10-K 1 qep-20161231x10k.htm 10-K Document


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
 
ý ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2016
 
001-34778
 
 
(Commission File No.)
 
qepresourcesstackcmykra08.jpg
QEP RESOURCES, INC.
(Exact name of registrant as specified in its charter)
 
STATE OF DELAWARE
 
87-0287750
(State or other jurisdiction of incorporation)
 
(I.R.S. Employer Identification No.)
 1050 17th Street, Suite 800, 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
 
Name of each exchange on which registered
Common stock, $0.01 par value
 
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 ý 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 ý
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 ý 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 ý 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. Yes ý No ¨
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
ý
 
Accelerated filer
o
 
 
 
 
 
Non-accelerated filer
o
(Do not check if a smaller reporting company)
Smaller reporting company
o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No ý




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, 2016): $4,224,248,350.

At January 31, 2017, there were 239,566,263 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 2017 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
 
 
 
Page
 
 
 
 
 
 
 
 

1


Where You Can Find More Information
 
QEP Resources, Inc. (QEP or the Company) files annual, quarterly, and current reports with the U.S. Securities and Exchange Commission (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 800-732-0330 for further information on the operation of the Public Reference Room. The SEC also maintains an Internet site at 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 Securities Exchange Act of 1934 (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 this 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 800, Denver, CO 80265 (telephone number: 303-672-6900).

Cautionary Statement Regarding 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 (the Securities Act), and Section 21E of the Exchange Act. 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:

our growth strategies;
strong liquidity position providing financial flexibility;
our liquidity and sufficiency of cash flow from operations, cash on hand and, if needed, availability under our revolving credit facility to fund our operations and planned capital expenditures;
plans and ability to pursue acquisition opportunities;
our inventory of drilling locations;
drilling and completion plans and strategies;
results from planned drilling operations and production operations;
plans to increase oil and gas production;
oil exports from and imports to the U.S.;
payments of dividends;
estimates of reserves;
future development costs;
development of proved undeveloped (PUD) reserves within five years;
leasehold development and financial capability to continue planned development;
ability to incur additional indebtedness under our revolving credit facility;
loss contingencies;
sufficiency of accruals;
expectations regarding oil, gas and NGL prices;
plans to recover or reject ethane from produced natural gas;
pro forma results for acquired properties;
impact of lower or higher commodity prices and interest rates;
the unfunded status of our pension plan;
volatility of oil, gas and NGL prices and factors impacting such prices;
impact of global geopolitical and macroeconomic events;
plans to enter into derivative contracts and the anticipated benefits from our derivative contracts;

2



divestitures of assets;
trucking of products to sales points;
impact of weather on drilling, completion and production operations;
need for capital expenditures to address air emission issues;
amount and allocation of forecasted capital expenditures and plans for funding capital expenditures, operating expenses and working capital requirements;
adequacy of insurance;
impact of and compliance with government regulations;
assumptions regarding equity compensation;
settlement of performance share units in cash;
recognition of compensation costs related to equity compensation grants;
expected contributions to our employee benefit plans;
employee benefit plan gains or losses;
the usefulness of Adjusted EBITDA (a non-GAAP financial measure) as a measure of financial performance and adjustments made to net income to arrive at Adjusted EBITDA;
delays caused by transportation, processing, storage and refining capacity issues;
fair values and critical accounting estimates, including estimated asset retirement obligations;
uncertain tax positions;
unrecognized tax benefits and the realization of those benefits;
implementation and impact of new accounting pronouncements;
impact of shutting in wells;
factors impacting our ability to transport oil and gas;
potential for asset impairments and impact of impairments on financial statements;
no expected additional costs of restructurings;
managing counterparty risk exposure;
loss of customers;
outcome and impact of various claims;
ability to meet delivery and sales commitments;
impact of our charter and bylaws on a potential takeover;
inflation and deflation; and
value of pension plan assets and plans regarding additional contributions to the pension plan.

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 risk factors in Part I, Item 1A of this Annual Report on Form 10-K;
changes in oil, gas and NGL prices;
global geopolitical and macroeconomic factors;
general economic conditions, including the performance of financial markets and interest rates;
asset impairments;
liquidity constraints, including those resulting from the cost and availability of debt and equity financing;
drilling and completion strategies, methods and results;
assumptions around well density/spacing and recoverable reserves per well prove to be inaccurate;
shortages of oilfield equipment, services and personnel;
lack of available pipeline, processing and refining capacity;
processing volumes and pipeline throughput;
our ability to successfully integrate acquired assets;
risks associated with hydraulic fracturing;
the outcome of contingencies such as legal proceedings;
delays in obtaining permits and governmental approvals;
operating risks such as unexpected drilling conditions and risks inherent in the production of oil and gas;
weather conditions;
changes in, adoption of and compliance with laws and regulations, including decisions and policies concerning: the environment, climate change, greenhouse gas or other emissions, natural resources, fish and wildlife, hydraulic

3



fracturing, water use and drilling and completion techniques, as well as the risk of legal proceedings arising from such matters, whether involving public or private claimants or regulatory investigative or enforcement measures;
derivative activities;
potential financial losses or earnings reductions from our commodity price risk management programs;
volatility in the commodity-futures market;
failure of internal controls and procedures;
failure of our information technology infrastructure or applications to prevent a cyberattack;
elimination of federal income tax deductions for oil and gas exploration and development costs;
production, severance and property taxation rates;
discount rates;
regulatory approvals and compliance with contractual obligations;
actions of, or inaction by federal, state, local or tribal governments, foreign countries and the Organization of Petroleum Exporting Countries;
lack of, or disruptions in, adequate and reliable transportation for our production;
competitive conditions;
production and sales volumes;
estimates of oil and gas reserve quantities;
reservoir performance;
operating costs;
inflation;
capital costs;
creditworthiness and performance of the Company's counterparties, including financial institutions, operating partners and other parties;
volatility in the securities, capital and credit markets;
actions by credit rating agencies and their impact on the Company; 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 Company's website to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.


4



Glossary of Terms

Adjusted EBITDA A non-GAAP financial measure which management defines as earnings before interest, income taxes, depreciation, depletion and amortization (EBITDA), adjusted to exclude changes in fair value of derivative contracts, exploration expenses, gains and losses from asset sales, impairment, and certain other items.

Argus WTI Midland An index price reflecting the weighted average price of WTI at the pipeline and storage hub at Midland, Texas.

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 swap A financial derivative that fixes the price difference between two sales points for a specified commodity volume over a specified time period.

Boe Barrels of oil equivalent.

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.

development well A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

dry hole An exploratory, development or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

exploratory well 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.

FERC The Federal Energy Regulatory Commission.

GAAP Accounting principles generally accepted in the United States of America.

gas All references to "gas" in this report refer to natural gas.

gross "Gross" oil and gas wells or "gross" acres are the total number of wells or acres in which the Company has an ownership interest.

ICE Brent Brent crude oil traded on the Intercontinental Exchange, Inc. (ICE).

IFNPCR Inside FERC's Gas Market Report monthly settlement index for the Northwest Pipeline Corporation Rocky Mountains.

M Thousand.

MM Million.


5



mineral interest The economic interest or ownership of minerals, giving the owner the right to a share of the minerals produced or proceeds from the sale of the minerals.

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 six Mcf 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" oil and gas wells or "net" acres are the sum of the fractional working interest the Company owns in the gross wells or acres. "Net" revenues are QEP Resources Inc.'s share of revenues from wells after deductions of royalties, overrides, net profits and other lease burdens.

NYMEX The New York Mercantile Exchange.

NYMEX HH The New York Mercantile Exchange price of natural gas at the Henry Hub.

NYMEX WTI The New York Mercantile Exchange price of West Texas Intermediate crude oil.

oil All references to "oil" in this report refer to crude oil.

oil equivalents Natural gas is converted to a crude oil equivalent at the ratio of six Mcf of natural gas to one barrel of crude oil equivalent.

possible reserves Those additional reserves that are less certain to be recovered than probable reserves.

probable reserves 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 developed reserves Reserves that are 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.

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 prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

proved undeveloped reserves or PUD Proved reserves that are expected to be recovered from new wells or from existing wells where a major expenditure is required for recompletion.

reserves Estimated remaining quantities of crude oil, natural gas and related substances anticipated to be economically producible as of a given date 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 or a revenue interest in the production.

reservoir An underground formation containing a natural accumulation of producible oil and/or gas 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 areal extent. Resource plays are characterized by continuous, aerially extensive hydrocarbon accumulations in tight sand, shale and coal reservoirs.

royalty An interest in an oil and gas 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, completing or operating the wells on the leased acreage. Royalties may be either landowner's royalties, which are

6



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.

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.

undeveloped reserves Reserves of any category that are expected to be recovered from new wells or from existing wells where a relatively major expenditure is required for recompletion.

working interest An interest in an oil and gas 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.



