economic
conditions or in considering the risk that is part of realizing future net cash flows from the reserves.
The standardized measure of future net cash flows relating to proved reserves is presented in the table below:
Future cash inflows
Future production costs
Future development costs
Future income tax expenses
Future net cash flows
10% annual discount for estimated timing of net cash flows
Standardized measure of discounted future net cash flows
$
$
2012
$
Year Ended December 31,
2011
(in millions)
18,300.6
$
(4,276.1)
(3,250.0)
(2,837.1)
7,937.4
(4,411.8)
3,525.6
18,200.2
(5,027.2)
(3,927.3)
(2,269.0)
6,976.7
(3,942.0)
3,034.7
$
$
2010
14,174.8
(3,701.8)
(2,275.9)
(1,957.6)
6,239.5
(3,533.9)
2,705.6
The principal sources of change in the standardized measure of future net cash flows relating to proved reserves is presented in
the table below:
Balance at January 1,
Sales of gas, oil and NGL produced during the period, net of production costs
Net change in sales prices and in production (lifting) costs related to future
production
Net change due to extensions, discoveries and improved recovery
Net change due to revisions of quantity estimates
Changes due to purchases of reserves in place
Changes due to sales of reserves in place
Previously estimated development costs incurred during the period
Changes in estimated future development costs
Accretion of discount
Net change in income taxes
Other
Net change
Balance at December 31,
Year Ended December 31,
2012
2011
2010
(in millions)
$ 3,525.6
(892.3)
$ 2,705.6
(1,779.9)
$ 1,443.0
(1,125.7)
(2,083.5)
948.5
(387.8)
831.4
—
513.0
(209.3)
499.4
273.6
16.1
(490.9)
$ 3,034.7
1,472.5
1,775.8
1,806.4
(48.2)
0.1
(8.0)
533.6
(1,110.4)
355.4
(411.4)
9.9
789.1
140.4
0.2
(26.0)
434.2
(325.4)
170.9
(582.4)
11.5
820.0
1,262.6
$ 3,525.6
$ 2,705.6
118
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
As disclosed in the Company's Current Report on Form 8-K, filed with the SEC on November 17, 2011, and its Current Report
on Form 8-K/A, filed with the SEC on February 28, 2012, the Company changed its independent registered public accountants
effective for the fiscal year ended December 31, 2012.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
The Company's Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the design and
operation of the Company's disclosure controls and procedures (as such term is defined in Rule 13a-15(e) under the Securities
Exchange Act of 1934 as amended), as of December 31, 2012. Based on such evaluation, such officers have concluded that, as
of December 31, 2012, the Company's disclosure controls and procedures are designed and effective to ensure that information
required to be included in the Company's reports filed or submitted under the Exchange Act is recorded, processed, summarized
and reported within the time periods specified by the SEC's rules and forms and that information required to be disclosed in
reports filed or submitted by the Company under the Exchange Act is accumulated and communicated to the Company's
management including its principal executive officer and principal financial officer, or persons performing similar functions, as
appropriate, to allow timely decisions regarding required disclosure.
In designing and evaluating the Company's disclosure controls and procedures, management recognizes that any controls and
procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the
objectives of the control system will be met. In addition, the design of any control system is based in part upon certain
assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of
possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable
assurance that the Company's controls will succeed in achieving their goals under all potential future conditions.
Changes in Internal Controls
There were no changes in the Company's internal controls over financial reporting that occurred during the quarter ended
December 31, 2012, that have materially affected, or are reasonably likely to materially affect, the Company's internal control
over financial reporting.
Management's Assessment of Internal Control Over Financial Reporting
The Company's management is responsible for establishing and maintaining adequate internal control over financial reporting,
as defined in Exchange Act Rule 13a-15(f). The Company's internal control over financial reporting is a process designed under
the supervision of QEP's Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance
with accounting principles generally accepted in the United States of America. Because of its inherent limitations, internal
control over financial reporting may not detect or prevent misstatements. Also, projections of any evaluation of the
effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or
that the degree of compliance with the policies or processes may deteriorate.
