QEP RESOURCES, INC.
ITEM 1. BUSINESS
Nature of Business
QEP Resources, Inc. (QEP or the Company) is a holding company with three major lines of business: oil and gas exploration and production; midstream field services; and energy marketing. These businesses are conducted through the Company’s three principal subsidiaries:
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QEP Energy Company (QEP Energy) acquires, explores for, develops and produces gas, oil, and NGL;
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QEP Field Services Company (QEP Field Services), which includes the ownership and operations of QEP Midstream Partners, LP (QEP Midstream), provides midstream field services, including gathering of natural gas, oil and NGL, natural gas processing, compression, and treating services, for affiliates and third parties, and;
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QEP Marketing Company (QEP Marketing) markets affiliate and third-party oil and gas, and owns and operates an underground gas storage reservoir.
QEP's operations are focused in two major regions: the Northern Region (primarily in North Dakota, Wyoming and Utah) and the Southern Region (primarily in Oklahoma, Louisiana and the Texas Panhandle) of the United States. QEP's corporate headquarters are located in Denver, Colorado.
Reincorporation Merger and Spin-off from Questar
Effective May 18, 2010, Questar Market Resources Inc. (Market Resources), then a wholly owned, public subsidiary of Questar Corporation (Questar), merged with and into a newly formed, wholly owned subsidiary, QEP Resources, Inc., a Delaware corporation, in order to reincorporate in the State of Delaware (Reincorporation Merger). The Reincorporation Merger was effected pursuant to an Agreement and Plan of Merger entered into between Market Resources and QEP. On June 30, 2010, Questar distributed all of the shares of common stock of QEP held by Questar to Questar shareholders in a tax-free, pro rata dividend (the Spin-off). Each Questar shareholder received one share of QEP common stock for each share of Questar common stock held at the close of business on the record date. In connection with the Spin-off, QEP distributed Wexpro Company (Wexpro), a wholly owned subsidiary of QEP at the time, to Questar. In addition, Questar contributed $250.0 million of equity to QEP prior to the Spin-off.
In connection with the reorganization, QEP renamed its subsidiaries as follows:
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QEP Energy Company (formerly Questar Exploration and Production Company);
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QEP Field Services Company (formerly Questar Gas Management Company); and
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QEP Marketing Company (formerly Questar Energy Trading Company).
The financial information presented in this Annual Report on Form 10-K presents QEP's financial results as an independent company separate from Questar.
Financial and Operating Highlights
Our financial and operating highlights for 2013 include:
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Generated net income of $159.4 million, or $0.89 per diluted share, an increase of 24% from 2012;
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Generated Adjusted EBITDA (a non-GAAP financial measure defined and reconciled in Item 7 of Part II of this Annual Report on Form 10-K) of $1,536.7 million, up from $1,409.0 million in 2012;
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Increased liquids (oil and NGL) production by 29% to 90.1 Bcfe;
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Increased total proved reserves 3% to 4.1 Tcfe and increased liquid (oil and NGL) proved reserves by 15% to 1.5 Tcfe;
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Added 783.8 Bcfe of proved reserves from extensions and discoveries;
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QEP Field Services' gathering throughput volumes, NGL sales volumes and fee-based processing volumes decreased by 13%, 37% and 1%, respectively;
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Recorded $105.7 million of gain on sales of several non-core oil and gas properties;
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Completed the initial public offering of limited partner interests in QEP Midstream (NYSE: QEPM) raising net proceeds of $449.6 million; and
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Completed an acquisition of oil and gas properties in the Permian Basin for approximately $950.0 million, subject to customary purchase price adjustments, during the first quarter of 2014.
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:
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operate in a safe and environmentally responsible manner;
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allocate capital to those projects that generate the highest returns;
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acquire businesses and assets that complement or expand our current business;
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maintain a sustainable, diverse inventory of low-cost, high-margin resource plays;
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be in the highest-potential areas of the resource plays in which we operate;
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build contiguous acreage positions that drive operating efficiencies;
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be the operator of our assets, whenever possible;
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be the low-cost driller and producer in each area where we operate;
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maximize the value of our midstream assets;
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actively market our QEP Energy production to maximize value;
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utilize derivative contracts to mitigate the impact of gas, oil or NGL price volatility and fluctuating interest rates, while locking in acceptable cash flows required to support future capital expenditures;
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attract and retain the best people; and
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maintain a capital structure that allows us the necessary financial flexibility with which to invest in organic growth and potential acquisition opportunities, as they may arise.
Exploration and Production - QEP Energy
QEP Energy conducts exploration and production (E&P) activities in several of North America's most important hydrocarbon resource plays. QEP Energy has a large inventory of identified development drilling locations, primarily in the Williston Basin in North Dakota; the Pinedale Anticline in western Wyoming; the Uinta Basin in eastern Utah; the Anadarko Basin in Oklahoma and Texas; the Haynesville/Cotton Valley in northwestern Louisiana and other proven properties in Wyoming, Colorado and Utah. During the first quarter of 2014, QEP Energy acquired oil and gas properties in the Permian Basin of Texas for an aggregate purchase price of $950.0 million, subject to customary purchase price adjustments (the Permian Basin Acquisition). The acquired properties consist of approximately 26,500 net acres of producing and undeveloped oil and gas properties and approximately 260 vertical producing wells in the Permian Basin, which creates a new core area of operation for QEP Energy.
For 2014, QEP plans to allocate approximately 94% of its capital budget to E&P activities, including capital expenditures allocated to the properties acquired in the Permian Basin Acquisition. The following map illustrates the location of the Company's significant exploration and production activities, its Northern and Southern Regions described elsewhere in this report, and related reserve and production data as of December 31, 2013:
QEP Energy generated approximately 86%, 81%, and 77% of the Company's Adjusted EBITDA (refer to Item 7 of Part II of this Annual Report on Form 10-K for management's definition and a reconciliation to net income of this non-GAAP financial measure) during the years ended December 31, 2013, 2012 and 2011, respectively. QEP Energy operates in two core regions - the Northern Region (including the states of Wyoming, Utah, Colorado, and North Dakota) and the Southern Region (including the states of Oklahoma, Texas and Louisiana). The Northern Region contributed 58% of 2013 production while the Southern Region contributed 42%. QEP Energy reported 4,061.9 Bcfe of estimated proved reserves as of December 31, 2013, up 125.8 Bcfe from 2012. Of those estimated proved reserves, approximately 75%, or 3,039.7 Bcfe, were located in the Northern Region at December 31, 2013, compared to 73%, or 2,875.6 Bcfe, at December 31, 2012. The remaining 25%, or 1,022.2 Bcfe, were located in the Southern Region at December 31, 2013, compared to 27%, or 1,060.5 Bcfe, at December 31, 2012. Approximately 53% of the total proved reserves reported by QEP Energy at December 31, 2013, were developed and approximately 37% of the total proved reserves were comprised of oil and NGL, up from 33% at December 31, 2012.
QEP Energy faces competition in every part of its business, including the acquisition of producing leaseholds and wells and undeveloped leaseholds, the marketing of oil and gas, and the procurement of goods, services and labor. Its longer-term growth strategy depends, in part, on its ability to acquire reasonably priced acreage containing undeveloped reserves and identify and develop the reserves in a low-cost and efficient manner.
The Company seeks to acquire, develop and produce oil and gas from resource plays in its core areas of operation and expand into new areas where it can capitalize on its operating expertise. Since the existence and distribution of hydrocarbons in resource plays is well understood, development of these accumulations has lower risk than conventional discrete hydrocarbon accumulations. Resource plays typically require many wells, drilled at high density, to fully develop and produce the hydrocarbon accumulations. Development of QEP Energy's resource play accumulations requires expertise in drilling large numbers of complex, highly deviated or horizontal wells to vertical depths that generally range between 10,000 and 14,000 feet and the application of advanced well completion techniques, including hydraulic fracture stimulation, to achieve economic production rates. QEP Energy also continues to conduct some exploratory drilling to determine the commerciality of its inventory of unproven leaseholds. QEP Energy seeks to maintain geographical and geological diversity with its two core
regions. In addition to the Williston Basin acquisition in 2012 and the Permian Basin Acquisition in the first quarter of 2014, 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 Energy, both directly and through QEP Marketing, sells its gas, oil and NGL production to a variety of customers, including gas-marketing firms, industrial users, local-distribution companies, crude oil refiners and marketers. QEP Energy regularly evaluates counterparty credit and may require financial guarantees or prepayments from parties that fail to meet its credit criteria.
Midstream Field Services - QEP Field Services
QEP Field Services provides midstream services (gathering, processing and treating) to QEP Energy and third-party customers, including major and independent producers. QEP generates revenues from its midstream activities through a variety of agreements including fee-based gathering and processing agreements and keep-whole processing agreements.
In August 2013, QEP completed the initial public offering (the IPO) of QEP Midstream, a publicly traded master limited partnership formed by QEP to own, operate, acquire and develop certain midstream energy assets. QEP Midstream is consolidated into QEP as it is a majority-owned and controlled subsidiary. Refer to Note 3 - QEP Midstream, in Part II, Item 8 of this Annual Report on Form 10-K for detailed information on the IPO.
In December 2013, after a review of strategic alternatives to maximize the value of its midstream assets, QEP's Board of Directors authorized the Company to develop a plan to separate the business of QEP Field Services, including the Company's interest in QEP Midstream, from QEP.
For 2014, QEP plans to allocate approximately 4% of its capital budget to QEP Field Services to grow its midstream business, including the construction of additional gathering facilities in the Uinta Basin as well as an expansion of the Vermillion processing plant.
The following map illustrates QEP Field Services' areas of operations and the locations corresponding with QEP Energy's operating areas:
QEP Field Services generated approximately 14%, 19%, and 23% of the Company's Adjusted EBITDA (refer to Item 7 of Part II of this Annual Report on Form 10-K for management's definition and a reconciliation to net income of this non-GAAP financial measure) for the years ended December 31, 2013, 2012 and 2011, respectively. QEP Field Services owns various
natural gas gathering, treating and processing facilities as well as a 57.8% interest in QEP Midstream and 38% of Uintah Basin Field Services, LLC (UBFS).
QEP Midstream's assets currently consist of ownership interests in four gathering systems and two FERC regulated pipelines, which provide oil and gas gathering and transportation services. These assets are located in, or within close proximity to, the Green River Basin located in Wyoming and Colorado, the Uinta Basin located in eastern Utah, and the Williston Basin located in North Dakota.
Fee-based gathering and processing revenues represented 82%, 77% and 70% of QEP Field Services' net operating revenues (revenues less plant shrink and transportation costs) during the years ended December 31, 2013, 2012 and 2011, respectively. Approximately 55%, 41%, and 35% of QEP Field Services' 2013, 2012 and 2011, net gas processing revenues (processing revenues less plant shrink) were derived from fee-based processing agreements. The remaining revenues were derived from keep-whole processing agreements. A keep-whole contract exposes QEP Field Services to frac-spread risk while a fee-based contract eliminates direct commodity price exposure. To further reduce volatility associated with keep-whole contracts, QEP Field Services may enter into forward-sales contracts for NGL or NGL price derivatives and equivalent gas volume derivatives with the intent to lock in a processing margin.
QEP Field Services faces regional competition with varying competitive factors in each basin. QEP Field Services' gathering and processing business competes with interstate and intrastate pipelines, producers and independent gatherers and processors. Numerous factors impact a customer's choice of a gathering or processing service provider, including location, rate, term, pressure obligations, timeliness of services, and contract structure. QEP Field Services provides natural gas gathering, processing and treating services to affiliates and third-party producers who own producing natural gas fields in the Rocky Mountain region, the Williston Basin and northwest Louisiana. In addition to its natural gas operations, QEP Field Services also provides oil and water gathering and handling to affiliates and third-party producers in the Rocky Mountain region and the Williston Basin. QEP Field Services' gas gathering, processing and treating services are generally provided under long-term agreements.
Energy Marketing-QEP Marketing
QEP Marketing provides wholesale marketing and sales of affiliate and third-party gas, oil and NGL and generated less than 1% of the Company's Adjusted EBITDA (refer to Item 7 of Part II of this Annual Report on Form 10-K for management's definition and a reconciliation to net income of this non-GAAP financial measure) for each of the years ended December 31, 2013, 2012 and 2011. As a wholesale marketing entity, QEP Marketing concentrates on markets in the Rocky Mountains and Midcontinent that are either close to affiliate reserves and production or accessible by major pipelines. QEP Marketing contracts for firm-transportation capacity on pipelines and firm-storage capacity at Clay Basin, a large gas storage facility in northeast Utah.
QEP Marketing, through its wholly owned subsidiary Clear Creek Storage Company, LLC (Clear Creek), owns and operates an underground gas-storage reservoir in southwestern Wyoming. QEP Marketing uses owned and leased storage capacity together with firm-transportation capacity, to manage seasonal swings in prices in the Rocky Mountain region. QEP Marketing sells NGL volumes associated with the gas stored in its Clear Creek storage facility.
QEP Marketing competes directly with large independent energy marketers, marketing affiliates of regulated pipelines and utilities and natural gas producers. QEP Marketing also competes with brokerage houses, energy hedge funds and other energy-based companies offering similar services. QEP Marketing sells QEP Energy's gas and volumes purchased from third parties to wholesale marketers, industrial end-users and utilities. QEP Marketing sells QEP Energy's oil volume to refiners, marketers and other companies, including some with pipeline facilities near QEP Energy's producing properties. In the event pipeline facilities are not available, QEP Marketing arranges transportation of oil by truck or rail to storage, refining or pipeline facilities.
Government Regulation
QEP's business operations are subject to regulation under a wide range of local, state, tribal and federal statutes, rules, orders and regulations. The regulatory burden on the oil and gas industry increases the cost of doing business and consequently affects its profitability. While QEP believes that it is in substantial compliance with currently applicable laws and regulations and has not experienced any material adverse effect arising from these requirements, there is no assurance that this trend will continue in the future. Due to the myriad of complex federal, state, tribal and local regulations that may affect the Company, directly or indirectly, the following discussion of certain laws and regulations should not be considered an exhaustive review of all regulatory considerations affecting QEP's operations. See additional discussion of regulations under
ITEM 1A. RISK FACTORS
Investors should read carefully the following factors as well as the cautionary statements referred to in "Forward-Looking Statements" herein. If any of the risks and uncertainties described below or elsewhere in this Annual Report actually occur, the Company's business, financial condition or results of operations could be materially adversely affected.