7



FORM 10-K
ANNUAL REPORT 2016
PART I
ITEMS 1 and 2. BUSINESS AND PROPERTIES

Nature of Business
 
QEP Resources, Inc. (QEP or the Company) is an independent crude oil and natural gas exploration and production company focused in two regions of the United States: the Northern Region (primarily in North Dakota, Wyoming and Utah) and the Southern Region (primarily in Texas and Louisiana). Unless otherwise specified or the context otherwise requires, all references to "QEP" or the "Company" are to QEP Resources, Inc. and its subsidiaries on a consolidated basis. QEP's corporate headquarters are located in Denver, Colorado and shares of QEP's common stock trade on the New York Stock Exchange (NYSE) under the ticker symbol "QEP".

Changes in Segment Reporting due to Discontinued Operations and Termination of Marketing Agreements

In December 2014 , the Company sold substantially all of its midstream business, including the Company's ownership interest in QEP Midstream Partners, LP (QEP Midstream), to Tesoro Logistics LP for total cash proceeds of approximately $2.5 billion, including $230.0 million to refinance debt at QEP Midstream, and QEP recorded a pre-tax gain of approximately $1.8 billion for the year ended December 31, 2014 (Midstream Sale). As a result of the Midstream Sale, the results of operations for the QEP Field Services Company (QEP Field Services) reporting segment, excluding the retained ownership of the Haynesville gathering system (Haynesville Gathering), were classified as discontinued operations on the Consolidated Statement of Operations and the Notes accompanying the Consolidated Financial Statements.

Effective January 1, 2016, QEP terminated its contracts for resale and marketing transactions between its wholly owned subsidiaries, QEP Marketing Company (QEP Marketing) and QEP Energy Company (QEP Energy). In addition, substantially all of QEP Marketing's third-party purchase and sale agreements and gathering, processing and transportation contracts were assigned to QEP Energy, except those contracts related to natural gas storage activities and Haynesville Gathering. As a result, QEP Energy is directly marketing its own oil, gas and NGL production. While QEP will continue to act as an agent for the sale of oil, gas and NGL production for other working interest owners, for whom QEP serves as the operator, QEP is no longer the first purchaser of this production. QEP has substantially reduced its marketing activities, and subsequently, is reporting lower resale revenue and expenses than it had prior to 2016.

In conjunction with the changes described above, QEP conducted a segment analysis in accordance with Accounting Standards Codification (ASC) Topic 280, Segment Reporting, and determined that QEP had one reportable segment effective January 1, 2016. The Company has recast its financial statements for historical periods to reflect the impact of the Midstream Sale and the termination of marketing agreements to show its financial results without segments. See Part II, Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations, in this Annual Report on Form 10-K for further discussion.

Financial and Operating Highlights

During the year ended December 31, 2016, QEP:

Reported record oil equivalent reserves of 731.4 MMboe as of December 31, 2016, a 21% increase over 2015;
Delivered record oil equivalent production of 55.8 MMboe, a 2% increase over 2015;
Increased oil production to 20.3 MMbbl, a 4% increase over 2015, including a 43% increase in the Permian Basin;
Reduced lease operating and transportation and other handling expense by $0.52 per Boe compared to the year ended December 31, 2015, to $9.21 per Boe;
Generated a net loss of $1,245.0 million, or $5.62 per diluted share;
Reported $626.2 million of Adjusted EBITDA (a non-GAAP measure defined and reconciled in Item 7 of Part II of this Annual Report on Form 10-K);
Incurred capital expenditures (excluding property acquisitions) of $530.1 million, a 48% reduction from 2015;
Incurred impairment expense of $1,194.3 million, primarily due to lower future commodity prices;
Issued 60.95 million shares of common stock through two public offerings and received net proceeds of approximately $781.4 million;
Acquired various oil and gas properties for approximately $645.2 million, of which approximately $590.6 million was related to the 2016 Permian Basin Acquisition (defined below), subject to customary purchase price adjustments; and

8



Maintained strong liquidity, including $443.8 million in cash and cash equivalents and no borrowings under its revolving credit facility as of December 31, 2016.

Strategies
 
We create value for our shareholders through returns-focused growth, superior execution and a low-cost structure. To achieve these objectives we strive to:

operate in a safe and environmentally responsible manner;
allocate capital to those projects that generate the highest returns;
increase oil production as a percentage of total production;
acquire businesses and assets that complement or expand our current business;
divest of non-core assets;
maintain an inventory of low-cost, high-margin development projects in resource plays;
develop 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;
actively market our production to maximize value;
utilize derivative contracts to reduce the impact of oil, gas and NGL price volatility;
attract and retain the best people; and
maintain a capital structure that provides sufficient financial flexibility to successfully operate and grow the business.

Overview

QEP conducts exploration and production (E&P) activities in several of North America's most important hydrocarbon resource plays. QEP has an inventory of developed and identified undeveloped drilling locations in the Permian Basin in western Texas, the Williston Basin in North Dakota, Haynesville/Cotton Valley in northwestern Louisiana, the Pinedale Anticline (Pinedale) in western Wyoming, the Uinta Basin in eastern Utah and other proven properties in Wyoming, Utah and Colorado.
 
While historically the Company has been more natural gas weighted, in recent years the Company has increased its focus on growing oil and NGL production. Since the beginning of 2012, the Company has made over $3.0 billion of acquisitions of oil-weighted properties and spent approximately 60% of its capital expenditures (excluding property acquisitions) on its oil-weighted properties. During 2016, QEP increased oil production by 4% compared to 2015, and oil and NGL production represented 47% of total production during the year ended December 31, 2016, compared to 45% during the year ended December 31, 2015, and 44% during the year ended December 31, 2014. Additionally, oil and NGL revenue represented approximately two-thirds of total field-level revenues during the three-year period ended December 31, 2016. Consistent with its emphasis on oil-weighted properties, QEP now reflects its production and reserve amounts in oil equivalent volumes rather than gas equivalent volumes.

In October 2016, QEP acquired oil and gas properties in the Permian Basin for an aggregate purchase price of approximately $590.6 million, subject to customary purchase price adjustments (the 2016 Permian Basin Acquisition). The 2016 Permian Basin Acquisition consists of approximately 9,600 net acres in Martin County, Texas, which are primarily held by production from existing vertical wells. The 2016 Permian Basin Acquisition was funded with proceeds from an equity offering in June 2016 and cash on hand.

9




The following map illustrates the location of the Company's significant E&P activities, the location of its Northern and Southern Regions, and related reserve and production data as of December 31, 2016:

a201610kirmapa01.jpg

QEP seeks to acquire, develop and produce oil and gas from resource plays in its core operating areas and expand into new areas where it can capitalize on its operating expertise. Since the existence and distribution of hydrocarbons in resource plays is now better understood, developing these accumulations generally has lower risk than developing conventional discrete hydrocarbon accumulations. Resource plays typically require drilling and completing many wells at high density to fully develop and recover the hydrocarbon accumulations. QEP's resource play development requires expertise in drilling and completing a large number of complex, highly deviated or horizontal wells and the application of advanced well completion techniques, including hydraulic fracture stimulation, to achieve economic production rates and recoverable volumes. QEP enters into contracts with various service companies to drill and complete its wells. QEP also conducts exploratory drilling to determine the commercial viability of its unproven leasehold inventory. QEP seeks to maintain geographical and geological diversity with its two regions. The Company may pursue additional acquisitions of producing properties through the purchase of assets or corporate entities in order to further expand its presence in its core areas of operations or to create new core areas. QEP may also divest non-core assets that it believes have limited growth opportunities or no longer fit into its corporate strategy.
 
QEP sells gas volumes to wholesale marketers, industrial users, local distribution companies and utilities. QEP sells oil and NGL volumes to refiners, marketers and other companies, including some with pipeline facilities near QEP's producing properties. QEP regularly evaluates counterparty credit risk and may require parental guarantees, letters of credit or prepayment from companies with perceived higher credit risk. In order to get its oil, gas and NGL volumes to their ultimate sale point, QEP has contracts with midstream providers for the gathering, processing and/or fractionation of these products. In addition, QEP

10



has firm transportation commitments with interstate pipelines to move its gas volumes to multiple destinations dependent upon market conditions. Disruptions with pipelines or midstream providers' processing facilities can impact QEP's production volumes. In cases were QEP's wells are not connected to sales pipelines, the Company will have its products trucked from the well location to ultimate sales point.

Description of Properties

Northern Region

Williston Basin
QEP owns 333.8 net productive wells in the Williston Basin that generate substantial cash flows, which help fund future development of the Company’s portfolio of assets. QEP has developed a majority of its acreage but continues its infill drilling program targeting the Bakken and Three Forks formations. As of December 31, 2016, QEP had one operated rig drilling in the Williston Basin.

Pinedale
QEP owns 685.0 net productive wells in Pinedale that generate substantial cash flows, which help fund future development of the Company’s portfolio of assets. QEP has developed a majority of its acreage but continues its development program, targeting the Lance Pool, which is a tight gas sand reservoir. As of December 31, 2016, QEP had one operated rig drilling in Pinedale. 