As of December 31, 2012, management assessed the effectiveness of our internal control over financial reporting based on the
criteria for effective internal control over financial reporting established in Internal Control—Integrated Framework, issued by
the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, management determined
that the Company maintained effective internal control over financial reporting as of December 31, 2012, based on those
criteria. Management included in its assessment of internal control over financial reporting all consolidated entities.
PricewaterhouseCoopers, LLP, the independent registered public accounting firm that audited the consolidated financial
statements included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of internal control
over financial reporting as of December 31, 2012, which is included in the consolidated financial statements in Item 8 of Part II
of this Annual Report on Form 10-K.
ITEM 9B. OTHER INFORMATION
None.
119
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by Item 10 concerning QEP's directors and nominees for directors and other corporate governance
matters will be presented in the Company's definitive Proxy Statement prepared for the solicitation of proxies in connection
with the Company's annual Meeting of Stockholders to be held on May 24, 2013, which will be filed with the Securities and
Exchange Commission no later than 120 days subsequent to December 31, 2012 (Proxy Statement), and is incorporated by
reference herein.
Information about the Company's executive officers can be found in Item 1 of Part I in this Annual Report on Form 10-K.
Information concerning compliance with Section 16(a) of the Exchange Act will be set forth in the Proxy Statement and is
incorporated herein by reference.
The Company has a Business Ethics and Compliance Policy (Ethics Policy) that applies to all of its directors, officers
(including its Chief Executive Officer and Chief Financial Officer) and employees. QEP has posted the Ethics Policy on its
website, www.qepres.com. Any waiver of the Ethics Policy for executive officers must be approved only by the Company's
Board of Directors. QEP will post on its website any amendments to or waivers of the Ethics Policy that apply to executive
officers.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 will be set forth in the Proxy Statement and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
STOCKHOLDER MATTERS
The information required by Item 12 will be set forth in the Proxy Statement and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by Item 13 will be set forth in the Proxy Statement and is incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by Item 14 will be set forth in the Proxy Statement and is incorporated herein by reference.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
PART IV
(a) Financial statements and financial statement schedules filed as part of this report are listed in the index included in Item 8.
Financial Statements and Supplementary Data of this report.
(b) Exhibits. The following is a list of exhibits required to be filed as a part of this report in Item 15(b).
120
Exhibit No.
Description
2.1
2.2
3.1
3.2
3.3
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
10.1
10.2
10.3
Agreement and Plan of Merger dated as of May 18, 2010, between Questar Market Resources, Inc., a Utah
corporation, and QEP Resources, Inc., a Delaware corporation. (Incorporated by reference to Exhibit No. 2.1 to
the Company's Current Report on Form 8-K filed with the Securities and Exchange Commission on May 24,
2010.)
Separation and Distribution Agreement dated as of June 14, 2010, by and between Questar Corporation and
QEP Resources, Inc. (Incorporated by reference to Exhibit No. 2.1 to the Company's Current Report on Form 8-
K filed with the Securities and Exchange Commission on June 16, 2010.)
Certificate of Incorporation dated May 18, 2010. (Incorporated by reference to Exhibit No. 3.1 to the
Company's Current Report on Form 8-K filed with the Securities and Exchange Commission on May 24, 2010.)
Amended and Restated Bylaws, deemed effective February 14, 2013. (Incorporated by reference to Exhibit No.
3.1 to the Company's Current Report on Form 8-K filed with the Securities and Exchange Commission on
February 15, 2013.)
Certificate of Elimination with respect to Series A Junior Participating Preferred Stock of QEP Resources, Inc.
(Incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K filed with the
Securities and Exchange Commission on May 16, 2012.)