The prices for gas, oil and NGL are volatile, and a decline in such prices could adversely affect QEP's results, stock price and growth plans. Historically gas, oil and NGL prices have been volatile and will likely continue to be volatile in the future. U.S. natural gas prices in particular are significantly influenced by weather and weather forecasts. Any significant or extended decline in commodity prices would impact the Company's future financial condition, revenue, operating results, cash flow, return on invested capital, and rate of growth. In addition, significant and extended declines in commodity prices could limit QEP's access to sources of capital or cause QEP to delay or postpone some of its capital projects. Because a significant portion of QEP Energy's future production is gas, the Company's financial results are substantially more sensitive to changes in gas prices than to changes in oil prices.
QEP cannot predict the future price of gas, oil and NGL because of factors beyond its control, including but not limited to:
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changes in domestic and foreign supply of gas, oil and NGL;
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changes in local, regional, national and global demand for gas, oil, NGL and related commodities;
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the activities of the Organization of Petroleum Exporting Countries;
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domestic and global economic conditions;
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regional price differences resulting from available pipeline transportation capacity or local demand;
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terrorist attacks on production or transportation assets;
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the level of imports of, and the price of, foreign gas, oil and NGL;
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the potential long-term impact of an abundance of gas, oil and NGL from unconventional sources on the global and local energy supply;
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political developments and actions in the United States and in or affecting other producing countries, including conflicts in the Middle East, Africa, South America and Russia;
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weather conditions and weather forecasts;
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government regulations and taxes, including regulations or legislation relating to climate change or oil and gas exploration and production activities;
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technological advances affecting energy consumption and energy supply;
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conservation efforts;
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the price, availability and acceptance of alternative fuels, including coal, nuclear energy and biofuels;
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demand for electricity as well as natural gas used for fuel for electricity generation;
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storage levels of gas, oil, and NGL; and
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the quality of oil and gas produced.
Lower commodity prices may reduce the amount of gas, oil and NGL that QEP can produce economically. In addition, lower commodity prices may result in asset impairment charges from reductions in the carrying values of QEP's oil and gas properties or a reduction in the carrying value of goodwill. During the years ended December 31, 2013 and 2012, QEP recorded impairment charges of $1.2 million and $107.6 million, respectively, on its proven properties and $32.3 million and $25.4 million, respectively, on its unproven properties. QEP also recorded a $59.5 million impairment of goodwill in 2013. See Part I, Item 8, Note 1 - Summary of Significant Accounting Policies, of this Annual Report on Form 10-K for additional information.
Slower economic growth rates in the U.S. may materially adversely impact QEP's operating results. The U.S. and other economies are recovering from a global financial crisis and recession that began in 2008. Growth has resumed but has been modest and at an unsteady rate. There could be significant long-term effects resulting from the financial crisis and recession, including a future global economic growth rate that is slower than that experienced in the years leading up to the crisis, and more volatility may occur before a sustainable growth rate is achieved. Global economic growth drives demand for energy from all sources, including fossil fuels. A lower future economic growth rate is likely to result in decreased demand growth for QEP's gas, oil and NGL production. A decrease in demand, excluding changes in other factors, could potentially result in lower commodity prices, which would reduce QEP's cash flows from operations and its profitability.
Multi-well pad drilling may result in volatility in QEP operating results. QEP utilizes multi-well pad drilling where practical. Because 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, multi-well pad drilling delays the commencement of production, which may cause volatility in QEP’s quarterly operating results.
The Company may not be able to economically find and develop new reserves. The Company's profitability depends not only on prevailing prices for gas, oil and NGL, but also 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 QEP wells typically experience relatively steep declines in the first year of operation and continue to decline over the economic life of the well, QEP must continue to invest significant capital to find, develop and acquire oil and gas reserves to replace those depleted by production.
Oil and gas reserve estimates are imprecise and subject to revision. 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 also involves economic assumptions relating to commodity prices, operating costs, severance and other taxes, capital expenditures and remediation costs. Actual results most likely will vary from the estimates. Any significant variance from these assumptions could affect the recoverable quantities of reserves attributable to any particular properties, the classifications of reserves, the estimated future net cash flows from proved reserves and the present value of those reserves.
Investors should not assume that QEP's presentation of the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves in this Annual Report is reflective of the current market value of the estimated 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 percent per year. Actual future production, prices and costs may differ materially from those used in the current estimate, and future determinations of the Standardized Measure of Discounted Future Net Cash Flows using similarly determined prices and costs may be significantly different from the current estimate.
Shortages of, and increasing prices for, oilfield equipment, services and qualified personnel could impact results of operations. The demand for and availability of qualified and experienced personnel to drill wells and conduct field operations, in addition to geologists, geophysicists, engineers, landmen and other professionals in the oil and gas industry, can fluctuate significantly, often in correlation with oil and gas prices, causing periodic shortages. There have also been regional shortages of drilling rigs and other equipment, as demand for specialized rigs and equipment has increased along with the number of wells being drilled. These factors also cause increases in costs for equipment, services and personnel. These cost increases could impact profit margin, cash flow and operating results or restrict the ability to drill wells and conduct operations, especially during periods of lower oil and gas prices.
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 gathering, transporting, storage, processing and treating of natural gas; the fractionation, transportation and storage of NGLs; and oil transportation and production handling; including:
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injuries and/or deaths of employees, supplier personnel, or other individuals;
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fire, explosions and blowouts;
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aging infrastructure and mechanical problems;
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unexpected drilling conditions such as abnormally pressured formations;
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pipe, cement or casing failures;
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title problems;
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equipment malfunctions and/or mechanical failure on high-volume wells;
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security breaches, cyber attacks, piracy, or terroristic acts;
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theft or vandalism of oilfield equipment and supplies, especially in areas of increased activity;
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severe weather that could affect QEP's operations;
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plant, pipeline, railway and other facility accidents and failures;
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truck and rail loading and unloading; and
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environmental accidents such as oil spills, natural gas leaks, pipeline or tank ruptures, or discharges of air pollutants, brine water or well fluids into the environment, including from hydraulic fracturing activities.
QEP could incur substantial losses as a result of injury or loss of life, pollution or other environmental damage, damage to or destruction of property and equipment, regulatory compliance investigations, fines or curtailment of operations; or attorney's fees and other expenses incurred in the prosecution or defense of litigation. As a working interest owner in wells operated by other companies, QEP may also be exposed to the risks enumerated above from operations that are not within its care, custody or control.
The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites could increase the level of damages resulting from these risks. Certain segments of QEP's pipelines run through such areas. In spite of QEP's precautions, an accident or other event could cause considerable harm to people or property, and could have a material adverse effect on QEP's financial position and results of operations, particularly if the event is not fully covered by insurance. Accidents or other operating risks once realized could further result in lost business. Such circumstances could adversely impact QEP's ability to meet contractual obligations.
Consistent with industry practice, QEP generally indemnifies drilling contractors and oilfield service companies (collectively, contractors) against certain losses suffered by the operator and third parties resulting from a well blowout or fire or other uncontrolled flow of hydrocarbons, regardless of fault. Therefore, QEP may be liable, regardless of fault, for some or all of the costs of controlling a blowout, drilling a relief and/or replacement well and the cleanup of any pollution or contamination resulting from a blowout as well as for claims for personal injury or death suffered by QEP's employees and others. QEP's drilling contracts and oilfield service agreements, however, generally provide that the contractor will indemnify QEP for claims related to injury and death of employees of the contractor and for property damage suffered by the contractor.
As is also customary in the oil and gas industry, QEP maintains insurance against some, but not all, of these potential risks and losses. Although QEP believes the coverage and amounts of insurance that it carries are consistent with industry practice, QEP does not have insurance protection against all risks that it faces because QEP chooses not to insure certain risks, insurance is not available at a level that balances the costs of insurance and QEP's desired rates of return, or actual losses may exceed coverage limits.
Lack of availability of refining or transportation capacity could impact results of operations. The lack of availability of satisfactory oil, gas and NGL transportation, including trucks, railways and pipelines, or refining capacity may hinder QEP's access to oil, NGL and gas markets or delay production from its wells. QEP's ability to market its production depends in substantial part on the availability and capacity of transportation or refineries owned and operated by third parties. Although QEP has some contractual control over the transportation of its production through firm transportation arrangements, third-party systems may be temporarily unavailable due to market conditions, mechanical failures, accidents or other reasons. If transportation facilities do not exist near producing wells, if transportation or refining capacity is limited or if transportation or refining capacity is unexpectedly disrupted, completion activity could be delayed, sales could be reduced, or production shut in each of which could reduce profitability. For example, during the third quarter of 2013, growing volumes on third-party gathering systems in QEP’s South Antelope area of the Williston Basin resulted in problems with the redelivery of oil from gathering systems to downstream markets. As a result, QEP was forced to take oil off the gathering system and truck it to rail-loading facilities, which delayed QEP’s operations and, as a result of additional trucking costs, reduced QEP’s realized prices. In addition, there have been rail accidents involving crude oil carriers, which may result in new restrictions on transportation of oil by railway. Furthermore, if QEP were required to shut in wells, it might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain its leases; or depending on the specific lease provisions, some leases could terminate. If transportation quality requirements change, QEP might be required to install or contract for additional treating or processing equipment, which could increase costs. Federal and state regulation of oil and gas production and transportation, tax and energy policies, changes in supply and demand, transportation pressures, damage to or destruction of transportation facilities and general economic conditions could also adversely affect QEP's ability to transport oil and gas.
QEP acts as the general partner of a publicly traded master limited partnership, QEP Midstream, which may involve a greater exposure to legal liability than QEP’s historic business operations. One of QEP's subsidiaries acts as the general partner of QEP Midstream, a publicly traded master limited partnership. QEP’s control of the general partner of QEP Midstream may increase the possibility of claims of breach of fiduciary duties including claims of conflicts of interest related to QEP Midstream. Any liability resulting from such claims could have a material adverse effect on QEP’s future business, financial condition, results of operations and cash flows.
Certain of QEP's undeveloped leasehold assets are subject to lease agreements that will expire over the next several years unless production is established on units containing the acreage. Leases on oil and gas properties typically have a term of three to five years after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. If QEP's leases expire and QEP is unable to renew the leases, QEP will lose its right to develop the related reserves. While QEP seeks to actively manage its leasehold inventory by drilling sufficient wells to hold the leases that it believes are material to its operations, QEP's drilling plans are subject to change based upon various factors, including drilling results, oil and gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals.
QEP’s identified potential well locations are scheduled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, QEP may not be able to raise the substantial amount of capital that would be necessary to drill its potential well locations. QEP’s management team has specifically identified and scheduled certain well locations as an estimation of its future multi-year drilling activities on its existing acreage. These well locations represent a significant part of QEP’s growth strategy. QEP’s ability to drill and develop these locations depends on a number of uncertainties, including oil and gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water and water disposal facilities, regulatory approvals and other factors. Because of these factors, QEP does not know if the numerous potential well locations QEP has identified will be drilled or if QEP will be able to produce oil and gas from these or any other potential well locations. In addition, any drilling activities QEP is able to conduct on these potential locations may not be successful or result in QEP’s ability to add additional proved reserves to its overall proved reserves or may result in a downward revision of its estimated proved reserves, which could have a material adverse effect on QEP’s future business and results of operations.
The fees charged by QEP to third parties under its gathering and processing agreements may not escalate sufficiently to cover increases in costs, or the agreements may not be renewed or may be suspended in some circumstances. QEP's costs may increase at a rate greater than the fees it charges to third parties for gathering, treating and processing services.
Furthermore, third parties may not renew their contracts with QEP. Additionally, some third parties' obligations under their agreements with QEP may be permanently or temporarily reduced due to certain events, some of which are beyond QEP's control, including force majeure events wherein the supply of either gas, oil or NGL are curtailed or cut off. Force majeure events include (but are not limited to): wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, fires, storms, floods, earthquakes, acts of God, explosions and mechanical or physical failures of equipment affecting QEP's facilities or facilities of third parties. If the escalation of fees is insufficient to cover increased costs, if third parties do not renew or extend their contracts with QEP or if third parties suspend or terminate their contracts with QEP, the Company's financial results would suffer.
QEP is required to pay fees to its service providers based on minimum volumes regardless of actual volume throughput. QEP has contracts with third-party service providers for transportation services with minimum volume delivery commitments. As of December 31, 2013, QEP’s long-term contractual obligation under these agreements was $790.3 million. QEP is obligated to pay fees on minimum volumes to service providers regardless of actual volume throughput, which fees could be significant and have a material adverse effect on its results of operations.
QEP is dependent on its revolving credit facility and continued access to capital markets to successfully execute its operating strategies. If QEP is unable to obtain needed capital or financing on satisfactory terms, QEP may experience a decline in its oil and gas production rates and reserves. QEP is partially dependent on external capital sources to provide financing for certain projects. The availability and cost of these capital sources is cyclical, and these capital sources may not remain available, or the Company may not be able to obtain financing at a reasonable cost in the future. Over the last few years, conditions in the global capital markets have been volatile, making terms for certain types of financings difficult to predict, and in certain cases, resulting in certain types of financing being unavailable. If QEP's revenues decline as a result of lower gas, oil or NGL prices, operating difficulties, declines in production or for any other reason, QEP may have limited ability to obtain the capital necessary to sustain its operations at current levels. The Company utilizes its revolving credit facility, provided by a group of financial institutions, to meet short-term funding needs. All of QEP's debt under its revolving credit facility is floating-rate debt. From time to time, the Company may use interest-rate derivatives to manage the interest rate on a portion of its floating-rate debt. The interest rates for the Company's revolving credit facility are tied to QEP's ratio of indebtedness to Consolidated EBITDAX (as defined in the credit agreement). QEP's failure to obtain additional financing could result in a curtailment of its operations relating to exploration and development of its prospects or construction of new oil and gas processing facilities, which in turn could lead to a possible reduction in QEP's oil or gas production, reserves and revenues, and could negatively impact its results of operations.