Uinta Basin
The majority of the Uinta Basin's proved reserves are found in a series of vertically stacked, laterally discontinuous reservoirs. The Company continues to evaluate how to best develop this field through horizontal and vertical development and has a large inventory of remaining future locations. As of December 31, 2016, QEP did not have any operated rigs drilling in the Uinta Basin.
 
Other Northern
The remainder of QEP's Northern Region leasehold interests and proved reserves are distributed over a number of fields and properties in various states.

Southern Region 

Permian Basin
QEP has multiple targeted formations within its acreage in the Permian Basin and is actively developing oil producing zones, primarily in the Spraberry formations. QEP continues to actively acquire acreage in the basin and in 2016, acquired approximately 26,500 additional net acres. QEP continues to test additional formations and evaluate the appropriate ultimate density of its development program. As of December 31, 2016, QEP had three operated rigs drilling in the Permian Basin.

Haynesville/Cotton Valley
QEP owns producing and undeveloped properties in Haynesville/Cotton Valley and additional lease rights that cover the overlying Hosston and Cotton Valley formations. Production is primarily dry gas and QEP has numerous future locations to fully develop its acreage. In addition, in 2016 the Company began a workover program that has provided positive production results on older, lower rate wells. As of December 31, 2016, QEP did not have any operated rigs drilling in the Haynesville/Cotton Valley area.
 
Other Southern
The remainder of QEP's Southern Region primarily consists of small royalty interests over a large number of properties.


11



Reserves
 
At December 31, 2016 and 2015, QEP's estimated proved reserves were approximately 731.4 MMboe and 603.4 MMboe, respectively, of which 97% and 96%, respectively, were Company operated. Proved developed reserves represented 49% and 58% of the Company's total proved reserves at December 31, 2016 and 2015, respectively, while the remaining reserves were classified as proved undeveloped. All reported reserves are located in the United States. QEP 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's estimated proved reserves are summarized in the table below:
 
December 31, 2016
 
December 31, 2015
 
Oil
 
Gas
 
NGL
 
Total(1)
 
Oil
 
Gas (1)
 
NGL
 
Total(1)
 
(MMbbl)
 
(Bcf)
 
(MMbbl)
 
(MMboe)(2)
 
(MMbbl)
 
(Bcf)
 
(MMbbl)
 
(MMboe)(2)
Proved developed reserves
103.2

 
1,309.8

 
35.7

 
357.2

 
109.7

 
1,245.3

 
34.4

 
351.6

Proved undeveloped reserves
135.4

 
1,244.0

 
31.5

 
374.2

 
83.4

 
863.6

 
24.4

 
251.8

Total proved reserves
238.6

 
2,553.8

 
67.2

 
731.4

 
193.1

 
2,108.9

 
58.8

 
603.4

 ____________________________
(1) 
Proved reserves include gas reserves that QEP expects to produce and use as field fuel.
(2) 
Natural gas is converted to a crude oil equivalent at the ratio of six Mcf of natural gas to one barrel of crude oil equivalent.

QEP's reserve, production and production life index for each of the years ended December 31, 2014, through December 31, 2016, are summarized in the table below:
Year Ended December 31,
 
Year End Reserves
(MMboe)
 
Oil, Gas and NGL Production
(MMboe)
 
Reserve Life Index(1)
(Years)
2014
 
655.3
 
53.8
 
12.2
2015
 
603.4
 
54.5
 
11.1
2016
 
731.4
 
55.8
 
13.1
 ____________________________
(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 permit 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) 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 15 – Supplemental Oil and Gas Information (unaudited), in Item 8 of Part II of this Annual Report on Form 10-K for additional information regarding estimates of proved reserves and the preparation of such estimates.
 

12



QEP's proved reserves in major operating areas are summarized in the table below:
 
December 31,
 
2016
 
2015
Northern Region
(MMboe)
 
(% of total)
 
(MMboe)
 
(% of total)
Williston Basin
160.2

 
22
%
 
181.0

 
30
%
Pinedale
160.7

 
22
%
 
187.5

 
31
%
Uinta Basin
106.1

 
14
%
 
93.1

 
16
%
Other Northern
12.3

 
2
%
 
12.4

 
2
%
Southern Region
 
 
 
 
 
 
 
Permian Basin
147.8

 
20
%
 
62.4

 
10
%
Haynesville/Cotton Valley
144.3

 
20
%
 
66.1

 
11
%
Other Southern

 
%
 
0.9

 
%
Total proved reserves
731.4

 
100
%
 
603.4

 
100
%
 
Estimates of the quantity of proved reserves increased during 2016, primarily due to the 2016 Permian Basin Acquisition and the results of successful workovers in Haynesville/Cotton Valley.

Proved Undeveloped Reserves
Significant changes to PUD reserves that occurred during 2016 are summarized in the table below:
 
2016
 
(MMboe)
Proved undeveloped reserves at January 1,
251.8

Transferred to proved developed reserves
(45.5
)
Revisions to previous estimates(1)
47.3

Extensions and discoveries(2)
40.5

Purchase of reserves in place(3)
80.1

Proved undeveloped reserves at December 31,
374.2

 ____________________________
(1) 
Revisions of previous estimates include 51.1 MMboe of positive revisions, primarily related to reserves associated with increased density wells in areas that have been previously developed on lower density spacing and 3.4 MMboe of positive performance revisions. These positive revisions were partially offset by 3.8 MMboe of negative revisions related to pricing, driven by lower oil, gas and NGL prices.
(2) 
Extensions and discoveries in 2016 were primarily in the Permian and Uinta basins and related to new well completions and associated new PUD locations.
(3) 
Purchase of reserves in place in 2016 was primarily related to the 2016 Permian Basin Acquisition as discussed in Note 2 – Acquisitions and Divestitures, in Item 8 of Part II of this Annual Report on Form 10-K.

The costs incurred to continue the development of PUD reserves were approximately $258.1 million, $490.4 million and $792.9 million for the years ended December 31, 2016, 2015 and 2014, respectively. The costs incurred to continue the development of PUD reserves in 2016 were reduced from historical levels in conjunction with our efforts to reduce drilling and completion activities in 2016 as a result of the commodity price environment. QEP transferred 45.5 MMboe of PUD reserves to proved developed reserves in 2016, some of which was a result of installing additional compression at Pinedale. QEP's PUD to proved developed reserves conversion rate was 18%, 23% and 19% for the years ended December 31, 2016, 2015 and 2014, respectively.
 
All of QEP's proved undeveloped reserves at December 31, 2016, are scheduled to be developed within five years from the date such locations were initially disclosed as proved undeveloped reserves. QEP estimates that its future development costs relating to the development of PUD reserves are approximately $503.0 million in 2017, $717.3 million in 2018, and $781.3 million in 2019. Estimated future development costs include capital spending on major development projects, some of which will take several years to complete. QEP believes cash flow from operations, cash on hand and, if needed, availability under its revolving credit facility will be sufficient to cover these estimated future development costs. PUD reserves related to major development projects will be reclassified to proved developed reserves when production commences.

13




Internal Controls Over Proved Reserve Estimates, Technical Qualifications and Technologies Used
Estimates of proved oil and gas reserves have been completed in accordance with professional engineering standards and the Company's established internal controls, which includes the oversight of a multi-functional reserves review committee reporting to the Company's Audit Committee of the Board of Directors. The Company retained Ryder Scott Company, L.P. (RSC), independent oil and gas reserve evaluation engineering consultants, to prepare the estimates of all of its proved reserves as of December 31, 2016, and retained RSC and DeGolyer and MacNaughton (D&M) to prepare the estimates of all of its proved reserves as of December 31, 2015 and 2014. RSC prepared approximately 90% and D&M prepared approximately 10% of the Company's total net proved reserves as of December 31, 2015. RSC prepared approximately 91% and D&M prepared approximately 9% of the Company's total net proved reserves as of December 31, 2014.

The individual at RSC who was responsible for overseeing the preparation of QEP's reserve estimates as of December 31, 2016, 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 31 years of experience in the petroleum industry, including experience estimating and evaluating petroleum reserves. A more detailed letter, including such individual's professional qualifications, has been filed as part of Exhibit 99.1 to this report.

The individual at QEP responsible for ensuring the accuracy of the reserve estimate preparation material provided to RSC and reviewing the estimates of reserves received from RSC is QEP's Corporate Reserves Manager. This individual is a member of the Society of Petroleum Engineers and graduated with a Bachelors of Science degree in Engineering from the University of Minnesota. This individual has over 29 years of experience in the petroleum industry, including 14 years of experience in corporate reserves management.

To estimate proved 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 QEP's proved reserve estimates. The principal methodologies employed are performance, analogy and volumetric methods.

All of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods. Volumetric measures are then used, when available, to further corroborate these reserves estimates. Performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of historical production data available through late 2016, in those cases where such data were considered to be definitive. For wells currently producing, 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.