Indenture dated as of March 1, 2001, between Questar Market Resources, Inc. (predecessor-in-interest to QEP
Resources, Inc.) and Bank One, NA, (predecessor-in-interest to Wells Fargo Bank, National Association), as
Trustee, (Incorporated by reference to Exhibit No. 4.01 to the Company's Current Report on Form 8-K filed
with the Securities and Exchange Commission on March 13, 2001.)
The Company's 6.05% Notes due 2016. (Incorporated by reference to Exhibit 99.2 to the Company's Current
Report on Form 8-K filed with the Securities and Exchange Commission on May 15, 2006.)
Officers' Certificate setting forth the terms of the Company's 6.05% Notes due 2016. (Incorporated by reference
to Exhibit 99.3 to the Company's Current Report on Form 8-K filed with the Securities and Exchange
Commission on May 15, 2006.)
The Company's 6.80% Notes due 2018. (Incorporated by reference to Exhibit 4.1 to the Company's Current
Report on Form 8-K filed with the Securities and Exchange Commission on April 1, 2008.)
Officers' Certificate setting forth the terms of the Company's 6.80% Notes due 2018. (Incorporated by reference
to Exhibit 4.2 to the Company's Current Report on Form 8-K filed with the Securities and Exchange
Commission on April 1, 2008.)
The Company's 6.80% Notes due 2020. (Incorporated by reference to Exhibit 4.1 to the Company's Current
Report on Form 8-K filed with the Securities and Exchange Commission on September 2, 2009.)
Officers' Certificate setting forth the terms of the Company's 6.80% Notes due 2020. (Incorporated by reference
to Exhibit 4.2 to the Company's Current Report on Form 8-K filed with the Securities and Exchange
Commission on September 2, 2009.)
Officers' Certificate, dated as of August 16, 2010 (including the form of the Company's 6.875% Notes due
2021). (Incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed with the
Securities and Exchange Commission on August 16, 2010.)
Indenture, dated as of March 1, 2012, between the Company and Wells Fargo Bank, National Association, as
Trustee. (Incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed with the
Securities and Exchange Commission on March 1, 2012.)
Officer's Certificate, dated as of March 1, 2012 (including the form of the Company's 5.375% Notes due 2022).
(Incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K filed with the
Securities and Exchange Commission on March 1, 2012.)
Officer's Certificate, dated as of September 12, 2012 (including form of the Registrant's 5.250% Notes due
2023). (Incorporated by reference to Exhibit No. 4.1 to the Company's Current Report on Form 8-K filed with
the Securities and Exchange Commission on September 14, 2012.)
Credit Agreement, dated as of August 25, 2011, among QEP Resources, Inc., Wells Fargo Bank, National
Association, as the administrative agent, letter of credit issuer and swing line lender, and the lenders party
thereto. (Incorporated by reference to Exhibit No. 10.1 to the Company's Current Report on Form 8-K filed
with the Securities and Exchange Commission on August 25, 2011.)
Term Loan Agreement, dated as of April 18, 2012, among QEP Resources, Inc, as borrower, Wells Fargo Bank,
National Association, as administrative agent, and the lenders party thereto. (Incorporated by reference to
Exhibit No. 10.1 to the Company's Current Report on Form 8-K filed with the Securities and Exchange
Commission on April 20, 2012.)
Employee Matters Agreement, dated as of June 14, 2010, by and between Questar Corporation and QEP
Resources, Inc. (Incorporated by reference to Exhibit No. 10.1 to the Company's Current Report on Form 8-K
filed with the Securities and Exchange Commission on June 16, 2010.)
121
10.4
10.5
10.6+
10.7+
10.8+
10.9+
10.10+
10.11+
10.12+
10.13+
10.14+
10.15+
10.16+
10.17+
10.18+
10.19+
10.20+
10.21+
10.22+
Tax Matters Agreement, dated as of June 14, 2010, by and between Questar Corporation and QEP Resources,
Inc. (Incorporated by reference to Exhibit No. 10.2 to the Company's Current Report on Form 8-K filed with
the Securities and Exchange Commission on June 16, 2010.)