A downgrade in QEP's credit rating could negatively impact QEP's cost of and ability to access capital. Although QEP is not aware of any current plans of credit rating agencies to lower their ratings on QEP's debt, QEP's credit ratings may be subject to future downgrades. A downgrade of credit ratings may make it more difficult or expensive to raise capital from financial institutions or other sources. A downgrade in QEP's credit rating below a certain level could limit the amount of debt that QEP may incur. In addition, a downgrade could affect QEP's requirements to provide financial assurance of its performance under certain contractual arrangements and derivative agreements.
QEP's debt and other financial commitments may limit its financial and operating flexibility. QEP's total debt was approximately $3.0 billion at December 31, 2013. QEP also has various commitments for leases, drilling contracts, derivative contracts, firm transportation, and purchase obligations for services and products. QEP's financial commitments could have important consequences to its business including, but not limited to, limiting QEP's ability to fund future working capital and capital expenditures, to engage in future acquisitions or development activities, to pay dividends to shareholders, or to otherwise realize the value of its assets and opportunities fully because of the need to dedicate a substantial portion of its cash flows from operations to payments on its debt or to comply with any restrictive terms of its debt. Additionally, the credit agreements governing QEP's revolving credit facility, term loan facility and the indentures covering QEP’s senior notes contain a number of covenants that impose constraints on the Company, including restrictions on QEP's ability to dispose of assets, make certain investments, incur liens and engage in transactions with affiliates.
QEP is exposed to counterparty credit risk as a result of QEP's receivables and commodity derivative transactions. QEP has significant credit exposure to outstanding accounts receivable from purchasers of its production, joint interest and working interest owners as well as customers in all segments of its business. Because QEP is the operator of a majority of its production and major development projects, QEP pays joint venture expenses and in some cases makes cash calls on its non-operating partners for their respective shares of joint venture costs. These projects are capital intensive and, in some cases, a non-operating partner may experience a delay in obtaining financing for its share of the joint venture costs. Counterparty liquidity problems could result in a delay in QEP receiving proceeds from commodity sales or reimbursement of joint venture costs. Credit enhancements, such as financial guarantees or prepayments, have been obtained from some but not all parties. Nonperformance by a trade creditor or joint venture partner could result in financial losses. In addition, QEP's
commodity derivative transactions expose it to risk of financial loss if the counterparty fails to perform under a contract. During periods of falling commodity prices, QEP's commodity derivative receivable positions increase, which increases its counterparty credit exposure.
QEP faces various risks associated with the trend toward increased opposition to oil and gas exploration and development activities. Opposition to oil and gas drilling and development activity has been growing globally and is particularly pronounced in the U.S. Companies in the oil and gas industry, such as QEP, are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, environmental compliance and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain projects such as the development of oil or gas shale plays. For example, environmental activists continue to advocate for increased regulations on shale drilling in the U.S., even in jurisdictions that are among the most stringent in their regulation of the industry. Future activist efforts could result in the following:
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delay or denial of drilling and other necessary permits;
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shortening of lease terms or reduction in lease size;
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restrictions on installation or operation of production, gathering or processing facilities;
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setback requirements from houses, schools and businesses;
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towns, cities, states and counties considering bans on certain activities, including hydraulic fracturing;
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restrictions on the use of certain operating practices, such as hydraulic fracturing, or the disposition of related waste materials, such as hydraulic fracturing fluids and produced water;
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increased severance and/or other taxes;
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cyber attacks;
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legal challenges or lawsuits;
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negative publicity about QEP;
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increased costs of doing business;
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reduction in demand for QEP's products; and
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other adverse effects on QEP's ability to develop its properties and increase production.
QEP may incur substantial costs associated with responding to these initiatives or complying with any resulting additional legal or regulatory requirements that are not adequately provided for and could have a material adverse effect on its business, financial condition and results of operations.
QEP's use of derivative instruments to manage exposure to uncertain prices could result in financial losses or reduce its income. QEP uses commodity-price derivative arrangements to reduce exposure to the volatility of gas, oil, and NGL prices, and to protect cash flow and returns on capital from downward commodity price movements. To the extent the Company enters into commodity derivative transactions, it may forgo some or all of the benefits of commodity price increases. Additional financial regulations may change QEP's reporting and margining requirements relating to such instruments. Furthermore, QEP's use of derivative instruments through which it attempts to reduce the economic risk of its participation in commodity markets could result in increased volatility of QEP's reported results. Changes in the fair values (gains and losses) of derivatives are recorded in QEP's income, which creates the risk of volatility in earnings even if no economic impact to QEP has occurred during the applicable period. QEP has incurred significant unrealized gains and losses in prior periods and may continue to incur these types of gains and losses in the future.
QEP enters into commodity-price derivative arrangements with credit-worthy counterparties (banks and energy-trading firms) that do not require collateral deposits. QEP is exposed to the risk of counterparties not performing. The amount of credit available may vary depending on QEP's counterparty's assessment of QEP's credit risk.
Relative changes in NGL and gas prices may adversely impact QEP's results due to changes in the frac spread. Approximately 18%, 23% and 30% of QEP Field Services' net operating revenues for the years ended December 31, 2013, 2012 and 2011, respectively, were derived from keep-whole processing agreements. Under QEP's keep-whole processing contracts, QEP is exposed to the frac spread and transportation and fractionation exposure from firm transportation constraints. Generally, the frac spread and, consequently, the net operating margins are positive under these contracts. In the event gas becomes more expensive on a Btu equivalent basis than NGL products, QEP's cost of keeping the producer "whole" would result in operating losses. Due to timing of gas purchases and liquid sales, direct exposure to changes in market prices of either gas or liquids can be created, because there is an offsetting purchase or sale that remains exposed to market pricing. Through QEP's marketing and derivatives activity, direct exposure may occur naturally or QEP may choose direct price exposure to either gas or liquids when QEP favors that exposure over frac spread risk. Given that QEP has derivative positions, adverse movement in prices to the positions QEP has taken will negatively impact results.
QEP has made significant investments in new cryogenic gas processing plants in its Northern Region (Rockies) in recent years. The expected returns on these investments depend in large part on the future ethane price and margin, which historically have been more volatile than the price of other NGL products, including propane, butane and gasoline. QEP's competitors have also made significant investments in gas processing plants that recover significant volumes of ethane. The U.S. ethane market is currently oversupplied, and probably will remain oversupplied in the foreseeable future, resulting in lower ethane prices.
QEP faces significant competition and certain of its competitors have resources in excess of QEP's available resources. QEP operates in the highly competitive areas of oil and gas exploration, exploitation, acquisition and production. QEP faces competition from:
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large multi-national, integrated oil companies;
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U.S. independent oil and gas companies;
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service companies engaging in oil and gas exploration and production activities; and
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private equity funds investing in oil and gas assets.
QEP faces competition in a number of areas such as:
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acquiring desirable producing properties or new leases for future exploration;
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marketing its gas, oil and NGL production;
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obtaining the equipment and expertise necessary to operate and develop properties; and
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attracting and retaining employees with certain critical skills.
Certain of QEP's competitors have financial and other resources in excess of those available to QEP. Such companies may be able to pay more for oil and gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than QEP's financial or human resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than QEP is able to offer. This highly competitive environment could have an adverse impact on QEP's business.
QEP may be unable to make acquisitions, successfully integrate acquired businesses and/or assets, or adjust to the effects of divestitures, causing a disruption to its business. One aspect of QEP's business strategy calls for acquisitions of businesses and assets that complement or expand QEP's current business, such as QEP's acquisition in the Williston Basin completed in September 2012 and its Permian Basin Acquisition completed in February 2014. QEP cannot provide assurance that it will be able to identify additional acquisition opportunities. Even if QEP does identify additional acquisition opportunities, it may not be able to complete the acquisitions due to capital constraints. Any acquisition of a business or assets involves potential risks, including, among others:
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difficulty integrating the operations, systems, management and other personnel and technology of the acquired business with QEP's own;
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the assumption of unidentified or unforeseeable liabilities, resulting in a loss of value;
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the inability to hire, train or retain qualified personnel to manage and operate QEP's growing business and assets; or
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a decrease in QEP's liquidity to the extent it uses a significant portion of its available cash or borrowing capacity to finance acquisitions or operations of the acquired properties.
Organizational modifications due to acquisitions, divestitures or other strategic changes can alter the risk and control environments, disrupt ongoing business, distract management and employees, increase expenses and adversely affect results of operations. Even if these challenges can be dealt with successfully, the anticipated benefits of any acquisition, divestiture or other strategic change may not be realized.
In addition, QEP’s credit agreements and the indentures governing QEP’s senior notes impose certain limitations on QEP's ability to enter into mergers or combination transactions. QEP’s credit agreements also limit QEP’s ability to incur certain indebtedness, which could indirectly limit QEP’s ability to engage in acquisitions of businesses.
QEP may be unable to dispose of non-core, non-strategic assets on financially attractive terms, resulting in reduced cash proceeds. QEP's business strategy also includes sales of non-core, non-strategic assets. QEP continually evaluates its portfolio of assets related to capital investments, divestitures and joint venture opportunities such as QEP's current plans to sell non-core E&P assets located in the Midcontinent during 2014. Various factors can materially affect QEP's ability to dispose of assets on terms acceptable to QEP. Such factors include current commodity prices, laws, regulations and the permitting process impacting oil and gas operations in the areas where the assets are located, willingness of the purchaser to assume certain liabilities such as asset retirement obligations, QEP's willingness to indemnify buyers for certain matters, and other factors.
Inability to achieve a desired price for assets, or underestimation of amounts of retained liabilities or indemnification obligations, can result in a reduction of cash proceeds, a loss on sale due to an excess of the asset's net book value over proceeds, or liabilities that must be settled in the future at amounts that are higher than QEP had expected.
The potential separation of QEP’s midstream business may not achieve its intended results. In December 2013, QEP announced its intention to pursue a separation of its midstream business. QEP may not be successful in consummating such a transaction. If QEP does consummate the separation of its midstream business, the separation may not achieve its intended results and could have an adverse effect on QEP due to a number of factors. For example, the separation may significantly reduce the scope and scale of QEP’s business, QEP may not be able to grow as expected and QEP may incur proportionately higher costs to operate.
QEP is involved in legal proceedings that may result in substantial liabilities. Like many oil and gas companies, QEP is involved in various legal proceedings, such as title, royalty, and contractual disputes, in the ordinary course of its business. The cost to settle legal proceedings or satisfy any resulting judgment against QEP in such proceedings could result in a substantial liability, which could materially and adversely impact QEP's cash flows and operating results for a particular period. Current accruals for such liability may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal proceedings could change from one period to the next and such changes could be material.
Failure of the Company's controls and procedures to detect errors or fraud could seriously harm its business and results of operations. QEP's management, including its chief executive officer and chief financial officer, does not expect that the Company's internal controls and disclosure controls will prevent all possible errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are being met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls are evaluated relative to their costs. Because of the inherent limitations in all control systems, no evaluation of QEP's controls can provide absolute assurance that all control issues and instances of fraud, if any, in the Company have been detected. The design of any system of controls is based in part upon the likelihood of future events, and there can be no assurance that any design will succeed in achieving its intended goals under all potential future conditions. Over time, a control may become inadequate because of changes in conditions or the degree of compliance with its policies or procedures may deteriorate. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur without detection.
QEP is subject to complex federal, state, tribal, local and other laws and regulations that could adversely affect its cost of doing business and recording of proved reserves. QEP's operations are subject to extensive federal, state, tribal and local tax, energy, environmental, health and safety laws and regulations. The failure to comply with applicable laws and regulations can result in substantial penalties and may threaten the Company's authorization to operate.
Environmental laws and regulations are complex, change frequently and have tended to become more onerous over time. The regulatory burden on the Company's operations increases its cost of doing business and, consequently, affects its profitability. In addition to the costs of compliance, substantial costs may be incurred to take corrective actions at both owned and previously owned facilities. Accidental spills and leaks requiring cleanup may occur in the ordinary course of QEP's business. As standards change, the Company may incur significant costs in cases where past operations followed practices that were considered acceptable at the time, but now require remedial work to meet current standards. Failure to comply with these laws and regulations may result in fines, significant costs for remedial activities, or injunctions that could limit the scope of QEP's planned operations.
Current federal regulations restrict activities during certain times of the year on significant portions of QEP Energy leasehold in the Northern Region due to wildlife activity and/or habitat. QEP Energy has worked with federal and state officials in Wyoming to obtain authorization for limited winter-drilling activities on the Pinedale Anticline and has developed measures, such as drilling multiple wells from a single pad location, to minimize the impact of its activities on wildlife and wildlife habitat in its operations on federal lands. Various wildlife species inhabit QEP Energy's leaseholds at Pinedale and in other areas. The presence of wildlife or plants, including species that are protected under the federal Endangered Species Act, could limit access to leases held by QEP Energy on public and other lands. Many of QEP's operations are subject to the requirements of the National Environmental Policy Act (NEPA), and are therefore evaluated under NEPA for their direct, indirect and cumulative environmental impacts. This is done in Environmental Assessments or Environmental Impact Statements prepared for a lead agency under Council on Environmental Quality and other agency regulations, usually for the BLM in the areas where QEP operates currently. In September 2008, the BLM issued a Record of Decision (ROD) on the Final Supplemental Environmental Impact Statement (FSEIS) for long-term development of gas resources in the Pinedale Anticline Project Area (PAPA). Under the ROD, QEP Energy is allowed to drill and complete wells year-round in one of five Concentrated Development Areas
defined in the PAPA. The ROD contains additional requirements and restrictions on development of the PAPA to which QEP Energy is subject.
New federal Clean Air Act regulations at 40 CFR Part 63, Subpart OOOO impose additional air quality controls and requirements upon QEP Energy’s and QEP Field Services’ operations, and are undergoing further reconsideration by EPA. Additionally, many states are adopting more stringent air permitting and other air quality control regulations specific to oil and gas exploration, production, gathering and processing that go beyond the requirements of federal regulations.