In 2016, all of QEP's proved developed non-producing and undeveloped reserves included in this Annual Report on Form 10-K were estimated by analogy to offset producing wells. 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 in 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, 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 15 – Supplemental Oil and Gas 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's proved reserves as of the end of each of the last three years.

In addition to this filing, QEP will file reserve estimates as of December 31, 2016, with the Energy Information Administration of the Department of Energy (EIA) on Form EIA-23. Although QEP uses the same technical and economic assumptions when it prepares the Form EIA-23 as used to estimate reserves for this Annual Report on Form 10-K, it is obligated to report to the EIA

14



reserves only for 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.

Production, Prices and Production Costs

The following table sets forth the production volumes and field-level prices of oil, gas and NGL produced, and the related production costs, for the years ended December 31, 2016, 2015 and 2014:
 
 
Year Ended December 31,
 
 
2016
 
2015
 
2014
Production volumes
 
 
 
 
 
 
Oil (Mbbl)
 
20,293.8

 
19,582.3

 
17,146.5

Gas (Bcf)
 
177.0

 
181.1

 
179.3

NGL (Mbbl)
 
5,978.8

 
4,704.3

 
6,769.1

Total equivalent production (Mboe)
 
55,780.2

 
54,462.1

 
53,778.9

Total equivalent production (Bcfe)
 
334.7

 
326.8

 
322.7

Average field-level price (1)
 
 

 
 
 
 
Oil (per bbl)
 
$
37.90

 
$
42.59

 
$
79.79

Gas (per Mcf)
 
$
2.36

 
$
2.59

 
$
4.33

NGL (per bbl)
 
$
13.97

 
$
16.98

 
$
32.95

Production costs (per Boe)
 
 

 
 
 
 
Lease operating expense
 
$
4.03

 
$
4.38

 
$
4.46

Oil, gas and NGL transportation and other handling costs
 
5.18

 
5.35

 
5.16

Production and property taxes
 
1.70

 
2.16

 
3.82

Total production costs
 
$
10.91

 
$
11.89

 
$
13.44

 ____________________________
(1) 
The average field-level price does not include the impact of settled commodity price derivatives.

A summary of oil production by major geographical area is shown in the following table:
 
 
Year Ended December 31,
 
Change
 
 
2016
 
2015
 
2014
 
2016 vs 2015
 
2015 vs 2014
Oil production volumes (Mbbl)
 
 
 
 
 
 
 
 
 
 
Northern Region
 
 
 
 
 
 
 
 
 
 
Williston Basin
 
14,658.6

 
14,871.8

 
13,130.9

 
(213.2
)
 
1,740.9

Pinedale
 
670.9

 
716.6

 
632.0

 
(45.7
)
 
84.6

Uinta Basin
 
774.2

 
848.6

 
893.3

 
(74.4
)
 
(44.7
)
Other Northern
 
141.9

 
186.5

 
200.9

 
(44.6
)
 
(14.4
)
Southern Region
 
 
 
 
 
 

 
 
 
 
Permian Basin
 
3,983.9

 
2,791.2

 
1,582.2

 
1,192.7

 
1,209.0

Haynesville/Cotton Valley
 
28.4

 
33.6

 
35.3

 
(5.2
)
 
(1.7
)
Other Southern
 
35.9

 
134.0

 
671.9

 
(98.1
)
 
(537.9
)
Total production
 
20,293.8

 
19,582.3

 
17,146.5

 
711.5

 
2,435.8



15




A summary of gas production by major geographical area is shown in the following table:
 
 
Year Ended December 31,
 
Change
 
 
2016
 
2015
 
2014
 
2016 vs 2015
 
2015 vs 2014
Gas production volumes (Bcf)
 
 
 
 
 
 
 
 
 
 
Northern Region
 
 
 
 
 
 
 
 
 
 
Williston Basin
 
15.2

 
11.3

 
6.6

 
3.9

 
4.7

Pinedale
 
82.4

 
87.5

 
75.0

 
(5.1
)
 
12.5

Uinta Basin
 
22.4

 
22.7

 
17.9

 
(0.3
)
 
4.8

Other Northern
 
7.9

 
9.4

 
9.3

 
(1.5
)
 
0.1

Southern Region
 
 
 
 
 
 

 
 
 
 
Permian Basin
 
5.3

 
4.4

 
3.2

 
0.9

 
1.2

Haynesville/Cotton Valley
 
43.4

 
43.2

 
49.5

 
0.2

 
(6.3
)
Other Southern
 
0.4

 
2.6

 
17.8

 
(2.2
)
 
(15.2
)
Total production
 
177.0

 
181.1

 
179.3

 
(4.1
)
 
1.8

 
A summary of NGL production by major geographical area is shown in the following table:
 
 
Year Ended December 31,
 
Change
 
 
2016
 
2015
 
2014
 
2016 vs 2015
 
2015 vs 2014
NGL production volumes (Mbbl)
 
 
 
 
 
 
 
 
 
 
Northern Region
 
 
 
 
 
 
 
 
 
 
Williston Basin
 
3,182.7

 
1,953.4

 
1,010.5

 
1,229.3

 
942.9

Pinedale
 
1,417.1

 
1,528.6

 
3,350.2

 
(111.5
)
 
(1,821.6
)
Uinta Basin
 
203.9

 
287.6

 
679.0

 
(83.7
)
 
(391.4
)
Other Northern
 
22.3

 
19.6

 
14.9

 
2.7

 
4.7

Southern Region
 
 
 
 
 
 

 
 
 
 
Permian Basin
 
1,109.9

 
815.4

 
511.0

 
294.5

 
304.4

Haynesville/Cotton Valley
 
28.2

 
28.6

 
37.3

 
(0.4
)
 
(8.7
)
Other Southern
 
14.7

 
71.1

 
1,166.2

 
(56.4
)
 
(1,095.1
)
Total production
 
5,978.8

 
4,704.3

 
6,769.1

 
1,274.5

 
(2,064.8
)
 
A summary of oil equivalent total production by major geographical area is shown in the following table:
 
 
Year Ended December 31,
 
Change
 
 
2016
 
2015
 
2014
 
2016 vs 2015
 
2015 vs 2014
Total production volumes (Mboe)
 
 
 
 
 
 
 
 
 
 
Northern Region
 
 
 
 
 
 
 
 
 
 
Williston Basin
 
20,370.0

 
18,709.6

 
15,238.2

 
1,660.4

 
3,471.4

Pinedale
 
15,826.0

 
16,829.6

 
16,479.5

 
(1,003.6
)
 
350.1

Uinta Basin
 
4,714.3

 
4,924.0

 
4,547.1

 
(209.7
)
 
376.9

Other Northern
 
1,491.7

 
1,764.1

 
1,763.5

 
(272.4
)
 
0.6

Southern Region
 
 
 
 
 
 
 
 
 
 
Permian Basin
 
5,976.7

 
4,332.5

 
2,629.2

 
1,644.2

 
1,703.3

Haynesville/Cotton Valley
 
7,285.5

 
7,268.0

 
8,315.0

 
17.5

 
(1,047.0
)
Other Southern
 
116.0

 
634.3

 
4,806.4

 
(518.3
)
 
(4,172.1
)
Total production
 
55,780.2

 
54,462.1

 
53,778.9

 
1,318.1

 
683.2

 

16



A regional comparison of average field-level prices and average production costs per Boe is shown in the following table:
 
Year Ended December 31,
 
Change
 
2016
 
2015
 
2014
 
2016 vs 2015
 
2015 vs 2014
Average field-level oil price (per bbl)
 
 
 
 
 
 
 

 
 

Northern Region
$
36.97

 
$
41.78

 
$
78.87

 
$
(4.81
)
 
$
(37.09
)
Southern Region
$
41.68

 
$
47.16

 
$
85.76

 
$
(5.48
)
 
$
(38.60
)
Average field-level oil price
$
37.90

 
$
42.59

 
$
79.79

 
$
(4.69
)
 
$
(37.20
)
Average field-level gas price (per Mcf)
 
 
 
 
 
 
 
 
 
Northern Region
$
2.33

 
$
2.58

 
$
4.26

 
$
(0.25
)
 
$
(1.68
)
Southern Region
$
2.42

 
$
2.60

 
$
4.44

 
$
(0.18
)
 
$
(1.84
)
Average field-level gas price
$
2.36

 
$
2.59

 
$
4.33

 
$
(0.23
)
 
$
(1.74
)
Average field-level NGL price (per bbl)
 
 
 
 
 
 
 

 
 

Northern Region
$
14.50

 
$
18.06

 
$
33.22

 
$
(3.56
)
 
$
(15.16
)
Southern Region
$
11.75

 
$
12.49

 
$
32.15

 
$
(0.74
)
 
$
(19.66
)
Average field-level NGL price
$
13.97

 
$
16.98

 
$
32.95

 
$
(3.01
)
 
$
(15.97
)
 
 
 
 
 
 
 
 
 
 
Lease operating and transportation and other handling costs (per Boe)
Northern Region
$
8.71

 
$
8.67

 
$
9.08

 
$
0.04

 
$
(0.41
)
Southern Region
$
10.79

 
$
13.41

 
$
10.94

 
$
(2.62
)
 
$
2.47

Average lease operating and transportation and other handling costs
$
9.21

 
$
9.73

 
$
9.62

 
$
(0.52
)
 
$
0.11


Northern Region

Williston Basin
Production increased 9% to 20,370.0 Mboe during 2016 compared to 2015, due to increased gas and NGL production, which was primarily attributable to additional ethane recovered combined with higher gas recovery from a midstream provider in 2016. These increases were partially offset by a decrease in oil production volumes due to fewer net well completions in 2016 compared to 2015.