Transition Services Agreement, dated as of June 14, 2010, by and between Questar Corporation and QEP
Resources, Inc. (Incorporated by reference to Exhibit No. 10.3 to the Company's Current Report on Form 8-K
filed with the Securities and Exchange Commission on June 16, 2010.)
QEP Resources, Inc. Deferred Compensation Plan for Directors (Incorporated by reference to Exhibit No. 10.4
to the Company's Current Report on Form 8-K filed with the Securities and Exchange Commission on June 16,
2010.)
Amended and Restated Employment Agreement dated June 15, 2010 by and between QEP Resources, Inc.,
Questar Corporation and Charles B. Stanley (Incorporated by reference to Exhibit No. 10.5 to the Company's
Current Report on Form 8-K filed with the Securities and Exchange Commission on June 16, 2010.)
Amended and Restated Employment Agreement dated June 15, 2010 by and between QEP Resources, Inc.,
Questar Corporation and Richard J. Doleshek (Incorporated by reference to Exhibit No. 10.6 to the Company's
Current Report on Form 8-K filed with the Securities and Exchange Commission on June 16, 2010.)
QEP Resources, Inc. Cash Incentive Plan, dated effective as of January 1, 2012. (Incorporated by reference to
Appendix A to the Company's Proxy Statement on Schedule 14A filed with the Securities and Exchange
Commission on April 3, 2012.)
QEP Resources, Inc. 2010 Long-Term Stock Incentive Plan adopted June 12, 2010. (Incorporated by reference
to Exhibit No. 10.9 to the Company's Current Report on Form 8-K filed with the Securities and Exchange
Commission on June 16, 2010.)
QEP Resources, Inc. Executive Severance Compensation Plan effective as of March 1, 2012. (Incorporated by
reference to Exhibit No. 10.1 to the Company's Current Report on Form 8-K filed with the Securities and
Exchange Commission on May 16, 2012.)
QEP Resources, Inc. Amended Deferred Compensation Wrap Plan adopted January 28, 2013. (Incorporated by
reference to Exhibit No. 10.1 to the Company's Current Report on Form 8-K filed with the Securities and
Exchange Commission on January 31, 2013.)
QEP Resources, Inc. Supplemental Executive Retirement Plan (Incorporated by reference to Exhibit No. 10.12
to the Company's Current Report on Form 8-K filed with the Securities and Exchange Commission on June 16,
2010), as amended by the Amended Deferred Compensation Wrap Plan adopted January 28, 2013.
(Incorporated by reference to Exhibit No. 10.1 to the Company's Current Report on Form 8-K filed with the
Securities and Exchange Commission on January 31, 2013.)
QEP Resources, Inc. Form of Nonqualified Stock Option Agreement for nonqualified stock options granted to
certain key executives. (Incorporated by reference to Exhibit No. 10.1. to the Company's Current Report on
Form 8-K filed with the Securities and Exchange Commission on June 29, 2010.)
QEP Resources, Inc. Form of Nonqualified Stock Option Agreement for nonqualified stock options granted to
other officers and key employees. (Incorporated by reference to Exhibit No. 10.2 to the Company's Current
Report on Form 8-K filed with the Securities and Exchange Commission on June 29, 2010.)
QEP Resources, Inc. Form of Incentive Stock Option Agreement for incentive stock options granted to certain
key executives. (Incorporated by reference to Exhibit No. 10.3. to the Company's Current Report on Form 8-K
filed with the Securities and Exchange Commission on June 29, 2010.)
QEP Resources, Inc. Form of Incentive Stock Option Agreement for incentive stock options granted to other
officers and key employees. (Incorporated by reference to Exhibit No. 10.4 to the Company's Current Report on
Form 8-K filed with the Securities and Exchange Commission on June 29, 2010.)
QEP Resources, Inc. Form of Restricted Stock Agreement for restricted stock granted to certain key executives.