Several of QEP Field Services' transportation facilities are subject to FERC jurisdiction, and as such, are subject to specific regulations regarding interstate transmission facilities and activities, including but not limited to rates charged for transmission, open access/non-discrimination rules, and public daily capacity and flow reporting requirements. Additionally, FERC has jurisdiction over the operation of QEP Marketing's Clear Creek storage facility by virtue of the facility's connection to interstate pipelines (also subject to FERC jurisdiction) at both its inlet and outlet. Clear Creek is subject to specific FERC regulations governing interstate transmission facilities and activities, including but not limited to rates charged for transmission, open access/non-discrimination, and public disclosure via an electronic bulletin board of daily capacity and flows.
Section 1(b) of the Natural Gas Act exempts gathering activities from regulation or jurisdiction by the FERC. QEP owns, or holds interests in, a number of pipelines that it believes meet the tests FERC has used to determine a pipeline system's status as a non-jurisdictional gatherer. There is, however, no bright-line test for determining jurisdictional status of QEP Field Services' gathering systems, so the distinction between non-jurisdictional gathering and FERC-regulated transmission pipelines may from time-to-time be the subject of disputes and litigation. QEP Field Services therefore cannot guarantee that the jurisdictional status of its gathering systems will remain unchanged. QEP's gas gathering systems are not currently subject to state utility regulations. The FERC has jurisdiction under the Energy Policy Act of 2005 to impose rules and regulations applicable to all natural gas market participants to ensure market transparency.
Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation. The U.S. President's Fiscal Year 2014 Budget Proposal includes provisions that, if enacted into law, would eliminate certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These changes include (i) the repeal of the percentage depletion allowance for oil and gas wells, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and development and increase the cost of exploration and development of oil and gas resources.
Environmental laws are complex and potentially burdensome for QEP's operations. QEP must comply with numerous and complex federal, state and tribal environmental regulations governing activities on federal, state and tribal lands, notably including the Clean Air Act, the Clean Water Act, the SDWA, OPA, CERCLA, RCRA, NEPA, the Endangered Species Act, the National Historic Preservation Act and similar state laws and tribal codes. Federal, state and tribal regulatory agencies frequently impose conditions on the Company's activities under these laws. These restrictions have become more stringent over time and can limit or prevent exploration and production on significant portions of the Company's leasehold. These laws also allow certain environmental groups to oppose drilling on some of QEP's federal and state leases. These groups sometimes sue federal and state regulatory agencies and/or the Company under these laws for alleged procedural violations in an attempt to stop, limit or delay oil and gas development on public and other lands.
QEP may not be able to obtain the permits and approvals necessary to continue and expand its operations. Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. It may be costly and time consuming to comply with requirements imposed by these authorities and compliance may result in delays in the commencement or continuation of the Company's exploration and production and midstream field services operations. For example, QEP's drilling operations on tribal lands within the Williston Basin in North Dakota and Vermillion Basin in Wyoming continue to be delayed due to substantial backlog of permit applications. Further, the public may comment on and otherwise seek to influence the permitting process, including through intervention in the courts. Accordingly, necessary permits may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements that restrict QEP's ability to conduct its operations or to do so profitably.
Federal and state hydraulic fracturing legislation or regulatory initiatives could increase QEP's costs and restrict its access to oil and gas reserves. 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 and operation. The EPA recently asserted federal
regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the federal SDWA and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. The EPA appears to be considering its existing regulatory authorities for possible avenues to further regulate hydraulic fracturing fluids and/or the components of those fluids. Additionally, the Bureau of Land Management proposed in May 2012, new regulations regarding chemical disclosure requirements and other regulations specific to well stimulation activities, including hydraulic fracturing, on federal and tribal lands and proposed further revision to those regulations in May 2013. Legislation has also been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process, notwithstanding the proposed and ongoing rulemaking proceedings noted above. At the state level, some states have adopted and other states are considering adopting regulations that could restrict hydraulic fracturing in certain circumstances. In the event that new or more stringent federal, state or local regulations, restrictions or moratoria are adopted in areas where QEP operates, QEP could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling or stimulating wells in some areas.
QEP's ability to produce oil and gas economically and in commercial quantities could be impaired if it is unable to acquire adequate supplies of water for its drilling and completion operations or is unable to dispose of or recycle the water or other waste at a reasonable cost and in accordance with applicable environmental rules. The hydraulic fracture stimulation process on which QEP depends to produce commercial quantities of oil and gas requires the use and disposal of significant quantities of water. The availability of disposal wells with sufficient capacity to receive all of the water produced from QEP’s wells may affect QEP’s production. QEP's inability to secure sufficient amounts of water, or to dispose of or recycle the water used in its operations, could adversely impact its operations. As noted above, the imposition of new environmental initiatives and regulations could include restrictions on QEP's ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of gas. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase QEP's operating costs and cause delays, interruptions or termination of its operations, the extent of which cannot be predicted.
The adoption of greenhouse gas (GHG) emission or other environmental legislation could result in increased operating costs, delays in obtaining air pollution permits for new or modified facilities, and reduced demand for the gas, oil and NGL that QEP produces. Federal and state courts and administrative agencies are considering the scope and scale of climate-change regulation under various laws pertaining to the environment, energy use and development. Federal, state and local governments may also pass laws mandating the use of alternative energy sources, such as wind power and solar energy, which may reduce demand for oil and gas. QEP's ability to access and develop new oil and gas reserves may be restricted by climate-change regulation, including GHG reporting and regulation. Legislative bills have been proposed in Congress that would regulate GHG emissions through a cap-and-trade system under which emitters would be required to buy allowances for offsets of emissions of GHG. The EPA has adopted final regulations for the measurement and reporting of GHG emitted from certain large facilities. Additionally, the EPA and authorized states have begun the permitting of major sources of GHG under the Clean Air Act pursuant to the EPA's GHG Tailoring Rule whereby new and existing sources of GHG emitting above major source thresholds are required to obtain major source permits. In addition, several of the states in which QEP operates are considering various GHG registration and reduction programs, including methane leak detection monitoring and repair requirements specific to upstream and midstream oil and gas operations. While additional climate-change regulation is possible at the federal level, it is too early to predict how such regulation would affect QEP's business, operations or financial results. It is uncertain whether QEP's operations and properties, located in the Northern and Southern Regions of the United States, are exposed to possible physical risks, such as severe weather patterns, due to climate change that may or may not be the result of anthropogenic emissions of GHG. Management does not, however, believe such physical risks are reasonably likely to have a material effect on the Company's financial condition or results of operations.
The adoption and implementation of new statutory and regulatory requirements for swap transactions could have an adverse impact on QEP's ability to mitigate risks associated with its business and increase the working capital requirements to conduct these activities. The Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act), enacted in July 2010, provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market. The Dodd-Frank Act mandates that the Commodity Futures Trading Commission (CFTC), adopt rules and regulations implementing the Dodd-Frank Act and further defining certain terms used in the Dodd-Frank Act. The Dodd-Frank Act also requires the CFTC and the prudential banking regulators to establish margin requirements for certain uncleared swaps. Although there is an exception from swap clearing and trade execution requirements for commercial end-users that meet certain conditions (the End-User Exception), certain market participants, including most if not all of QEP’s counterparties, will also be required to clear many of their swap transactions with entities that do not satisfy the End-User Exception and will have to transact many of their swaps on swap execution facilities or designated contract markets, rather than over-the-counter on a bilateral basis. These requirements may increase the cost to QEP’s counterparties of hedging the swap positions they enter into with us, and thus may increase the cost to
QEP of entering into hedges. The changes in the regulation of swaps may result in certain market participants deciding to curtail or cease their derivatives activities. While many regulations have been promulgated and are already in effect, the rulemaking and implementation process is ongoing, and the ultimate effect of the adopted rules and regulations and any future rules and regulations on QEP’s business remains uncertain.
QEP qualifies as a "non-financial entity" for purposes of the End-User Exception and will seek to satisfy the other requirements of the End-User Exception on an ongoing basis. As a result, QEP does not expect its hedging activity to be subject to mandatory clearing.
A rule adopted under the Dodd-Frank Act imposing position limits in respect of transactions involving certain commodities, including oil and gas, was vacated and remanded to the CFTC for further proceedings by order of the United States District Court for the District of Columbia on September 28, 2012. The CFTC appealed this decision and on November 5, 2013, filed a consensual motion to dismiss its appeal. The same day, the CFTC proposed a new position limits rule which would limit trading in certain oil and gas related derivative contracts. Comments on the proposed rule are due February 10, 2014. QEP cannot predict whether or when the proposed rule will be adopted or the effect of the proposed rule on QEP’s business. The Dodd-Frank Act and the rules promulgated thereunder could significantly increase the cost of derivative contracts (including through requirements to post collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks QEP encounters, reduce QEP’s ability to monetize or restructure QEP’s existing derivative contracts, increase the administrative burden and regulatory risk associated with entering into certain derivative contracts, and increase QEP’s exposure to less credit-worthy counterparties. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil and gas. QEP revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material and adverse effect on QEP’s business, financial condition and results of operations.
QEP relies on highly skilled personnel and, if QEP is unable to retain or motivate key personnel, hire qualified personnel, or transfer knowledge from retiring personnel, QEP’s operations may be negatively impacted. QEP’s performance largely depends on the talents and efforts of highly skilled individuals. QEP’s future success depends on its continuing ability to identify, hire, develop, motivate, and retain highly skilled personnel for all areas of its organization. Competition in the oil and gas industry for qualified employees is intense. QEP’s continued ability to compete effectively depends on its ability to attract new employees and to retain and motivate its existing employees. QEP does not have employment agreements with or maintain key-man insurance for its key management personnel. The loss of services of one or more of its key management personnel could have a negative impact on QEP’s financial condition and results of operations.
In certain areas of QEP’s business, institutional knowledge resides with employees who have many years of service. As these employees retire, QEP may not be able to replace them with employees of comparable knowledge and experience. QEP’s efforts at knowledge transfer could be inadequate. If knowledge transfer, recruiting and retention efforts are inadequate, access to significant amounts of internal historical knowledge and expertise could become unavailable to QEP and could negatively impact QEP’s business.
General economic and other conditions impact QEP's results. QEP's results may also be negatively affected by: changes in global economic conditions; availability and economic viability of oil and gas properties for sale or exploration; rate of inflation and interest rates; assumptions used in business combinations; weather and natural disasters; changes in customers' credit ratings; competition from other forms of energy, other pipelines and storage facilities; effects of accounting policies issued periodically by accounting standard-setting bodies; and terrorist attacks or acts of war.
The Company's pension plans are currently underfunded and may require large contributions, which may divert funds from other uses. QEP has a closed defined benefit pension plan that covers 128, or 13%, of QEP's active employees and 86 participants that are retired, terminated and vested, or suspended. Over time, periods of declines in interest rates and pension asset values may result in a reduction in the funded status of the Company's pension plans. As of December 31, 2013 and 2012, QEP's pension plans were underfunded by $46.3 million and $74.4 million, respectively. The underfunded status of QEP's pension plans may require that the Company make large contributions to such plans. QEP made cash contributions of $11.5 million and $6.9 million during the years ended December 31, 2013 and 2012, respectively, to its defined benefit pension plans and expects to make contributions of approximately $13.8 million to its pension plans in 2014. QEP cannot, however, predict whether changing economic conditions, the future performance of assets in the plans or other factors will require the Company to make contributions in excess of its current expectations, diverting funds QEP would otherwise apply to other uses.
A failure in QEP’s information technology infrastructure or applications could negatively affect QEP’s business.
QEP is planning to have a new enterprise resource planning (ERP) system to further enhance operating efficiencies and provide more effective management of its business operations in 2014. Implementing a new ERP system is costly and involves risks inherent in the conversion to a new computer system, including loss of information, disruption to QEP’s normal operations, changes in accounting procedures and internal control over financial reporting, as well as problems achieving accuracy in the conversion of electronic data. Failure to properly or adequately address these issues could result in increased costs and the diversion of management’s and employees’ attention and resources and could materially adversely affect QEP’s operating results, internal controls over financial reporting and ability to manage its business effectively. While the ERP system is intended to further improve and enhance QEP’s information systems, large scale implementation of a new information system exposes QEP to the risks of starting up the new system and integrating that system with QEP’s existing systems and processes, including possible disruption of QEP’s financial reporting, which could lead to a failure to make required filings under the federal securities laws on a timely basis.
QEP is subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss. The oil and gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, and processing activities. For example, QEP depends on digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering and processing systems, conduct reservoir modeling and reserves estimation, and process and record financial and operating data. Pipelines, refineries, power stations and distribution points for both fuels and electricity are becoming more interconnected by computer systems. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. QEP's technologies, systems, networks, and those of its vendors, suppliers and other business partners may become the target of cyber attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of its business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. QEP's systems and insurance coverage for protecting against cyber security risks may not be sufficient.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
Exploration and Production - QEP Energy
QEP's exploration and production business is conducted through QEP Energy in two core regions - the Northern Region (including the states of Wyoming, Utah, Colorado and North Dakota) and the Southern Region (including the states of Oklahoma, Texas and Louisiana).
Northern Region
Pinedale
QEP's largest property, in terms of proved reserves, is Pinedale, where the Company is targeting the Lance Pool tight gas sand reservoir. The top of the Lance Pool reservoir ranges from 8,500 to 9,500 feet across QEP Energy's acreage. The Company currently estimates that there are over 600 additional wells required to fully develop its Pinedale acreage on 5 to 10-acre density. At December 31, 2013, QEP Energy had four operated rigs drilling in the Pinedale Anticline. In addition to QEP Energy's 798 gross producing wells, QEP Energy has an overriding royalty interest in an additional 50 wells at Pinedale.
Williston Basin
QEP has approximately 116,000 net acres of leaseholds in the Williston Basin in western North Dakota, where the Company is targeting the Bakken and Three Forks formations. During the third quarter of 2012, QEP Energy closed the acquisition of oil and gas properties in the Williston Basin (the 2012 Acquisition), which added 27,600 net acres of producing leasehold. The top of the Bakken Formation ranges from approximately 9,500 feet to 10,000 feet across QEP Energy's leasehold. The Three Forks Formation lies approximately 60 to 70 feet below the Middle Bakken Formation and is also a target for horizontal drilling. As of December 31, 2013, QEP Energy had eight operated rigs drilling in the Williston Basin.