During 2015, production increased 23% to 18,709.6 Mboe, compared to 2014, due to increased oil, gas and NGL production. The increase in production volumes was primarily attributable to continued development drilling and completion activity.

During the years ended December 31, 2016, 2015 and 2014, Williston Basin production represented 37%, 34%, and 29%, respectively, of QEP's total production.

Pinedale
Production decreased 6% to 15,826.0 Mboe during 2016 compared to 2015. Despite improved results from wells drilled and completed in 2016, production volumes decreased primarily as a result of fewer net well completions due to a decreased rig count in Pinedale in 2016 compared to 2015.

Production from Pinedale increased 2% to 16,829.6 Mboe during 2015 compared to 2014. This increase in production volumes was primarily a result of increased gas production due to continued net well completions in 2014 and 2015 and better performing well completions from the new wells drilled in 2015. This increase was mostly offset by a decrease in NGL production due to operating in ethane rejection throughout the majority of 2015 compared to ethane recovery in 2014.

During the year ended December 31, 2016, Pinedale's production represented 28% of QEP's total production, compared to 31% for the years ended December 31, 2015 and 2014, respectively.

Uinta Basin
Production volumes decreased 4% to 4,714.3 Mboe during 2016 compared to 2015, primarily attributable to decreased gas production from decreased net well completions in 2016 compared to 2015. QEP did not have an operated rig in the Uinta Basin for the majority of 2016.

17




Production volumes increased 8% to 4,924.0 Mboe during 2015 compared to 2014, primarily due to increased gas production due to new Lower Mesaverde well completions in 2015, partially offset by a decrease in NGL production due to operating in ethane rejection throughout the majority of 2015 compared to ethane recovery in 2014.

During the years ended December 31, 2016, 2015 and 2014, Uinta Basin production represented 8%, 9%, and 8%, respectively, of QEP's total production.

Other Northern
Production volumes decreased 15% to 1,491.7 Mboe during 2016 compared to 2015, primarily due to a decrease in gas production on Wyoming properties.

During 2015, production remained flat compared to 2014, due to a slight increase in gas production, primarily from 4.0 net well completions, offset by a slight decrease in oil production.

For each of the three years ended December 31, 2016, 2015 and 2014, Other Northern production represented 3% of QEP's total production.

Southern Region

Permian Basin
Production volumes increased 38% to 5,976.7 Mboe during 2016 compared to 2015, primarily attributable to continued horizontal development drilling, primarily in the Spraberry Shale, despite fewer net well completions in 2016 compared to 2015.

Production from the Permian Basin increased 65% to 4,332.5 Mboe during 2015 compared to 2014, due to increased horizontal well development combined with a full year of production in 2015 related to the 2014 Permian Basin Acquisition compared to 10 months of production in 2014 (see Note 2 – Acquisitions and Divestitures, in Item 8 of Part II of this Annual Report on Form 10-K).

During the years ended December 31, 2016, 2015 and 2014, Permian Basin production represented 11%, 9%, and 5% respectively, of QEP's total production.

Haynesville/Cotton Valley
Production slightly increased during 2016 compared to 2015, due to well workovers and increased non-operated production, partially offset by a natural decline and the continued suspension of QEP's operated drilling program.

During 2015, production volumes decreased 13% to 7,268.0 Mboe compared to 2014, due to natural decline and the continued suspension of QEP's operated drilling program, partially offset by 3.2 net non-operated well completions in 2015.

During the years ended December 31, 2016 and 2015, Haynesville/Cotton Valley's production represented 13% of QEP's total production, compared to 15% for the year ended December 31, 2014.

Other Southern
Production volumes decreased 82% to 116.0 Mboe during 2016 compared to 2015, due to the continued divestitures of non-core properties.

During 2015, production decreased 87% to 634.3 Mboe compared to 2014, due to the continued divestitures of non-core properties.

During the years ended December 31, 2015 and 2014, Other Southern production represented 1%, and 9% of QEP's total production, respectively.


18



Productive Wells
The following table summarizes the Company's operated and non-operated productive wells as of December 31, 2016, all of which are located in the U.S.:
 
 
Oil
 
Gas
 
Total
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Northern Region
 
 
 
 
 
 
 
 
 
 
 
 
Williston Basin
 
844

 
333.8

 

 

 
844

 
333.8

Pinedale(1)
 

 

 
1,113

 
685.0

 
1,113

 
685.0

Uinta Basin
 
1,548

 
195.0

 
707

 
522.0

 
2,255

 
717.0

Other Northern
 
43

 
17.4

 
473

 
206.0

 
516

 
223.4

Southern Region
 
 
 
 
 
 
 
 
 
 
 
 
Permian Basin
 
484

 
458.3

 

 

 
484

 
458.3

Haynesville/Cotton Valley
 
1

 
0.1

 
839

 
443.0

 
840

 
443.1

Other Southern
 
1

 

 
58

 
4.0

 
59

 
4.0

Total productive wells
 
2,921

 
1,004.6

 
3,190

 
1,860.0

 
6,111

 
2,864.6

 ____________________________
(1) 
Gross productive wells includes 69 wells in which QEP only owns a small overriding royalty interest.

Although many wells produce both oil and gas, and many gas wells also have allocated NGL volumes from gas processing, a well is categorized as either an oil well or a gas well based upon the ratio of oil to gas produced at the wellhead. Additionally, each well completed in more than one producing zone is counted as a single well.

The Company also holds numerous overriding royalty interests in oil and gas wells, a portion of which is convertible to working interests after recovery of certain costs by third parties. Once the overriding royalty interests are converted to working interests, these wells are included in the Company's gross and net well count.
 
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, 2016. "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)
 
Undeveloped Acres (2)
 
Total Acres
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Colorado
 
170,582

 
114,316

 
79,117

 
17,774

 
249,699

 
132,090

Kansas
 
46,433

 
20,912

 
35,419

 
12,765

 
81,852

 
33,677

Louisiana
 
69,740

 
61,915

 
1,384

 
1,531

 
71,124

 
63,446

Montana
 
38,377

 
15,887

 
331,925

 
58,397

 
370,302

 
74,284

New Mexico
 
7,740

 
4,266

 
28,611

 
5,644

 
36,351

 
9,910

North Dakota
 
207,596

 
69,461

 
167,190

 
54,409

 
374,786

 
123,870

South Dakota
 
40

 
40

 
203,330

 
107,551

 
203,370

 
107,591

Texas
 
41,060

 
31,799

 
91,865

 
46,855

 
132,925

 
78,654

Utah
 
203,183

 
156,483

 
194,205

 
117,321

 
397,388

 
273,804

Wyoming
 
245,317

 
152,962

 
160,045

 
99,906

 
405,362

 
252,868

Other
 
15,715

 
4,547

 
157,821

 
43,517

 
173,536

 
48,064

Total
 
1,045,783

 
632,588

 
1,450,912

 
565,670

 
2,496,695

 
1,198,258

 ____________________________
(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 oil and gas regardless of whether such acreage contains proved reserves.

19




Expiring Leaseholds
A portion of the leases covering the acreage 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: 
 
 
Undeveloped Acres Expiring
 
 
Gross
 
Net
Year ending December 31,
 
 
 
 
2017
 
59,175

 
39,885

2018
 
45,211

 
22,155

2019
 
10,371

 
8,466

2020
 
8,950

 
8,287

2021 and later
 
7,446

 
7,289

Total
 
131,153

 
86,082



20



Drilling Activity
The following table summarizes the total number of developmental and exploratory wells drilled (defined to include the number of wells completed at any time during the applicable year, regardless of when drilling was initiated), including both operated and non-operated wells, during the years indicated.
 