(Incorporated by reference to Exhibit No. 10.5 to the Company's Current Report on Form 8-K filed with the
Securities and Exchange Commission on June 29, 2010.)
QEP Resources, Inc. Form of Restricted Stock Agreement for restricted stock granted to other officers and key
employees. (Incorporated by reference to Exhibit No. 10.6 to the Company's Current Report on Form 8-K filed
with the Securities and Exchange Commission on June 29, 2010.)
QEP Resources, Inc. Form of Restricted Stock Agreement for restricted stock granted to non-employee
directors. (Incorporated by reference to Exhibit No. 10.7 to the Company's Current Report on Form 8-K filed
with the Securities and Exchange Commission on June 29, 2010.)
QEP Resources, Inc. Form of Phantom Stock Agreement for phantom stock granted to non-employee directors.
(Incorporated by reference to Exhibit No. 10.8 to the Company's Current Report on Form 8-K filed with the
Securities and Exchange Commission on June 29, 2010.)
QEP Resources, Inc. Form of Restricted Stock Units Agreement for restricted stock units granted to Mr. Keith
O. Rattie. (Incorporated by reference to Exhibit No. 10.9 to the Company's Current Report on Form 8-K filed
with the Securities and Exchange Commission on June 29, 2010.)
122
10.23
10.24
10.25
Purchase and Sale Agreement, dated August 23, 2012, by and among QEP Energy Company, as purchaser, and
Helis Oil & Gas Company, L.L.C., as seller. (Incorporate by reference to Exhibit No. 10.1 to the Company's
Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on October 30, 2012.)
Purchase and Sale Agreement, dated August 23, 2012, by and among QEP Energy Company, as purchaser, and
Black Hills Exploration and Production, Inc., Unit Petroleum Company, Sundance Energy, Inc., Highline
Exploration, Inc., Houston Energy, L.P., Nisku Royalty, LP, Empire Oil Company and Kent M. Lynch, as
sellers. (Incorporate by reference to Exhibit No. 10.2 to the Company's Quarterly Report on Form 10-Q filed
with the Securities and Exchange Commission on October 30, 2012.)
Stipulation and Agreement of Settlement, filed February 13, 2013, in the U.S. District Court for the Western
District of Oklahoma. (Incorporated by reference to Exhibit No. 10.1 to the Company's Current Report on Form
8-K filed with the Securities and Exchange Commission on February 15, 2013.)
12.1*
Ratio of earnings to fixed charges.
16.1
21.1*
23.1*
23.2*
23.3*
24*
31.1*
31.2*
32.1*
99.1*
Letter from Ernst & Young LLP to the Securities and Exchange Commission dated February 28, 2012 regarding
change in Registrant's Certifying Accountant. (Incorporated by reference to Exhibit No. 16.1 to the Company's
Current Report on Form 8-K/A filed with the Securities and Exchange Commission on February 28, 2012.)
Subsidiaries of the Company.
Consent of Independent Registered Public Accounting Firm. - PricewaterhouseCoopers LLP.
Consent of Independent Registered Public Accounting Firm - Ernst & Young LLP.
Consent of Independent Petroleum Engineers and Geologists - Ryder Scott Company, L.P.
Power of Attorney
Certification signed by Charles B. Stanley, QEP Resources, Inc. , Chairman, President and Chief Executive
Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Certification signed by Richard J. Doleshek, QEP Resources, Inc. Executive Vice President, Chief Financial
Officer and Treasurer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Certification signed by Charles B. Stanley and Richard J. Doleshek, QEP Resources, Inc. Chairman, President
and Chief Executive Officer and Executive Vice President, Chief Financial Officer and Treasurer, respectively,
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Qualifications and Report of Independent Petroleum Engineers and Geologists - Ryder Scott Company, L.P.
101.INS* XBRL Instance Document
101.SCH* XBRL Schema Document
101.CAL* XBRL Calculation Linkbase Document
101.LAB* XBRL Label Linkbase Document
101.PRE* XBRL Presentation Linkbase Document
101.DEF* XBRL Definition Linkbase Document
*Filed herewith
+ Indicates a management contract or compensatory plan or arrangement
123
(c) Financial Statement Schedule:
QEP RESOURCES, INC.