Since the 2012 Acquisition, the Company has been successful in lowering development well costs, de-risking unproven reserves, and increasing production, the number of future drilling locations and its estimate of recoverable reserves. In spite of completion delays due to downstream and weather-related issues, current Williston Basin oil production has grown to levels consistent with the Company's expectations at the time of the acquisition.
Uinta Basin
The majority of the Uinta Basin proved reserves are found in a series of vertically stacked, laterally discontinuous reservoirs at depths of 4,500 feet to deeper than 18,000 feet. QEP Energy owns working interests in approximately 257,000 net leasehold acres in the Uinta Basin. QEP Energy had one operated rig drilling in the Uinta Basin at December 31, 2013, targeting the Lower Mesaverde Formation productive fairway in the Red Wash Unit, in which QEP holds 32,300 net acres.
Legacy
The remainder of QEP Energy Northern Region leasehold interests, productive wells and proved reserves are distributed over a number of fields and properties managed as Legacy.
Southern Region
Haynesville/Cotton Valley
QEP Energy has approximately 50,500 net acres of Haynesville Shale leaseholds in northwest Louisiana and additional lease rights that cover the Hosston and Cotton Valley formations. The top of the Haynesville Shale ranges from approximately 10,500 feet to 12,500 feet across QEP Energy's leasehold and is below the Hosston and Cotton Valley formations that QEP Energy has been developing in northwest Louisiana since the 1990's. As of December 31, 2013, QEP Energy did not have any operated rigs drilling in the Haynesville/Cotton Valley area.
Midcontinent
QEP Energy's Midcontinent operations cover all properties in the Southern Region except the Haynesville/Cotton Valley area of northwest Louisiana and are distributed over a large area, including the Anadarko Basin of Oklahoma and the Texas Panhandle.
QEP Energy has approximately 76,000 net acres of Woodford "Cana" Shale leaseholds in western Oklahoma. The top of the Woodford Shale ranges from approximately 10,500 feet to 14,500 feet across QEP Energy's leasehold. As of December 31, 2013, QEP Energy had two operated rigs drilling in the Woodford/Cana play.
QEP Energy has approximately 35,000 net acres of Granite Wash/Atoka Wash leaseholds in the Texas Panhandle and western Oklahoma and has been drilling vertical Granite Wash/Atoka Wash wells for over a decade. The top of the Granite Wash/Atoka Wash interval ranges from approximately 11,100 feet to 15,900 feet across QEP Energy's leasehold. As of December 31, 2013, QEP Energy did not have any operated rigs drilling in the Texas Panhandle.
Reserves - QEP Energy
At December 31, 2013 and 2012, approximately 89% and 91%, respectively, of QEP Energy's estimated proved reserves were Company operated. Proved developed reserves represented 53% and 54% of the Company's total proved reserves at December 31, 2013 and 2012, respectively, while the remaining reserves were classified as proved undeveloped. All reported reserves are located in the United States. QEP Energy does not have any long-term supply contracts with foreign governments, reserves of equity investees or reserves of subsidiaries with a significant minority interest. QEP Energy's estimated proved reserves are summarized in the table below:
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(1)
Oil and NGL are converted to natural gas equivalents at the ratio of one bbl of crude oil, condensate or NGL to six Mcf of equivalent natural gas.
QEP Energy's reserve, production and production life index for each of the years ended December 31, 2011, through December 31, 2013, are summarized in the table below:
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(1)
Reserve life index is calculated by dividing year-end proved reserves by production for that year.
Proved Reserves
Reserve and related information is presented consistent with the requirements of the SEC's rules for the Modernization of Oil and Gas Reporting. These rules expand the use of reliable technologies to estimate and categorize reserves and require the use of the average of the first-of-the-month commodity prices, adjusted for location and quality differentials, for the prior 12 months (unless contractual arrangements designate the price) used to calculate economic producibility of reserves and the discounted cash flows reported as the Standardized Measure of Future Net Cash Flows Relating to Proved Reserves. Refer to Note 17 - Supplemental Oil and Gas Information (Unaudited), in Item 8 of Part II of this Annual Report for additional information regarding estimates of proved reserves and the preparation of such estimates.
QEP Energy's proved reserves in major operating areas are summarized in the table below:
Estimates of the quantity of proved reserves increased during 2013 primarily related to reserve additions in the Williston Basin, offset by decreases in estimated Haynesville/Cotton Valley and Legacy proved reserves. The increase in Williston Basin reserves was primarily the result of extensions and additions from the recognition of additional proved undeveloped locations due to QEP's increased drilling program. The Haynesville/Cotton Valley decrease was primarily related to changes in performance estimates based on well performance during 2013 as well as the natural decline in reserves from production without reserve replacement from the lack of new wells being drilled. Legacy's proved reserves decreased as a result of property divestitures in 2013.
Proved Undeveloped Reserves
Significant changes to proved undeveloped reserves (PUDs) that occurred during 2013 are summarized in the table below:
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(1)
Negative revisions were caused by a change in well spacing assumptions in Pinedale and Haynesville. Some more densely spaced wells were removed from the Company’s reserves. However, certain less densely spaced wells with higher estimates of recoverable oil and gas were rebooked as extensions and discoveries. Negative revisions were also partially offset by positive pricing-related revisions due to increased oil and gas prices during 2013.
(2)
Extensions and discoveries in 2013 increased proved undeveloped reserves due to extensions and discoveries of 263.9 Bcfe in Pinedale, 169.6 Bcfe in the Williston Basin, 170.3 Bcfe in Haynesville, and 83.9 Bcfe in Midcontinent. Extensions and discoveries in Pinedale and Haynesville related to certain less densely spaced wells with higher estimates of recoverable oil and gas, which were rebooked to replace wells removed from the Company's reserves through negative revisions caused by a change in well spacing assumptions in these areas.
(3)
All of QEP Energy's PUDs at December 31, 2013, are scheduled to be developed within five years from the date such locations were initially booked as PUDs, except for 120 Bcfe of reserves located within the northern portion of the Company's Pinedale Anticline leasehold in western Wyoming. Long-term development of gas reserves in Pinedale is governed by the BLM's September 2008 ROD on the FSEIS. Under the ROD, QEP Energy is allowed to drill and complete wells year-round in designated concentrated development areas. The ROD contains additional requirements and restrictions on the sequence of development, which require the Company to develop its leasehold from the south to the north. These restrictions result in protracted, phased development that is beyond the control of the Company. The Company has an ongoing development plan and the financial capability to continue development in the manner estimated.
The costs incurred to continue the development of PUDs were approximately $645.9 million, $513.0 million and $533.6 million for the years ended December 31, 2013, 2012 and 2011, respectively. The costs incurred in 2013 related to the drilling of PUDs in QEP's development projects. This investment resulted in the transfer in 2013 of 332.7 Bcfe of reserves from PUDs to proved developed reserves, representing 18% of the Company's total proved undeveloped reserves as of December 31, 2012.
Estimated future development costs relating to the development of PUDs are projected to be approximately $852.6 million in 2014, $1.2 billion in 2015, and $1.1 billion in 2016. Estimated future development costs include capital spending on major development projects, some of which will take several years to complete. PUDs related to major development projects will be reclassified to proved developed reserves when production commences.
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 compliance oversight of a multi-functional reserves review committee reporting to the Company's Board of Directors. The Company retained Ryder Scott Company, independent oil and gas reserve evaluation engineering consultants (Ryder Scott), to prepare the estimates of 100% of its proved reserves as of December 31, 2013, 2012 and 2011. The individual at Ryder Scott who was responsible for overseeing the preparation of QEP's reserve estimates as of December 31, 2013, 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 30 years experience in the Petroleum Industry, including experience estimating and evaluating petroleum reserves. A more detailed letter of the individual's professional qualifications has been filed as part of Exhibit 99.1 to this report.
The individual at QEP responsible for insuring the accuracy of the reserve estimate preparation material provided to Ryder Scott and reviewing the estimates of reserves received from Ryder Scott is QEP's Chief Engineer. This individual is a member of the Society of Petroleum Engineers and graduated with a Bachelors of Science degree in Geological Engineering from South Dakota School of Mines and Technology in 1979. He is a registered Professional Petroleum Engineer in the state of
Colorado. This individual has over 30 years experience in the Petroleum Industry, including more than 20 years reservoir engineering experience in most of the active domestic basins in the U.S.
To establish reserves, the SEC allows a company to use technologies that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. A variety of methodologies were used to determine QEP's proved reserve estimates. The principal methodologies employed are performance, analogy, volumetric methods or a combination of methods.
All of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods. Performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of historical production data available through December 2013 in those cases where such data were considered to be definitive. For wells currently in production, forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.
Approximately 99% of QEP's proved developed non-producing and undeveloped reserves included in this Annual Report on Form 10-K were estimated by analogy. The remaining one percent of such reserves was estimated by the volumetric method. The volumetric analysis utilized pertinent well data furnished to Ryder Scott by QEP or obtained from available public data sources through December 2013. 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, producing market demand and/or allowables or other constraints set by regulatory bodies. Some combination of these methods is used to determine reserve estimates in substantially all of QEP's fields.
Refer to Note 17 - Supplemental 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 Energy's proved reserves as of the end of each of the last three years.
In addition to this filing, QEP Energy will file reserves estimates as of December 31, 2013, with the Energy Information Administration of the Department of Energy on Form EIA-23. Although QEP uses the same technical and economic assumptions when it prepares the EIA-23 as used to estimate reserves for this Annual Report on Form 10-K, it is obligated to report reserves for only wells it operates, not for all of the wells in which it has an interest, and to include the reserves attributable to other owners in such wells.
Production, Prices and Production Costs
The following table sets forth the net production volumes and field-level prices of gas, oil and NGL produced, and the related operating expenses for the years ended December 31, 2013, 2012 and 2011:
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(1) The average field-level price does not include the impact of settled commodity price derivatives.
A summary of gas production by major geographical area is shown in the following table:
A summary of oil production by major geographical area is shown in the following table:
A summary of NGL production by major geographical area is shown in the following table:
A summary of natural gas equivalent total production by major geographical area is shown in the following table:
A regional comparison of average field-level prices is shown in the following table:
Northern Region
Pinedale
Production from the Pinedale Anticline decreased 5% to 94.7 Bcfe during 2013 compared to 2012. This decrease in production was primarily a result of lower NGL production due to operating in ethane rejection mode throughout the majority of 2013 compared to operating in ethane recovery throughout the majority of 2012. Additionally, QEP had lower average interest in wells drilled in the 2013 drilling program.
Production from Pinedale grew 26% to 99.7 Bcfe during 2012 compared to 2011, driven by increased drilling activity over the period and the fee-based processing agreement at Blacks Fork II entered into in the third quarter of 2011 between QEP Energy and QEP Field Services.
During the years ended December 31, 2013, 2012 and 2011, Pinedale's production represented 31%, 31%, and 29% of QEP Energy's total production, respectively.
Williston Basin
In the Williston Basin, production increased 133% to 47.2 Bcfe during 2013 compared to 2012, due to increased oil and NGL production. The increase in production volumes was primarily attributable to the properties acquired in the 2012 Acquisition, which contributed 2,591.6 Mbbls of increased oil and NGL volume. The remaining 1,598.0 Mbbls increase in 2013 related to increased development drilling on QEP's existing pre-acquisition acreage.
During 2012, production increased 186% compared to 2011, due to increased oil-directed drilling activity in the basin. In addition, the 2012 Acquisition contributed 5.2 Bcfe of increased production in the fourth quarter 2012.
During the years ended December 31, 2013, 2012 and 2011, Williston Basin production represented 15%, 6%, and 3% of QEP Energy's total production, respectively.
Uinta Basin
In the Uinta Basin, production increased 13% to 26.9 Bcfe during 2013, due to increased drilling activity in the Lower Mesaverde formation in the Red Wash Unit. NGL production increased 92.7 Mbbl during 2013 compared to 2012, primarily as a result of QEP Energy executing a fee-based cryogenic processing agreement with QEP Field Services for a portion of the Red Wash Unit's gas production in mid-2012, which was partially offset by decreased production related to processing plants running in ethane rejection mode throughout the majority of 2013.
During 2012, production increased 15% due to increased drilling activity in the Lower Mesaverde formation in the Red Wash Unit. NGL production increased 264.7 Mbbl during 2012 compared to 2011, primarily as a result of QEP Energy executing a fee-based cryogenic processing agreement with QEP Field Services for a portion of the Red Wash Unit's gas production in mid-2012.
During the years ended December 31, 2013, 2012 and 2011, Uinta Basin production represented 9%, 7%, and 8%, respectively, of QEP Energy's total production.
Legacy
QEP Energy's Legacy's production decreased 13% to 11.9 Bcfe during 2013 compared to 2012, due to declining production on older wells and divestitures of certain of QEP's noncore properties in the Northern Region during 2013.
Legacy's production decreased 4% to 13.7 Bcfe during the year ended December 31, 2012 compared to 2011, due to declining production on older wells partially offset by increased drilling activity in the Powder River Basin during 2012.
During the years ended December 31, 2013, 2012 and 2011, Legacy's production represented 4% of QEP Energy's total production.
Southern Region
Haynesville/Cotton Valley
Production from the Haynesville Shale and Cotton Valley decreased 36% to 72.2 Bcfe during 2013 when compared to 2012. Decreased production was due to the suspension of QEP's drilling program in the area due to depressed gas prices and QEP's focus on developing more oil rich areas during 2013.
Production from the Haynesville Shale and Cotton Valley increased 4% to 112.3 Bcfe during 2012 when compared to 2011. The increase in 2012 was due to the completion of several high-rate wells in early 2012 that were drilled during the latter half of 2011.
During the years ended December 31, 2013, 2012 and 2011, Haynesville/Cotton Valley's production comprised 23%, 35%, and 39% of QEP Energy's total production, respectively.
Midcontinent
Production in the Midcontinent grew 14% to 56.1 Bcfe during 2013 when compared to 2012, due to a 494.1 Mbbl increase in NGL production and a 4.2 Bcfe increase in gas production offset by decreased oil production of 61.0 Mbbl. The increase in gas and NGL production was driven by several high rate and high working interest well completions in 2013.
Net production in the Midcontinent grew 7% to 49.3 Bcfe during 2012 compared to 2011, driven by a 65% increase in oil production and an 18% increase in NGL production driven by the continued development of the Granite Wash, Marmaton and Tonkawa plays in Texas and western Oklahoma and the Woodford "Cana" Shale liquids-rich gas play in the Anadarko Basin of western Oklahoma.