 
Developmental Wells
 
Exploratory Wells
 
 
Productive
 
Dry
 
Productive
 
Dry
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Year Ended December 31, 2016
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Northern Region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Williston Basin
 
70

 
39.5

 

 

 

 

 

 

Pinedale
 
44

 
24.4

 

 

 

 

 

 

Uinta Basin
 
11

 
8.0

 

 

 

 

 

 

Other Northern
 
3

 
3.0

 

 

 

 

 

 

Southern Region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Permian Basin
 
19

 
18.8

 

 

 
1

 
0.7

 

 

Haynesville/Cotton Valley
 
15

 
2.6

 

 

 

 

 

 

Other Southern
 

 

 

 

 

 

 

 

Total
 
162

 
96.3

 

 

 
1

 
0.7

 

 

Year Ended December 31, 2015
 
 
 
 

 
 

 
 

 
 

 
 

 
 

 
 

Northern Region
 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Williston Basin
 
154

 
59.7

 

 

 

 

 

 

Pinedale
 
107

 
68.1

 

 

 

 

 

 

Uinta Basin
 
30

 
11.2

 

 

 

 

 

 

Other Northern
 
3

 
3.0

 

 

 
1

 
1.0

 

 

Southern Region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Permian Basin
 
38

 
32.5

 

 

 

 

 

 

Haynesville/Cotton Valley
 
24

 
3.2

 

 

 

 

 

 

Other Southern
 
4

 
0.1

 

 

 

 

 

 

Total
 
360

 
177.8

 

 

 
1

 
1.0

 

 

Year Ended December 31, 2014
 
 
 
 

 
 

 
 

 
 

 
 

 
 

 
 

Northern Region
 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Williston Basin
 
199

 
80.6

 

 

 

 

 

 

Pinedale
 
116

 
82.4

 

 

 

 

 

 

Uinta Basin
 
196

 
6.5

 

 

 

 

 

 

Other Northern
 
3

 
3.0

 

 

 
1

 
1.0

 

 

Southern Region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Permian Basin
 
71

 
63.2

 

 

 

 

 

 

Haynesville/Cotton Valley
 
40

 
3.2

 
1.0

 
0.3

 

 

 

 

Other Southern
 
32

 
2.3

 

 

 

 

 

 

Total
 
657

 
241.2

 
1.0

 
0.3

 
1

 
1.0

 

 




21



The following table presents operated and non-operated well completions for the year ended December 31, 2016:
 
Operated Completions
 
Non-operated Completions
 
Gross
 
Net
 
Gross
 
Net
Northern Region
 
 
 
 
 
 
 
Williston Basin
41

 
37.5

 
29

 
2.0

Pinedale
44

 
24.4

 

 

Uinta Basin
8

 
8.0

 
3

 
0.0

Other Northern
3

 
3.0

 

 

 
 
 
 
 
 
 
 
Southern Region
 

 
 

 
 

 
 

Permian Basin
20

 
19.5

 

 

Haynesville/Cotton Valley

 

 
15

 
2.6

Other Southern

 

 

 


The following table presents operated and non-operated wells drilling and waiting on completion at December 31, 2016:
 
Operated
 
Non-operated
 
Drilling
 
Waiting on completion
 
Drilling
 
Waiting on completion
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Northern Region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Williston Basin
3

 
3.0

 
15

 
12.8

 

 

 
14

 
0.4

Pinedale
6

 
2.4

 
8

 
4.5

 

 

 

 

Uinta Basin

 

 

 

 

 

 

 

Other Northern

 

 

 

 

 

 

 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Southern Region
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Permian Basin
3

 
3.0

 
13

 
13.0

 

 

 

 

Haynesville/Cotton Valley

 

 

 

 
3

 
0.5

 
9

 
0.9

Other Southern

 

 

 

 

 

 

 


QEP typically utilizes multi-well pad drilling where practical. Wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location. QEP sometimes suspends completion activities due to adverse weather conditions, operational factors or other macroeconomic circumstances, such as low commodity prices. QEP had 36 gross operated wells waiting on completion as of December 31, 2016.

Delivery Commitments

QEP is a party to various long-term sales commitments for physical delivery of oil and gas with future firm delivery commitments as follows:

 
Delivery Commitments
Period
(MMboe)
2017
17.3

2018
1.3

2019

Thereafter

 
These commitments are physical delivery obligations with prices based on prevailing index prices for oil and gas at the time of delivery. None of these commitments requires the Company to deliver oil or gas produced specifically from any of the

22



Company's properties. The Company believes that its production and reserves should be adequate to meet these term sales commitments. If the Company's oil or gas production is not sufficient to satisfy its firm delivery commitments, the Company believes it can purchase sufficient volumes of oil or gas in the market at index-related prices to satisfy its commitments. See also Part II, Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations – Contractual Cash Obligations and Other Commitments, in this Annual Report on Form 10-K for discussion of firm transportation and storage commitments related to oil and gas deliveries.

In addition, at December 31, 2016, the Company did not have a significant amount of production from QEP's owned properties that was subject to priorities, proration or third-party imposed curtailments that may affect quantities delivered to its customers, 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 Part I, Item 1A – Risk Factors, in this Annual Report on Form 10-K.

Seasonality

QEP drills and completes wells throughout the year, but adverse weather conditions can impact drilling, completion and field operations, which can impact overall production rates. Seasonal anomalies can minimize or exaggerate the impact on these operations, while extreme weather events can materially constrain our operations for a short period of time. In the Pinedale field, QEP typically ceases completion activities of newly drilled wells in the fourth quarter due to adverse weather conditions and resumes completion activity in the first quarter as weather allows. In the Williston Basin, QEP drills and completes wells throughout the year, but adverse weather conditions can impact drilling, completion and production operations.

Significant Customers

QEP's five largest customers accounted for 48%, 30%, and 33%, in the aggregate, of QEP's revenues for the years ended December 31, 2016, 2015 and 2014, respectively. During the year ended December 31, 2016, Shell Trading Company, BP Energy Company and Valero Marketing & Supply Company accounted for 14%, 10% and 10%, respectively, of QEP's total revenues. During the year ended December 31, 2015, no customer accounted for 10% or more of QEP's total revenues. During the year ended December 31, 2014, Valero Marketing & Supply Company accounted for 10% of QEP's total revenues. Management believes that the loss of any of these customers, 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.

Competition

QEP faces competition in every facet of its business, including the acquisition of producing leaseholds, wells and undeveloped leaseholds, the marketing of oil, gas and NGL products and the procurement of goods, services and labor. The Company’s competitors include national oil companies, major integrated oil and gas companies, independent oil and gas companies, individual producers, gas marketers and major pipeline companies, as well as participants in other industries supplying energy, fuel and services to consumers.

Employees
 
At December 31, 2016, QEP had 656 employees compared to 693 employees at December 31, 2015. None of QEP's employees are represented by unions or covered by collective bargaining agreements.


23



Executive Officers of the Registrant

The name, age, period of service, title and business experience of each of QEP's executive officers as of January 31, 2017, are listed below:
Charles B. Stanley
 
58
 
Chairman (2012 to present). President and Chief Executive Officer (2010 to present). Previous titles with Questar Corporation: 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).
Richard J. Doleshek
 
58
 
Executive Vice President and Chief Financial Officer (2010 to present). Treasurer (2010 to 2014). Chief Accounting Officer (2013 to 2014). Previous titles with Questar Corporation: Executive Vice President and Chief Financial Officer (2009 to 2010). Prior to joining Questar, Mr. Doleshek was Executive Vice President and Chief Financial Officer at Hilcorp Energy Company (2001 to 2009).
Jim E. Torgerson
 
53
 
Executive Vice President, QEP Energy (2013 to Present). Senior Vice President - Operations (2012 to 2013). Senior Vice President, Drilling and Completions (2011 to 2012). Previous titles with Questar Corporation: Vice President, Drilling and Completions (2009 to 2010); Vice President, Rockies Drilling and Completions (2005 to 2008).
Christopher K. Woosley
 
47
 
Vice President, General Counsel and Corporate Secretary (January 2016 to present). Vice President and General Counsel (2012 to 2016). 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).
Margo D. Fiala
 
53
 
Vice President, Human Resources (2010 to present). Prior to joining QEP, Ms. Fiala held a variety of roles at Suncor Energy (1995 to 2010), including Director of Human Resources.
Matthew T. Thompson
 
44
 
Vice President, Energy (2015 to present). Vice President - Northern Region (2013 to 2015). General Manager - High Plains Division (2012 to 2013). General Manager - Legacy Division (2011 to 2012). Reservoir Engineer Manager (2010 to 2011). Previous Titles with Questar Corporation: Manager - Business Development (2009 to 2010); Director of Planning (2006 to 2009).
Alice B. Ley
 
43
 
Vice President, Controller and Chief Accounting Officer (2014 to present). Interim Controller (2013-2014). Director of Financial Reporting (2012 to 2013). Prior to joining QEP, Ms. Ley was an Accounting/Financial Analyst Manager at Frontier Oil Corporation (2001 to 2011) and an Audit Manager in the Energy Division of Arthur Anderson, LLP (1996 to 2001).

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 any of the officers were selected.