Schedule of Valuation and Qualifying Accounts
Description
Beginning
Balance
Amounts charged (credited) to
expense
Deductions for accounts
written off and other
Ending
Balance
Year ended December 31, 2012
Allowance for bad debts
$
1.7
$
1.4
$
(0.3) $
(in millions)
Year ended December 31, 2011
Allowance for bad debts
Year ended December 31, 2010
Allowance for bad debts
2.3
3.0
0.2
(0.3)
(0.8)
(0.4)
2.8
1.7
2.3
124
Pursuant to the requirements of Section 13 or 15(d) 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, on February 22, 2013.
SIGNATURES
QEP RESOURCES, INC.
(Registrant)
/s/ C. B. Stanley
C. B. Stanley,
Chairman, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on February 22, 2013.
/s/ C. B. Stanley
C. B. Stanley
/s/ Richard J. Doleshek
Richard J. Doleshek
/s/ Kendall K. Carbone
Kendall K. Carbone
*C. B. Stanley
*Keith O. Rattie
*Phillips S. Baker, Jr.
*L. Richard Flury
*David Trice
*Robert E. McKee III
*M. W. Scoggins
February 22, 2013
Chairman, President and Chief Executive Officer
(Principal Executive Officer)
Executive Vice President, Chief Financial Officer and
Treasurer (Principal Financial Officer)
Vice President and Controller
(Principal Accounting Officer)
Chairman of the Board; Director
Director
Director
Director
Director
Director
Director
By /s/ C. B. Stanley
C. B. Stanley, Attorney in Fact
125
Corporate Information
Common StoCk
• 178.5 million basic shares issued, par value $0.01 per share, at Dec. 31, 2012
• Listed on the New York Stock Exchange, ticker symbol: QEP
SHAREHoLDER RECoRDS, tRAnSFER AnD PAYInG AGEnt
Wells Fargo Bank, N.A.
Shareowner Services
1110 Centre Pointe Curve, Suite 101
Mendota Heights, MN 55120-4100
Tel. 866-877-6324 (toll free)
FoRm 10-k
QEP Resources’ Form 10-K—an annual report of company operations filed with
the Securities and Exchange Commission—is available online at www.sec.gov, or at
www.qepres.com, or by calling QEP Investor Relations at 303-405-6665.
FoRWARD-LookInG StAtEmEntS
This Annual Report 2012 contains forward-looking statements regarding estimates
of reserves and production and plans and expectations for our business and opera-
tions. Actual results may differ materially from those anticipated due to many
factors. For more information, see “Forward-Looking Statements” on pages 2 and 3
of our Form 10-K included in this report.
In filings with the SEC, the SEC requires disclosure of proved reserves and permits
optional disclosure of probable and possible reserves. We do not disclose probable
and possible reserves in our SEC filings but do include such reserves in this Annual
Report 2012. We also include in this Annual Report 2012 the term “EUR” or
“estimated ultimate recovery,” and SEC guidelines strictly prohibit us from including
such estimates in our SEC filings. EUR, as well as estimates of probable and possible
reserves, are by their nature more speculative than estimates of proved reserves and,
accordingly, are subject to substantially more risks of actually being realized. For a
discussion of such risks, see our risk factor and reserve disclosures in the Form 10-K
included in this Annual Report 2012.
AnnUAL mEEtInG
The 2013 Annual Meeting of Shareholders will be held at 8 a.m. MDT Friday,
May 24, 2013, at The Westin Denver Downtown, 1672 Lawrence Street, Denver,
Colorado 80202.
AnALYSt AnD mEDIA ContACt
Greg Bensen
Director, Investor Relations
Tel. 303-405-6665
Email: greg.bensen@qepres.com
AUDItoRS
PricewaterhouseCoopers LLP
GLoSSARY oF tERmS
A glossary of terms used in this Annual Report 2012 can be found on pages 4
through 6 of our Form 10-K included in this report.