During the years ended December 31, 2013, 2012 and 2011, Midcontinent's production represented 18%, 15%, and 17% of QEP Energy's total production, respectively.
Productive Wells
The following table summarizes the Company's productive wells as of December 31, 2013, all of which are located in the U.S.:
The term "gross" refers to all wells or acreage in which QEP has at least a partial working interest and the term "net" refers to QEP's ownership represented by that working interest. Although many wells produce both oil and gas, and many gas wells also have allocated NGL volumes from processing, a well is categorized as either a gas or an oil well based upon the ratio of gas to oil produced at the wellhead. Each gross well completed in more than one producing zone is counted as a single well.
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, 2013. "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.
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(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.
Expiring Leaseholds
A portion of the leases summarized in the preceding table will expire at the end of their respective primary terms unless the leases are renewed or drilling or production has occurred on the acreage subject to the lease prior to that date. Leases held by production remain in effect until production ceases. The following table sets forth the gross and net undeveloped acres subject to leases summarized in the preceding table that will expire during the periods indicated:
Drilling Activity
The following table summarizes the number of development and exploratory wells drilled during the years indicated:
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(1)
Following the 2012 Acquisition, the Company began reporting the results of Williston Basin separately from Legacy in 2012. The Legacy well totals for the year ended December 31, 2011, include the total development and exploratory wells drilled in the Williston Basin.
The following table presents operated and non-operated well completions for the year ended December 31, 2013:
The following table presents operated and non-operated wells drilling and waiting on completion at December 31, 2013:
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(1)
QEP suspends Pinedale completion operations during the coldest months of the winter, generally from December to mid-March.
QEP utilizes multi-well pad drilling where practical. Wells drilled are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location. As a result, QEP had 63 gross operated wells waiting on completion as of December 31, 2013.
Delivery Commitments
QEP Energy is a party to various long-term sales commitments for physical delivery of gas with future firm delivery commitments as follows:
These commitments are physical delivery obligations with prices based on prevailing index prices for gas at the time of delivery. None of these commitments requires the Company to deliver gas produced specifically from any of the Company's properties. The Company believes that its production and reserves are adequate to meet these term sales commitments. If for some reason the Company's gas production is not sufficient to satisfy its firm delivery commitments, the Company believes it can purchase sufficient volumes of gas in the market at index-related prices to satisfy its commitments. See also Item 7 "Contractual Cash Obligations and Other Commitments" for discussion of firm transportation and storage commitments related to gas deliveries.
In addition, none of the Company's production from QEP Energy's owned properties is subject to any priorities, proration or third-party imposed curtailments that may affect quantities delivered to its customers, any priority allocations or price limitations imposed by federal or state regulatory agencies, or any other factors beyond the Company's control that may affect its ability to meet its contractual obligations other than those discussed in Item 1A - Risk Factors, in this Annual Report on Form 10-K.
Midstream Field Services - QEP Field Services
QEP Field Services provides midstream services (gathering, processing and treating) to QEP Energy and third-party customers, including major and independent producers. QEP Field Services' physical assets include the following:
•
810 miles of gathering lines in Utah and Louisiana;
•
six processing plants, which extract NGL from the natural gas stream and have an aggregate capacity of 1.52 Bcf per day of unprocessed natural gas;
•
treating facilities in northwest Louisiana which remove impurities from the natural gas stream and have an aggregate capacity of 600 MMcf per day of untreated natural gas;
•
compression facilities and field dehydration and measurement systems; and
•
the UBFS system, which consists of 100 miles of gathering lines and associated field equipment.
In February 2013, QEP Field Services put into service the 150 MMcf per day Iron Horse II cryogenic processing plant, an expansion of its Stagecoach and Iron Horse processing complex in the Uinta Basin of eastern Utah. The plant predominantly provides fee-based processing services to third parties and affiliates. During the third quarter of 2013, QEP Field Services completed the 10,000 Bbl per day expansion of the NGL fractionation facility located at the Blacks Fork processing complex.
QEP Field Services also owns a majority interest in QEP Midstream, a publicly traded master limited partnership that was formed by QEP to own, operate, acquire and develop midstream energy assets. QEP Midstream was formed in 2013 and completed its initial public offering in August 2013. In connection with the IPO, QEP Field Services contributed certain assets to QEP Midstream in exchange for net proceeds of $351.1 million and a 57.8% interest in QEP Midstream. QEP Midstream's assets currently consist of the following:
•
Four gathering systems consisting of 1,129 miles of gathering lines in Wyoming, Colorado, Utah and North Dakota;
•
Rendezvous Pipeline, a FERC regulated 21-mile, 20-inch diameter pipeline that can deliver up to 460 MMcf of natural gas per day to the Kern River Pipeline;
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a 78% interest in Rendezvous Gas, a joint venture consisting of 310 miles of gathering lines and associated field equipment; and
•
a 50% interest in Three Rivers Gathering, a joint venture that consists of 52 miles of gathering lines and associated field equipment.
Delivery Commitments
The Company sells NGL under a term sales agreement that contains a delivery commitment for 8,500 barrels per day of NGL extracted at several of QEP Field Services' gas processing facilities in the Northern Region. The agreement, which became effective May 1, 2010, extends for a period of seven years and contains terms and conditions customary for an agreement of this type in the oil and gas industry. The Company believes that the reserves dedicated to gas processing facilities and projected processing volumes are adequate to satisfy its delivery commitments under this agreement.
Energy Marketing - QEP Marketing
QEP Marketing owns and operates an underground gas storage reservoir in southwestern Wyoming. The reservoir has a gas storage capacity of approximately 8 Bcf, comprised of approximately 4 Bcf of QEP Marketing-owned cushion gas and working gas storage capacity of about 4 Bcf.
Delivery Commitments
QEP Marketing is a party to various long-term sales commitments for physical delivery of gas with future firm delivery commitments as follows:
These commitments are physical delivery obligations with prices based on prevailing index prices for gas at the time of delivery. Historically, QEP Marketing has materially fulfilled its delivery commitments by purchasing and selling QEP Energy's gas production. The Company believes that QEP Energy's gas production and reserves to be sold to QEP Marketing are adequate to meet these term sales commitments. If for some reason QEP Energy's gas production sold to QEP Marketing is not sufficient to satisfy its firm delivery commitments, the Company believes it can purchase sufficient volumes of gas in the market at index-related prices to satisfy its commitments. See also Item 7 "Contractual Cash Obligations and Other Commitments" for discussion of firm transportation and storage commitments related to gas deliveries.
ITEM 3. LEGAL PROCEEDINGS
In the ordinary course of its business, QEP is a defendant in a number of lawsuits and is involved in governmental proceedings and regulatory controls. QEP is also subject to various environmental remediation and reclamation obligations arising from federal, state, and local laws and regulations. While the ultimate outcome and impact on QEP cannot be predicted with certainty, management does not believe that the resolution of pending proceedings will materially affect the Company's consolidated financial position, results of operations, or cash flows.
See Note 10 - Commitments and Contingencies to the consolidated financial statements in Item 8 of Part II of this Annual Report on Form 10-K for disclosures regarding certain legal proceedings.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
QEP's common stock is listed and traded on the New York Stock Exchange (NYSE:QEP). As of January 31, 2014, QEP had 6,792 shareholders of record. The declaration and payment of dividends are at the discretion of QEP's Board of Directors and the amount thereof will depend on QEP's results of operations, financial condition, contractual restrictions, cash requirements, future prospects and other factors deemed relevant by the Company's Board of Directors. The Company expects that cash dividends will continue to be paid in the future.
The following table is a summary of the high and low sales price per share of QEP's common stock as reported on the NYSE as well as the dividends paid per share per quarter for 2013 and 2012:
Stock Performance Graph
The following stock performance information in this Item 5 of this Annual Report on Form 10-K is not deemed to be "soliciting material" or to be "filed" with the SEC or subject to Regulation 14A or 14C under the Securities Exchange Act of 1934 or to the liabilities of Section 18 of the Securities Exchange Act of 1934, and will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent QEP specifically incorporates it by reference into such a filing.
During 2013, the Board of Directors made changes to QEP's peer group to remove EOG Resources due to dissimilar financial characteristics. In addition, Plains Exploration & Production was acquired in 2013 and therefore was removed from the peer group. WPX Energy Inc., Concho Resources, and SM Energy were added to QEP's peer group, which is comprised of US companies of similar size and scope to QEP.
QEP's previous peer group, as defined, consisted of the following companies:
Cabot Oil & Gas Corporation
Pioneer Natural Resources Company
Cimarex Energy Company
Plains Exploration & Production Company
Denbury Resources Inc.
Quicksilver Resources, Inc.
EOG Resources, Inc.
Range Resources Corporation
Forest Oil Corporation
Southwestern Energy Company
Newfield Exploration Company
Ultra Petroleum Corporation
Noble Energy, Inc.
Whiting Petroleum Corporation
After the change in peer companies, the 2013 peer group consisted of the following:
Cabot Oil & Gas Corporation
Pioneer Natural Resources Company
Cimarex Energy Company
Range Resources Corporation
Concho Resources
SM Energy
Denbury Resources Inc.
Southwestern Energy Company
Forest Oil Corporation
Ultra Petroleum Corporation
Newfield Exploration Company
Whiting Petroleum Corporation
Noble Energy, Inc.
WPX Energy, Inc.
Quicksilver Resources, Inc.
The performance presentation shown below is being furnished as required by applicable rules of the SEC and was prepared using the following assumptions:
•
A $100 investment was made in QEP's common stock, the S&P 500 Index, the Company's old peer group and new peer group as of July 1, 2010, which is the date when QEP's common stock began trading on the NYSE;
•
Investment in the Company's old and new peer group was weighted based on the stock market capitalization of each individual company within the peer group at the beginning of each period for which a return is indicated; and
•
Dividends were reinvested on the relevant payment dates.
Recent Sales of Unregistered Securities; Purchases of Equity Securities by QEP and Affiliated Purchasers
The following repurchases of QEP shares were made by QEP in association with vested restricted stock awards withheld for taxes.
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(1)
All of the 20,541 shares purchased during the three-month period ended December 31, 2013, were acquired from employees in connection with the settlement of income tax and related benefit withholding obligations arising from vesting in restricted stock grants. These shares were not part of a publicly announced program to purchase common stock. Stock options that are net settled do not involve the acquisition of any shares.
In January 2014, the Board of Directors of QEP authorized the repurchase of up to $500.0 million of the Company’s outstanding shares of common stock. The timing and amount of any QEP share repurchases will depend upon a number of factors, including general market conditions, the Company’s financial position and the estimated intrinsic value of the Company’s shares. The repurchase plan does not obligate QEP to acquire any specific number of shares and may be discontinued at any time.
ITEM 6. SELECTED FINANCIAL DATA
Selected financial data for the five years ended December 31, 2013, is provided in the table below. Refer to
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide a reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company's operating results. MD&A should be read in conjunction with the consolidated financial statements and related notes included in Item 8 of Part II of this Annual Report on Form 10-K.
The following information updates the discussion of QEP's financial condition provided in its 2012 Annual Report on Form 10-K filing, and analyzes the changes in the results of operations between the years ended December 31, 2013 and 2012, and between the years ended December 31, 2012 and 2011.
OVERVIEW
QEP Resources, Inc. (QEP or the Company) is a holding company with three major lines of business: oil and gas exploration and production (QEP Energy); midstream field services (QEP Field Services, including QEP Midstream); and energy marketing (QEP Marketing).
Outlook
The Company has substantial acreage positions and operations in some of the most prolific hydrocarbon resource plays in the continental United States, including the Williston Basin, Pinedale Anticline, Uinta Basin, Woodford "Cana" shale and Haynesville Shale. These resource plays are characterized by unconventional oil or natural gas accumulations in continuous tight sands or shales that underlie broad geographic areas. The lateral continuity of such resource plays means that aside from wells abandoned due to mechanical issues, the Company does not expect to drill many unsuccessful wells as it develops these resource plays. Resource plays allow the Company the opportunity to gain considerable operational efficiencies through high-density, repeatable drilling and completion operations. The Company has a large inventory of lower-risk, predictable development drilling locations across its acreage holdings in the onshore United States that provide a solid base for consistent growth in organic production and reserves. QEP believes that it has one of the lowest cash operating structures among its exploration and production company peers. However, in certain of its resource plays, QEP, along with its peers, has experienced increased drilling and completion costs which could impact near term drilling plans.
While historically a natural gas producer, the Company has increased its focus on growing the relative proportion of oil and NGL production in its exploration and production business. During 2013, QEP Energy increased its oil and NGL production by 29% compared to 2012. As part of the Company's liquids growth strategy, during the third quarter of 2012, QEP Energy acquired oil and gas properties in the Williston Basin for an aggregate purchase price of $1.4 billion (the 2012 Acquisition). Additionally, during the first quarter of 2014, QEP Energy acquired oil and gas properties in the Permian Basin for an aggregate purchase price of approximately $950.0 million, subject to purchase price adjustments.
While QEP believes that it can grow production and reserves from its extensive inventory of identified drilling locations, the Company continues to evaluate acquisition opportunities that might create significant long-term value. QEP believes that its experience, expertise, and substantial presence in its core operating areas, combined with its low-cost operating model and financial strength, enhance its ability to pursue acquisition opportunities. In addition, the Company will occasionally divest select non-core portfolio assets to redirect capital towards higher-return projects, including $205.8 million of assets sold in 2013. Currently, QEP plans to sell non-core E&P assets located in the Midcontinent during 2014.
QEP owns and operates, directly or through its ownership in QEP Midstream, gathering and natural gas processing and treating facilities in the majority of its core producing areas outside of Oklahoma and Texas. In August 2013, QEP Midstream, a master limited partnership formed by QEP to hold certain midstream gathering assets, completed its IPO. In January 2014, QEP's Board of Directors authorized the Company to develop a plan to separate the business of QEP Field Services, including the Company's interest in QEP Midstream, from QEP.