Government Regulation

QEP's business operations are subject to a wide range of local, state, tribal and federal statutes, rules, orders and regulations. The regulatory environment in which the oil and gas industry operates increases the cost of doing business and consequently affects profitability. QEP believes that it is in compliance, in all material respects, with currently applicable laws and regulations. Due to the myriad of complex federal, state, tribal and local regulations that may directly or indirectly affect QEP, 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 Part I, Item 1A – Risk Factors, in this Annual Report on Form 10-K.

Regulation of Exploration and Production Activities

The regulation of oil and gas exploration and production activities is a broad and increasingly complex area, notably including laws and regulations governing the potential discharge or release of materials into the environment or otherwise relating to environmental protection. These laws and regulations include, but are not limited to, the following:

Clean Air Act. The federal Clean Air Act and similar state laws regulate the emission of air pollutants from equipment and facilities employed by QEP in its business, including, but not limited to, engines, tanks and dehydrators. In 2016, the Environmental Protection Agency (EPA) adopted various regulations specific to oil and gas exploration, production, gathering

24



and processing, which impose air quality controls and work practices, and govern source determination and permitting requirements, and methane emissions. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. Additionally, many states are adopting air permitting and other air quality control regulations specific to oil and gas exploration, production, gathering and processing that are more stringent than existing requirements under federal regulations.

Greenhouse Gas Regulations and Climate Change Legislation. In recent years, the EPA has adopted and substantially expanded regulations for the measurement and annual reporting of carbon dioxide, methane and other greenhouse gases (GHG) emitted from certain large facilities, including onshore oil and gas production, processing, transmission, storage and distribution facilities. In addition, both houses of Congress have considered legislation to reduce emissions of GHG, and a number of states have taken, or are considering taking, legal measures to reduce emissions of GHG, primarily through the development of GHG inventories, GHG permitting and/or state or regional GHG cap and trade programs.

Bureau of Land Management Methane Regulations. In November 2016, the Department of the Interior's Bureau of Land Management (BLM) finalized a rule regulating the venting and flaring of natural gas, leak detection, air emissions from equipment, well maintenance and unloading, drilling and completions and royalties potentially owed for loss of such emissions from oil and gas facilities producing on federal and tribal leases. The final rule became effective in January 2017 and is the subject of pending litigation filed by oil and gas trade associations and certain states seeking to modify or overturn the rule.

Other BLM Regulations. In November 2016, the BLM finalized regulations that update and replace Onshore Orders No. 3 (Site Security), No. 4 (Measurement of Oil) and No. 5 (Measurement of Gas). These regulations increase compliance burdens on federal lessees and operators like QEP by requiring them to obtain numbers for all onshore points of federal royalty measurement from the BLM, adjusting recordkeeping requirements, and imposing new oil and gas measurement equipment standards, among other requirements, for production from federal and Indian leases. These regulations took effect in January 2017, although the BLM has delayed one piece of the regulation and is assessing whether to extend other compliance deadlines as well.

Clean Water Act and Safe Drinking Water Act. The federal Clean Water Act and similar state laws regulate discharges of wastewater, oil, fill material and pollutants into waters of the United States. 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 federal Safe Drinking Water Act (SDWA) and comparable state statutes restrict the disposal, treatment, and release of water produced or used during oil and gas development, including via disposal wells.

In June 2015, the EPA and the U.S. Army Corps of Engineers (USACE) issued a final rule intended to clarify the definition of jurisdictional "waters of the United States" regulated under the Clean Water Act. The final rule, which has been stayed pending the outcome of litigation, could change the scope of waters subject to federal regulation under the Clean Water Act.

In January 2017, the USACE also issued revised and renewed nationwide permits (NWPs) that are available to satisfy permitting requirements for work in streams, wetlands and other waters of the United States under Section 404 of the Clear Water Act and Section 10 of the Rivers and Harbors Act of 1899. The new NWPs take effect in March 2017, or when certified by each state, whichever is later. The oil and gas industry currently utilizes NWP 12 and NWP 39 for the construction, maintenance and repairs of pipelines and drill pads, respectively, and related roads and structures in waters of the United States that impact no more than one-half acre of waters of the United States. These two renewed NWPs were not significantly revised from their previous versions, but the states or local USACE offices may impose additional, area-specific restrictions or requirements on these NWPs before they take effect.

Oil Pollution Act of 1990. The federal Oil Pollution Act of 1990 (OPA) and regulations issued under the OPA impose strict, joint and several liability on "responsible parties" for removal costs and damages to natural resources 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 federal 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 who contributed to the release of a "hazardous substance" into the environment. Such responsible persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances released into the environment and for damages to natural resources. Such liability is in addition to claims for personal injury and property damage allegedly caused by the release of hazardous substances into the environment, which may also be made by third parties.


25



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 on a person who is either a "generator" or "transporter" of hazardous waste or 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 oil, gas or geothermal energy." Any repeal or modification of the oil and gas exploration and production waste 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. In December 2016, the U.S. District Court for the District of Columbia approved a consent decree between the EPA and a coalition of environmental nongovernmental organizations (ENGOs). The consent decree requires the EPA to review and determine whether it will revise the RCRA regulations for exploration and production waste to treat such waste as hazardous waste. The EPA must complete its review and make its decision regarding revision by March 2019. If the EPA chooses to revise the applicable RCRA regulations, it must sign a notice taking final action related to the new regulation by July 2021.
 
Hydraulic Fracturing Regulations. All wells drilled in tight sand or shale reservoirs require hydraulic fracture stimulation to achieve economic production rates and recoverable reserves. QEP'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 composed 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. QEP discloses 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), and to state registries where required.

QEP obtains water for fracture stimulations from a variety of sources, including industrial water wells and surface water sources. When technically and economically feasible, QEP recycles flow-back and produced water, which reduces water consumption from surface and groundwater sources and reduces produced water disposal volumes. QEP also employs additional measures, when available, to protect water quality such as using hydrocarbon free lubricants in water well construction, locking all inactive water wells to prevent unauthorized use, and transporting both fresh and produced water by pipeline instead of truck when feasible to avoid truck traffic and emissions. QEP believes that the employment of fracture stimulation technology does not present any significant additional risks other than those associated with the disposal of waste water (see Item 1A – Risk Factors for additional information) and those generally associated with oil and gas drilling, completion 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 oil and gas well design, construction, and operation. The EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the SDWA and is considering other potential regulation of hydraulic fracturing activities, including pretreatment standards for the oil and gas extraction industry, reporting and disclosure requirements for chemical substances and mixtures used for hydraulic fracturing, and other possible regulations to address the potential effects of hydraulic fracturing on drinking water. QEP does not use diesel fuel in any of its hydraulic fracturing fluids. Additionally, in March 2015, the BLM finalized new regulations, which were to become effective in June 2015, regarding chemical disclosure requirements and other regulations specific to well stimulation activities, including hydraulic fracturing, on federal and tribal leases. These regulations have the potential to increase the cost of drilling and completing any well requiring federal permits and could result in further delays in getting such permits to authorize drilling and completion activities on federal and tribal leases. Several states, including some in which QEP operates, have filed suit against the Department of the Interior over the final BLM hydraulic fracturing regulations. The U.S. District Court for the District of Wyoming set aside the BLM's regulations and the decision is now on appeal to the U.S. Court of Appeals for the Tenth Circuit. Oral argument is currently scheduled for March 2017.

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.

Tribal Lands and Minerals. Various federal agencies within the U.S. Department of the Interior, particularly the BLM and the Bureau of Indian Affairs (BIA), along with certain Native American tribes, promulgate and enforce regulations pertaining to oil

26



and gas operations on Native American tribal lands and minerals where QEP operates. These regulations include, but are not limited to, such matters as lease provisions, drilling and production requirements, surface use restrictions, environmental standards, royalty considerations and taxes. In March 2016, the BIA implemented regulations significantly altering the procedure for obtaining rights-of-way on tribal lands. In certain cases, these new regulations have increased the time and cost required to obtain necessary rights-of-ways for operation on tribal lands for QEP and its competitors.

Endangered Species Act and National Environmental Policy Act. To develop federal or Indian leases, QEP seeks authorizations from federal agencies such as drilling permits and rights-of-way. Prior to issuing such authorizations, federal agencies must comply with both the Endangered Species Act and National Environmental Policy Act (NEPA). 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. NEPA requires that federal agencies assess the direct, indirect and cumulative environmental impacts of their authorizations. This analysis 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.

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 certain facilities to disseminate information on chemical inventories to employees as well as local emergency planning committees and emergency response departments. Following an October 2015 response to a petition of ENGOs, the EPA in January 2017 issued proposed rules to add natural gas processing facilities to the list of facilities that must report under EPCRA and is accepting public comment on the proposed rule until March 2017. 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.

Regulation of the 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. Under the Energy Policy Act of 2005, the FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.

Regulation of Underground Storage
 
QEP, through its wholly owned subsidiary Clear Creek Storage Company, LLC (Clear Creek), 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. In December 2016, the Pipeline and Hazardous Materials Safety Administration published an Interim Final Rule governing safety at underground natural gas storage facilities. The rule became effective in January 2017 and requires adoption of American Petroleum Institute Recommended Practices for depleted reservoir storage facilities by January 2018, which is a highly compressed time frame, especially for smaller facilities like the Clear Creek facility.
 