PRInCIPAL oFFICE
QEP Resources
1050 17th Street
Suite 500
Denver, CO 80265
Tel. 303-672-6900
mAJoR SUBSIDIARIES
QEP Energy Company
QEP Field Services Company
QEP Marketing Company
CoRPoRAtE WEB SItE
Corporate information is available online at www.qepres.com.
ComPAnY CERtIFICAtIon
In 2012, the company submitted the annual certification of its chief executive officer
regarding the company’s compliance with the New York Stock Exchange’s corporate
governance listing standards pursuant to Section 303A.12(a) of the NYSE Listed
Company Manual.
oFFICERS
Charles B. Stanley
Chairman, President and CEO, QEP Resources
Richard J. Doleshek
Executive Vice President, CFO and Treasurer, QEP Resources
Jay B. neese
Executive Vice President, QEP Resources
Austin S. murr
Senior Vice President, Land and Business Development, QEP Energy
Perry H. Richards
Senior Vice President, QEP Field Services
Jim E. torgerson
Senior Vice President, Operations, QEP Energy
kendall k. Carbone
Vice President, Controller and Chief Accounting Officer, QEP Resources
margo D. Fiala
Vice President, Human Resources, QEP Resources
S. Scott Gutberlet
Vice President, Commercial and Technical Services, QEP Energy
Abigail L. Jones
Vice President, Compliance and Corporate Secretary, QEP Resources
kevin R. Peretti
Vice President, Engineering and Operations, QEP Field Services
Vincent G. Rigatti
Vice President, New Ventures, QEP Energy
Jeffery R. tommerup
Vice President, Southern Region, QEP Energy
michael k. Watanabe
Vice President, Land, QEP Energy
Christopher k. Woosley
Vice President and General Counsel, QEP Resources
Board of Directors
Dr. M. W. Scoggins, (65)
President, Colorado School of Mines;
retired executive vice president, ExxonMobil
Production Co.; previously held senior
executive positions with Mobil Corp.;
director, Cobalt International Energy and
Laredo Petroleum Holdings Inc.; Questar
director 2005–2010; QEP director since
2010; QEP lead director since 2012.
Mr. Charles B. Stanley, (54)
Chairman of the Board since 2012;
president and chief executive officer, QEP;
former executive vice president and chief
operating officer, Questar; director, Hecla
Mining Company; Questar director 2002–
2010; QEP director since 2010.
Mr. David A. Trice, (64)
Retired chairman and chief executive officer,
Newfield Exploration Company; director,
New Jersey Resources Corporation,
McDermott International, Inc., Rockwater
Energy Solutions, Inc. and Crazy Mountain
Brewery, LLC.; QEP director since 2011.
Mr. Phillips S. Baker, Jr., (53)
President, chief executive officer and direc-
tor, Hecla Mining Company; former chief
financial officer and chief operating officer,
Hecla; Questar director 2004–2010; QEP
director since 2010.
Mr. L. Richard Flury, (65)
Retired chief executive, gas and power, BP
plc; former chief executive worldwide explo-
ration and production, Amoco Corp; non-
executive chairman, Chicago Bridge and
Iron NV and director, Callon Petroleum
Co.; Questar director 2002–2010; QEP
director since 2010.
Mr. Robert E. McKee, III, (66)
Retired executive vice president, exploration
and production, Conoco Phillips and
Conoco Corp.; director, Parker Drilling Co.
and Post Oak Bank; Questar director
2003–2010; QEP director since 2010.
Mr. Keith O. Rattie, (59)
Former president and chief executive officer,
Questar Corporation; non-executive chair-
man and director, QEP 2010–2012; non-
executive chairman, Questar Corporation;
director, ENSCO International, Rockwater
Energy Solutions, Inc. and Zions First
National Bank; QEP director since 2010.
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