In January 2014, QEP's Board of Directors authorized the repurchase of up to $500.0 million of the Company's outstanding shares of common shares. The timing and amount of any QEP share repurchases will depend upon a number of factors, including general market conditions, the Company’s financial position and the estimated intrinsic value of the Company’s shares. The repurchase plan does not obligate QEP to acquire any specific number of shares and may be discontinued at any time.
Financial and Operating Results
For the years ended December 31, 2013 and 2012, QEP Energy reported total equivalent production of 309.0 Bcfe and 319.2 Bcfe, respectively, a decrease of 3% and increase of 16% from the respective 2012 and 2011 comparable periods. Oil and NGL production for the years ended December 31, 2013 and 2012, was 15,021.0 Mbbls and 11,655.9 Mbbls, respectively, a combined increase of 29% and 81% when compared to the prior year periods. The Company's 2012 Acquisition contributed 3,447.9 Mbbls of oil and NGL production during the year ended December 31, 2013.
QEP Field Services' gathering throughput volumes for the years ended December 31, 2013 and 2012, were 13% lower and 2% higher, respectively, than the 2012 and 2011 comparable periods. During the years ended December 31, 2013 and 2012, QEP Field Services reported a 37% decrease and a 3% increase in NGL sales volumes, respectively, and a 1% decrease and 4% increase, respectively, in fee-based processing volumes when compared to the prior year periods.
For the years ended December 31, 2013, 2012 and 2011, QEP Energy's average net realized equivalent prices (including realized commodity derivative impact) were $6.59 per Mcfe, $5.48 per Mcfe and $5.72 per Mcfe, respectively. As a result of low ethane prices relative to natural gas prices, QEP Field Services' processing plants, in regard to its keep-whole processing activities, operated in ethane rejection mode (where the majority of ethane is left in the production stream and sold as natural gas) throughout 2013. When in ethane rejection mode, NGL volumes are lower and average NGL prices are higher as a result of the remaining components of the NGL stream having a higher average unit price than ethane. During the year ended December 31, 2013, QEP Field Services' NGL sales volumes declined by 37%, the impact of which was partially offset by an increase in average net realized NGL sales prices of 11% compared to the prior year. During the years ended December 31, 2013, 2012 and 2011, QEP Field Services' fee-based processing rates increased 7%, 27% and 38%, respectively, while fee-based gathering rates were relatively flat during the same periods.
On August 14, 2013, QEP Midstream completed its IPO of 20,000,000 common units, representing limited partner interests in QEP Midstream, at a price to the public of $21.00 per common unit. QEP Midstream received net proceeds of $390.7 million from the sale of the common units, after deducting underwriting discounts and commissions, structuring fees and offering expenses of approximately $29.3 million. Following the IPO, the underwriters exercised their over-allotment option to purchase an additional 3,000,000 common units, at a price of $21.00 per common unit, providing additional net proceeds of $58.9 million, after deducting $4.1 million of underwriters' discounts and commissions and structuring fees, to QEP Midstream. QEP Midstream used the net proceeds to repay its outstanding debt balance with QEP, which was assumed with the assets contributed to QEP Midstream, pay revolving credit facility origination fees and make a cash distribution to QEP, a portion of which was used to reimburse QEP for certain capital expenditures it incurred with respect to assets contributed to QEP Midstream.
QEP contributed gathering assets which are located in, or within close proximity to, the Green River Basin located in Wyoming and Colorado, the Uinta Basin located in eastern Utah, and the Williston Basin located in North Dakota. QEP utilized the proceeds of the cash distribution it received from QEP Midstream in connection with the IPO to fund ongoing operations, to repay debt under the Company's revolving credit facility and for general corporate purposes. Following the IPO, QEP owns a 57.8% ownership interest in QEP Midstream and consolidates QEP Midstream for financial reporting purposes.
Factors Affecting Results of Operations
Oil, Gas, and NGL Prices
Historically, field-level prices received for QEP's gas, NGL, and oil production have been volatile and unpredictable, and that volatility is expected to continue. In recent years, domestic natural gas supply has grown faster than natural gas demand, driven by advances in drilling and completion technologies, including horizontal drilling and multi-stage hydraulic fracturing. These changes have allowed producers to extract increased quantities of natural gas from shale, tight sand formations, and other unconventional reservoirs. Increased natural gas supplies have resulted in downward pressure on natural gas prices, while concern about the global economy and other factors has created volatility in the price of oil. Changes in the market prices for gas, oil, and NGL directly impact many aspects of QEP's business, including its financial condition, revenues, results of operations, planned drilling activity and related capital expenditures, liquidity, rate of growth, and costs of goods and services required to drill and complete wells, and may impact the carrying value of its oil and gas properties.
QEP uses commodity derivatives to reduce the volatility of the prices QEP receives for a portion of its production and to protect cash flow and returns on invested capital from a drop in commodity prices. Generally, QEP intends to enter into commodity derivative contracts for approximately 50% of its forecasted annual production by the end of the first quarter of each fiscal year. At December 31, 2013, assuming 2014 annual production of 295 Bcfe, QEP Energy had approximately 57% of its forecasted total production covered with fixed-price swaps, including 53% of its forecasted gas production and 82% of its forecasted oil production. See
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
QEP’s primary market risk exposures arise from changes in the market price for gas, oil and NGL, and to volatility in interest rates. These risks can affect revenues and cash flows from operating, investing and financing activities. Commodity prices have historically been volatile and are subject to wide fluctuations in response to relatively minor changes in supply and demand. If commodity prices fluctuate significantly, revenues and cash flow may significantly decrease or increase. QEP Energy and QEP Marketing also have long-term contracts for pipeline capacity and are obligated to pay for transportation services with no guarantee that QEP will be able to fully utilize the contractual capacity of these transportation commitments. In addition, a non-cash write-down of the Company’s oil and gas properties may be required if future oil and gas commodity prices experience a sustained, significant decline. Furthermore, the Company’s credit facility and term loan agreement have floating interest rates which expose QEP to interest rate risk. To manage the Company’s exposure to these risks, QEP enters into commodity derivative contracts in the form of fixed-price swaps to manage commodity price risk and periodically interest rate swaps to manage interest rate risk.
Commodity Price Risk Management
QEP uses commodity price derivative instruments in the normal course of business to reduce the risk of adverse commodity price movements. However, these same arrangements typically limit future gains from favorable price movements. The types of commodity derivative instruments currently utilized by the Company are fixed-price swaps. The volume of commodity derivative instruments utilized by the Company may vary from year-to-year based on QEP's forecasted production. The derivative instruments currently utilized by the Company do not have margin requirements or collateral provisions that would require payments prior to the scheduled cash settlement dates. As of December 31, 2013, QEP held commodity price derivative contracts totaling 93.4 million MMBtu of gas and 12.8 million barrels of oil. At December 31, 2012, the QEP derivative contracts covered 139.4 million MMBtu of gas and 6.9 million barrels of oil.
The following table presents open 2014 derivative positions, which includes what was in effect as of December 31, 2013 (see Note 7 - Derivative Contracts, under Part II,
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Financial Statements:
Page No.
Report of Independent Registered Public Accounting Firm as of and for the years ended December 31, 2013 and 2012
Report of Independent Registered Public Accounting Firm for the year ended December 31, 2011
Consolidated Statements of Operations, for the three years ended December 31, 2013
Consolidated Statements of Comprehensive Income (Loss), for the three years ended December 31, 2013
Consolidated Balance Sheets as of December 31, 2013 and 2012
Consolidated Statements of Equity, for the three years ended December 31, 2013
Consolidated Statements of Cash Flows, for the three years ended December 31, 2013
Notes Accompanying the Consolidated Financial Statements
Financial Statement Schedule:
Valuation and Qualifying Accounts, for the three years ended December 31, 2013
All other schedules are omitted because they are not applicable or the required information is shown in the consolidated financial statements or Notes thereto.
Report of Independent Registered Public Accounting Firm
To Board of Directors and Shareholders of QEP Resources, Inc.:
In our opinion, the accompanying consolidated balance sheets and related consolidated statements of operations, comprehensive income, equity, and cash flows present fairly, in all material respects, the financial position of QEP Resources, Inc. at December 31, 2013 and December 31, 2012, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for the years ended December 31, 2013 and December 31, 2012 appearing under Item 15(c) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Assessment of Internal Control Over Financial Reporting under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits which were integrated audits in 2013 and 2012. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
As discussed in Note 1 to the consolidated financial statements, the Company discontinued hedge accounting effective January 1, 2012.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 25, 2014
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders of
QEP Resources, Inc.
We have audited the consolidated statements of operations, comprehensive income (loss), equity, and cash flows for the one year period ended December 31, 2011. Our audits also included the financial statement schedule listed in the Index at Item 8 for the one year period ended December 31, 2011. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated results of QEP Resources, Inc.’s operations and its cash flows for the one year period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ Ernst & Young LLP
Denver, Colorado
February 24, 2012
QEP RESOURCES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
See notes accompanying the consolidated financial statements.
QEP RESOURCES, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
____________________________
(1)
Presented net of income tax benefit of $45.9 million and $101.3 million during the years ended December 31, 2013 and 2012, respectively, and net of income tax expense of $14.7 million during the year ended December 31, 2011.
(2)
Presented net of income tax expense of $8.3 million during the year ended December 31, 2013, and net of income tax benefit of $6.3 million and $9.2 million during the years ended December 31, 2012 and December 31, 2011, respectively.
(3)
Presented net of income tax expense of $0.9 million and $0.9 million during the years ended December 31, 2013 and 2012, respectively.
(4)
Presented net of income tax expense of $2.1 million, $2.2 million and $2.1 million during the years ended December 31, 2013, 2012 and 2011, respectively.
(5)
Presented net of income tax expense of $0.8 million during the year ended December 31, 2012.
See notes accompanying the consolidated financial statements.
QEP RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
See notes accompanying the consolidated financial statements.
QEP RESOURCES, INC.
CONSOLIDATED STATEMENTS OF EQUITY
See notes accompanying the consolidated financial statements.
QEP RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
See notes accompanying the consolidated financial statements.
QEP RESOURCES, INC.
NOTES ACCOMPANYING THE CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - Summary of Significant Accounting Policies
Nature of Business
QEP Resources, Inc. (QEP or the Company) is a holding company with three major lines of business: oil and gas exploration and production; midstream field services; and energy marketing. These businesses are conducted through the Company’s three principal subsidiaries:
•
QEP Energy Company (QEP Energy) acquires, explores for, develops and produces gas, oil, and NGL;
•
QEP Field Services Company (QEP Field Services), which includes the ownership and operations of QEP Midstream Partners, LP (QEP Midstream), provides midstream field services, including gathering of natural gas, oil and NGL, natural gas processing, compression, and treating services, for affiliates and third parties, and;
•
QEP Marketing Company (QEP Marketing) markets affiliate and third-party oil and gas, and owns and operates an underground gas storage reservoir.
QEP's operations are focused in two major regions: the Northern Region (primarily in North Dakota, Wyoming and Utah) and the Southern Region (primarily in Oklahoma, Louisiana and the Texas Panhandle) of the United States. QEP's corporate headquarters are located in Denver, Colorado.
Shares of QEP’s common stock trade on the New York Stock Exchange under the ticker symbol “QEP”.
Principles of Consolidation
The consolidated financial statements contain the accounts of QEP and its majority-owned or controlled subsidiaries, including QEP Midstream (see Note 3 - QEP Midstream). The consolidated financial statements were prepared in accordance with U.S. Generally Accepted Accounting Principles (GAAP) and with the instructions for annual reports on Form 10-K and Regulations S-X and S-K. All significant intercompany accounts and transactions have been eliminated in consolidation.
All dollar and share amounts in this Form 10-K are in millions, except per-share information and where otherwise noted.
Investment in Unconsolidated Affiliates
QEP uses the equity method to account for investment in unconsolidated affiliates where it does not have control, but has significant influence. The investment in unconsolidated affiliates on the Company's Consolidated Balance Sheets equals the Company's proportionate share of equity reported by the unconsolidated affiliates. Investment is assessed for possible impairment when events indicate that the fair value of the investment may be below the Company's carrying value. When such a condition is deemed to be other than temporary, the carrying value of the investment is written down to its fair value, and the amount of the write-down is included in the determination of net income.
The principal unconsolidated affiliates and QEP's ownership percentage as of December 31, 2013 and 2012, were Uintah Basin Field Services, LLC in which QEP owned (38%) and Three Rivers Gathering, LLC in which QEP Midstream currently owns (50%), which was previously owned by QEP prior to QEP Midstream's initial public offering (see Note 3 - QEP Midstream). Both are limited liability companies engaged in gathering and compressing natural gas.
Reclassifications
In 2012 and 2011, QEP presented certain credit facility payments and borrowings net on the Consolidated Statements of Cash Flow. These borrowings and payments were reclassified to be presented gross on the Consolidated Statement of Cash Flow in order to conform with the current period presentation. This reclassification is entirely within "Financing Activities" and has no effect on other categories or total cash on the Consolidated Statements of Cash Flows or net income or earnings per share on the Consolidated Statements of Operations.
Use of Estimates
The preparation of the consolidated financial statements and notes in conformity with GAAP requires that management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent assets
and liabilities. A significant item that requires management's estimates and assumptions is the estimate of proved gas, oil and NGL reserves which are used in the calculation of depreciation, depletion and amortization rates of its oil and gas properties, impairment of proved properties and asset retirement obligations. Changes in estimated quantities of its reserves could impact the Company's reported financial results as well as disclosures regarding the quantities and value of proved oil and gas reserves. Other items subject to estimates and assumptions include the carrying amount of property, plant and equipment and goodwill, assigning fair value and allocating purchase price in connection with business combinations, valuation allowances for receivables, income taxes, valuation of derivatives instruments, accrued liabilities, accrued revenue and related receivables and obligations related to employee benefits, among others. Although management believes these estimates are reasonable, actual results could differ from these estimates.
Revenue Recognition
QEP subsidiaries recognize revenues in the period that services are provided or products are delivered. Revenues associated with the sale of oil and gas are accounted for using the sales method, whereby revenue is recognized as oil and gas is sold to purchasers. A liability is recorded in the event that the Company has sold volumes in excess of its share of remaining oil and gas reserves in an underlying property. QEP's imbalance obligations at December 31, 2013 and 2012, were $18.6 million and $13.2 million, respectively.