State Regulations

The states where QEP operates have promulgated extensive and complex regulations that govern oil and gas development within their respective boundaries. These regulations generally increase the cost of constructing, operating, producing and abandoning wells, and violations may result in civil penalties and affect QEP's ability to operate. The following are two recent examples of these state regulations.

North Dakota. The North Dakota Industrial Commission (the Commission), North Dakota's chief energy regulator, issued an order in June 2014 to reduce the volume of natural gas flared from oil wells in the Bakken and Three Forks formations. In connection with that order, the Commission has required operators to develop gas capture plans that describe how much natural gas is expected to be produced, how it will be delivered to a processor and where it will be processed. Production caps or penalties will be imposed on certain wells that cannot meet the capture goals.

On December 9, 2014, the Commission issued Commission Order No. 25417 (Order) requiring that crude oil produced in the Bakken Petroleum System be conditioned to remove lighter, volatile hydrocarbons to reduce the vapor pressure of crude oil. The Order was effective April 1, 2015.

27




Utah. Utah’s Department of Environmental Quality (UDEQ) has experienced significant delays and backlogs in the processing of air permits for oil and gas activities. Although the UDEQ is pursuing the development of a Permit by Rule (PBR) program for future air permitting of most oil and gas activities in order to streamline permitting while protecting air quality, that program may be created only through future rulemaking. Also, Utah’s Governor has made recommendations to the EPA regarding the designation of a portion of the Uinta Basin as nonattainment for the eight-hour ozone National Ambient Air Quality Standard. That designation, expected to be made in 2017, will result in the lowering of emissions allowed in air permits to be issued by the UDEQ to QEP and other operators.

Other Regulations

Transporting Crude Oil by Rail. In May 2015, the U.S. Department of Transportation issued a final rule regarding the safe transportation of flammable liquids by rail. The final rule imposes certain requirements on "offerors" of crude oil, including sampling, testing and certification requirements to improve classification of energy products placed into transport.

Dodd-Frank Wall Street Reform and Consumer Protection Act. The Dodd-Frank Wall Street Reform and Consumer Protection Act (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 an exemption from these clearing and cash collateral requirements for commercial end-users. See Part I, Item 1A - Risk Factors, in this Annual Report on Form 10-K for more information.

Reporting and Payment of Federal Royalties. In July 2016, the Department of the Interior's Office of Natural Resources (ONRR) revised its regulations related to the valuation of federal oil and gas produced from onshore and offshore federal leases for royalty purposes. The regulations, which took effect in January 2017, change the requirements for valuing and reporting gas sold under certain contractual arrangements, change the reporting of allowed deductions for gas transportation and processing, and allow the ONRR to decide the value of oil and gas for royalty purposes in certain circumstances, among other changes. An oil and gas trade association filed a lawsuit challenging these regulations in December 2016. In addition, in August 2016, the ONRR revised its civil penalty regulations, making it easier for the ONRR to issue civil penalties for incorrectly reporting production and incorrectly paying royalties on federal and tribal leases.

ITEM 1A. RISK FACTORS
 
Described below are certain risks that we believe are applicable to our business and the oil and gas industry in which we operate. 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 on Form 10-K actually occur, the Company's business, financial condition or results of operations could be materially adversely affected.
 
The prices for oil, gas and NGL are volatile, and declines in such prices could adversely affect QEP's earnings, cash flows, asset values and stock price. Historically, oil, gas and NGL prices have been volatile and unpredictable, and that volatility is expected to continue. Volatility in oil, gas and NGL prices is due to a variety of factors that are beyond QEP’s control, including:

changes in local, regional, domestic and foreign supply of and demand for oil, gas and NGL;
the potential long-term impact of an abundance of oil, gas and NGL from unconventional sources on the global and local energy supply;
the level of imports and/or exports of, and the price of, foreign oil, gas and NGL;
localized supply and demand fundamentals, including the proximity, cost and availability of pipelines and other transportation facilities, and other factors that result in differentials to benchmark prices from time to time;
the availability of refining and storage capacity;
domestic and global economic and political conditions;
speculative trading in crude oil and natural gas derivative contracts;
the continued threat of terrorism and the impact of military and other action;
the activities of the Organization of Petroleum Exporting Countries (OPEC) and other oil producing countries, including the ability of members of OPEC to maintain oil price and production controls;
political and economic conditions and events in the United States and in or affecting other producing countries, including conflicts in the Middle East, Africa, South America and Russia;
the strength of the U.S. dollar relative to other currencies;

28



weather conditions and natural disasters;
government laws, regulations and taxes, including regulations or legislation relating to climate change, induced seismicity or oil and gas 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 and natural gas used as fuel for electricity generation;
the level of global oil, gas and NGL inventories and exploration and production activity; and
the quality of oil and gas produced.

The long-term effect of these and other factors on the prices of oil, gas and NGL is uncertain. Prolonged or further declines in these commodity prices may have the following effects on QEP's business:

adversely affecting QEP's financial condition and liquidity and QEP's ability to finance planned capital expenditures, borrow money, repay debt and raise additional capital;
reducing the amount of oil, gas and NGL that QEP can produce economically;
causing QEP to delay or postpone some of its capital projects;
reducing QEP's revenues, operating income or cash flows;
reducing the amounts of QEP's estimated proved oil, gas and NGL proved reserves;
reducing the carrying value of QEP's oil and gas properties due to recognizing additional impairments of proved and unproved properties;
limiting QEP's access to, or increasing the cost of, sources of capital such as equity and long-term debt; and
decreasing the value of QEP's common stock.

Lower oil, gas and NGL prices or negative adjustments to oil, gas and NGL reserves may result in significant impairment charges. Lower commodity prices may not only decrease QEP's revenues, operating income and cash flows but also may reduce the amount of oil, gas and NGL that QEP can produce economically. GAAP requires QEP to write down, as a non-cash charge to earnings, the carrying value of its oil and gas properties in the event it has impairments. QEP is required to perform impairment tests on its assets periodically and whenever events or changes in circumstances warrant a review of its assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of its assets, the carrying value may not be recoverable, and, therefore, a write-down may be required. During the years ended December 31, 2016, 2015 and 2014, QEP recorded impairment charges of $1,172.7 million, $39.3 million and $1,041.4 million, respectively, on its proved properties and $17.9 million, $2.0 million and $101.8 million, respectively, on its unproved properties. QEP also recorded goodwill impairment of $3.7 million and $14.3 million during the years ended December 31, 2016 and 2015, respectively. See Part I, Item 8, Note 1 – Summary of Significant Accounting Policies, of this Annual Report on Form 10-K for additional information.

The Company may not be able to economically find and develop new reserves. The Company's profitability depends not only on prevailing prices for oil, gas and NGL, but also on its ability to find, develop and acquire oil and gas reserves that are economically recoverable. Producing oil and gas reservoirs are generally characterized by declining production rates that vary depending on reservoir characteristics. Because oil and gas production volumes from unconventional 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 oil and gas reserves to replace those depleted by production. Failure to find or acquire additional reserves would cause reserves and production to decline materially from their current levels.
 
Oil and gas reserve estimates are imprecise, may prove to be inaccurate, and are subject to revision. Any significant inaccuracies in QEP's reserve estimates or underlying assumptions may negatively affect the quantities and present value of QEP's reserves. QEP's proved oil and gas reserve estimates are prepared annually by independent reservoir engineering consultants. Oil and gas 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 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 property, the classifications of reserves, the estimated future net cash flows from proved reserves and the present value of those reserves.

29



 
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 on Form 10-K is reflective of the current market value of the estimated oil and gas 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% 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. Therefore, reserve quantities may change when actual prices increase or decrease.
 
Our use of seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations. Even when properly used and interpreted, seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether producible hydrocarbons are, in fact, present in those structures in economic quantities. In addition, the use of 3-D seismic and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.

Shortages of qualified personnel and/or oilfield equipment and services could impact results of operations. The oil and gas industry has long suffered a skills shortage, recognized by many to be a threat to future growth. This skills shortage has been exacerbated by depressed oil and gas prices in 2015 and 2016 and the resulting loss of skilled workers through layoffs in the oil and gas industry during these years. 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 will create challenges for QEP and its competitors and may cause periodic and problematic personnel shortages. In periods of high prices, there have also been regional shortages of drilling rigs and other equipment. Any cost increases could impact profit margin, cash flow and operating results or restrict the ability to drill wells and conduct operations.

QEP's operations are subject to operational hazards and unforeseen interruptions for which QEP may not be adequately insured. There are operational risks associated with the exploration, production, gathering, transporting, and storage of oil, gas and NGL, including:
 
injuries and/or deaths of employees, supplier personnel, or other individuals;
fire, explosions and blowouts;
earthquakes and other natu