QEP Marketing reports revenues on a gross basis because, in the judgment of management, the nature and circumstances of its marketing transactions are consistent with guidance for gross revenue reporting. QEP Marketing markets affiliate and third-party gas, oil and NGL volumes. QEP Marketing uses derivatives to secure a known price for a specific volume over a specific time period. QEP Marketing does not engage in speculative hedging transactions, nor does it buy and sell energy contracts with the objective of generating profits on short-term differences in price. QEP Marketing has not engaged in buy/sell arrangements, as described in ASC 845-10-25-4, Accounting for Purchases and Sales of Inventory with the Same Counterparty.
QEP Field Services provides gathering and transportation services, primarily under fee-based contracts, as well as processing services, under keep-whole and fee-based contracts. Under fee-based arrangements, QEP Field Services receives a fee or fees for one or more of the following services: firm and interruptible gathering, processing or transmission of natural gas, oil, condensate, and water. The revenue QEP Field Services earns from the fee-based arrangements is generally directly related to the volume of gas, oil, or water that flows through QEP Field Services’ systems and is not directly dependent on commodity prices. A portion of the fee-based agreements provide for minimum annual payments or fixed demand charges which are recognized as revenue pursuant to the contract terms. In addition, under the majority of gas gathering agreements, QEP Field Services retains and sells condensate that falls out of the natural gas stream during the gathering process. Under keep-whole arrangements, QEP Field Services processes the natural gas for a customer and takes title to the resulting NGL, which are sold to third parties at market prices. Because the extraction of the NGL from the natural gas during processing reduces the Btu content of the natural gas, QEP Field Services must either purchase gas at market prices for return to producers or make cash payment to the producers equal to the energy content of this gas.
Cash and Cash Equivalents and Restricted Cash
Cash equivalents consist principally of highly liquid investments in securities with maturities of three months or less made through commercial-bank accounts that result in available funds the next business day.
As of December 31, 2013, QEP's restricted cash balance was $50.0 million, which consists of a deposit paid by QEP that was held in escrow for the acquisition that closed in the first quarter of 2014 (see Note 15 - Subsequent Event for further discussion on the acquisition). The cash payment is shown in investing activities on the Consolidated Statements of Cash Flow.
Supplemental cash flow information is shown in the below table:
Accounts Receivable Trade
Accounts receivable trade consists mainly of receivables from oil and gas purchasers and joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Generally, the Company's oil and gas receivables are collected and bad debts are minimal. Bad debt expense associated with accounts receivable for the years ended December 31, 2013, 2012 and 2011, was $3.5 million, $1.4 million, and $0.2 million, respectively. The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability. The allowance for bad debt expenses was $5.1 million at December 31, 2013 and $2.8 million at December 31, 2012.
Property, Plant and Equipment
Property, plant and equipment balances are stated at historical cost. Material and supplies inventories are valued at the lower of cost or market. Maintenance and repair costs are expensed as incurred with the exception of compressor maintenance costs, which are capitalized and depreciated. Significant accounting policies for our property, plant and equipment are as follows:
Oil and gas properties
QEP Energy uses the successful efforts method to account for oil and gas properties. The costs of acquiring leaseholds, drilling development wells, drilling successful exploratory wells, purchasing related support equipment and facilities are capitalized. Geological and geophysical studies and other exploratory activities are expensed as incurred. Costs of production and general corporate activities are expensed in the period incurred. A gain or loss is generally recognized only when an entire field is sold or abandoned, or if the unit-of-production depreciation, depletion and amortization rate would be significantly affected.
Capitalized costs of unproved properties are reclassified to proved property when related proved reserves are determined or charged against the impairment allowance when abandoned.
Capitalized exploratory well costs
The Company capitalizes exploratory well costs until it determines whether an exploratory well is commercial or noncommercial. If the Company deems the well commercial, capitalized costs are depreciated on a field basis using the unit-of-production method and the estimated proved developed oil and gas reserves. If the Company concludes that the well is noncommercial, well costs are immediately charged to exploration expense. Exploratory well costs capitalized for a period greater than one year since the completion of drilling are expensed unless the Company remains engaged in substantial activities to assess whether the well is commercial.
Depreciation, depletion and amortization
Capitalized proved leasehold costs are depleted on a field-by-field basis using the unit-of-production method and the estimated proved oil and gas reserves. Capitalized costs of exploratory wells that have found proved oil and gas reserves and capitalized development costs are depreciated using the unit-of-production method based on estimated proved developed reserves for a successful effort field. The Company capitalizes an estimate of the fair value of future abandonment costs.
Depreciation, depletion and amortization for the Company's remaining properties is based upon rates that will systematically charge the costs of assets against income over the estimated useful lives of those assets using either a straight-line or unit-of-production method. Investment in gas gathering and processing fixed assets is charged to expense using either the straight-line or unit-of-production method depending upon the facility. The estimated useful lives of those assets depreciated under the straight-line basis generally range as follows:
Impairment of Long-Lived Assets
Proved oil and gas properties are evaluated on a field-by-field basis for potential impairment. Impairment is indicated when a triggering event occurs and/or the sum of the estimated undiscounted future net cash flows of an evaluated asset is less than the asset's carrying value. Triggering events could include, but are not limited to, an impairment of oil and gas reserves caused by mechanical problems, faster-than-expected decline of reserves, lease ownership issues, declines in gas, NGL and oil prices and changes in the utilization of midstream gathering and processing assets. If impairment is indicated, fair value is calculated using a discounted-cash flow approach. Cash flow estimates require forecasts and assumptions for many years into the future
for a variety of factors, including commodity prices, operating costs, and estimates of proved, probable and possible reserves. Cash flow estimates relating to future cash flows from probable and possible reserves are reduced by additional risk-weighting factors.
Unproved properties are evaluated on a specific-asset basis or in groups of similar assets, as applicable. The Company performs periodic assessments of unproved oil and gas properties for impairment and recognizes a loss at the time of impairment. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current development and exploration drilling plans, favorable or unfavorable exploration activity on adjacent leaseholds, in-house geologists' evaluation of the lease, future reserve cash flows and the remaining lease term.
During the year ended December 31, 2013, QEP recorded impairment charges of $93.0 million, of which $1.2 million relates to price-related impairment charges on proved properties and $32.3 million relates to impairment on unproved properties due to lease expirations and changes in drilling plans. An additional $59.5 million of impairment was recorded due to the write-off of goodwill (see Goodwill section within this note for additional information). Of the $33.5 million property impairment charges incurred during the year ended December 31, 2013, $17.5 million related to oil and gas properties in the Southern Region and $16.0 million related to oil and gas properties in the Northern Region.
During the year ended December 31, 2012, QEP recorded impairment charges of $133.0 million on its oil and gas properties. Of the $133.0 million charges during the year ended December 31, 2012, $107.6 million related to price-related impairment charges on proved properties and $25.4 million related to impairment on unproved properties. The impairment charges reflect the reduced value of certain fields resulting from lower gas, oil and NGL prices and impairments of unproven leasehold acquisition costs. Of the $133.0 million impairment charges during the year ended December 31, 2012, $104.7 million related to oil and gas properties in the Southern Region and $28.3 million related to oil and gas properties in the Northern Region.
During the year ended December 31, 2011, QEP recorded impairment charges of $218.2 million, of which $173.1 million related to properties in the Northern Region with the remaining $45.1 million related to properties in the Southern Region. Proved property impairments were $195.5 million and unproved property impairments were $22.7 million during the year ended December 31, 2011.
Asset Retirement Obligations
Asset retirement obligations (ARO) associated with the retirement of tangible long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the tangible asset, including the asset retirement costs, is depreciated over the useful life of the asset. ARO are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company's credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of ARO change, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated ARO can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.
Capitalized Interest
The Company capitalizes interest costs during the construction phase of large capital projects that meet certain criteria. Capitalized interest was $2.0 million, $3.4 million and $3.0 million during the years ended December 31, 2013, 2012 and 2011, respectively.
Litigation and Other Contingencies
In accordance with ASC 450, Contingencies, an accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. QEP regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. The amount of ultimate loss may differ from these estimates. See Note 10 - Commitments and Contingencies, for additional information.
Except for environmental contingencies acquired in a business combination, which are recorded at fair value, QEP accrues losses associated with environmental obligations when such losses are probable and can be reasonably estimated. Accruals for estimated environmental losses are recognized no later than at the time the remediation feasibility study, or the evaluation of response options, is complete. These accruals are adjusted as additional information becomes available or as circumstances change. Future environmental expenditures are not discounted to their present value. Recoveries of environmental costs from other parties are recorded separately as assets at their undiscounted value when receipt of such recoveries is probable.
Goodwill
Goodwill represents the excess of the amount paid over the fair value of net assets acquired in a business combination and is not subject to amortization. As of December 31, 2013, goodwill was reduced to zero from $59.5 million in 2012 due to the recognition of impairment during 2013. Goodwill related to the Company's Uinta Basin reporting unit within QEP Energy. Goodwill is tested for impairment under a two-step quantitative test on an annual basis or when a triggering event occurs. Under the first step, the estimated fair value of the reporting unit is compared with its carrying value (including goodwill). QEP determines fair value of its reporting units in which goodwill is allocated using the income approach in which the fair value is estimated based on the value of expected future cash flows. Key assumptions used in the cash flow model consider estimated quantities of oil, NGL and gas reserves, including both proved reserves and risk-adjusted unproved reserves, including probable and possible reserves; estimates of market prices considering forward commodity price curves as of the measurement date; and estimates of capital costs. If the fair value of the reporting unit exceeds its carrying value, step two does not need to be performed. If the estimated fair value of the reporting unit is less than its carrying value, an indication of goodwill impairment exists for the reporting unit and the enterprise must perform step two of the impairment test (measurement). Under step two, an impairment loss is recognized for any excess of the carrying amount of the reporting unit’s goodwill over the implied fair value of that goodwill. The implied fair value of goodwill is determined by allocating the fair value of the reporting unit in a manner similar to a purchase price allocation in acquisition accounting. The residual fair value after this allocation is the implied fair value of the reporting unit goodwill. Fair value of the reporting unit under the two-step assessment is determined using a discounted cash flow analysis.
During the performance of QEP's annual goodwill impairment test, QEP failed the first step of the goodwill impairment test as described above. This was due primarily to lower forecasted oil and NGL prices. QEP performed the second step test described above resulting in a full write down of the Uinta reporting unit's goodwill of $59.5 million as of December 31, 2013.
Derivative Instruments
Effective January 1, 2012, the Company elected to de-designate all of its gas, oil and NGL derivative contracts that were previously designated as cash flow hedges and the Company elected to discontinue hedge accounting prospectively. Accordingly, all realized and unrealized gains and losses are recognized in earnings immediately as derivative contracts are settled and marked-to-market. For the years ended December 31, 2013 and 2012, an unrealized gain of $88.7 million and an unrealized loss of $63.2 million, respectively, were included in income that, prior to January 1, 2012, would have been deferred in Accumulated Other Comprehensive Income (AOCI) under hedge accounting (Refer to Note 7 - Derivative Contracts, for additional information). At December 31, 2011, AOCI consisted of $395.9 million ($248.6 million after tax) of unrealized gains, representing the mark-to-market value of the Company's cash flow hedges as of the balance sheet date, less any ineffectiveness recognized. As a result of discontinuing hedge accounting, such mark-to-market values at December 31, 2011, were frozen in AOCI as of the de-designation date and were reclassified into earnings as the original hedged transactions occurred and affected earnings. QEP fully reclassified all unrealized gains in AOCI into earnings during 2012 and 2013.
All of QEP's derivative contracts are net settled in cash without delivery of product. These contracts also have a nominal quantity, exchange an index price for a fixed price, and are net settled with the brokers as the price bulletins become available. These derivative contracts are recorded in revenues or cost of sales in the month of settlement. Basis-only swaps are used to manage the risk of widening basis differentials. These contracts are marked-to-market monthly with any change in the valuation recognized in the determination of income.
Credit Risk
The Northern and Southern Regions of the United States of America constitute the Company's primary market areas. Exposure to credit risk may be affected by the concentration of customers in these regions due to changes in economic or other conditions. Customers include individuals and numerous commercial and industrial enterprises that may react differently to changing conditions. Management believes that its credit review procedures, loss reserves, customer deposits and collection procedures have adequately provided for usual and customary credit-related losses. Commodity-based hedging arrangements also expose the Company to credit risk. The Company monitors the creditworthiness of its counterparties, which generally are major financial institutions and energy companies. Loss reserves are periodically reviewed for adequacy and may be established on a specific case basis. QEP requests credit support and, in some cases, fungible collateral, financial guarantees, letters of credit or prepayment from companies with unacceptable credit risks. The Company has master-netting agreements with some counterparties that allow the offsetting of receivables and payables in a default situation.
The Company's five largest customers accounted for 35%, 37%, and 32% of QEP's revenues for the years ended December 31, 2013, 2012 and 2011, respectively. During the year ended December 31, 2013, Freepoint Commodities, LLC made up 12% of
the Company's total revenues. During the year ended December 31, 2012, Chevron U.S.A. Inc. and Enterprise Products Operating, L.P. accounted for 13% and 10%, respectively, of the Company's total revenues. During the year ended December 31, 2011, no customer had sales accounting for 10% or more of QEP's total revenues. All of the these customers represent QEP Energy's customers and 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.
Income Taxes
Deferred income taxes are provided for the temporary differences arising between the book and tax carrying amounts of assets and liabilities. These differences create taxable or tax-deductible amounts for future periods. The Company records interest earned on income tax refunds in interest and other income and records penalties and interest charged on tax deficiencies in interest expense.
ASC 740, Income Taxes, specifies the accounting for uncertainty in income taxes by prescribing a minimum recognition threshold for a tax position to be reflected in the financial statements. If recognized, the tax benefit is measured as the largest amount of tax benefit that is more-likely-than-not to be realized upon ultimate settlement. Management has considered the amounts and the probabilities of the outcomes that could be realized upon ultimate settlement and believes that it is more-likely-than-not that the Company's recorded income tax benefits will be fully realized. There were no unrecognized tax benefits at the beginning or end of the twelve-month periods ended December 31, 2013, 2012 and 2011. The federal income tax returns for 2012 and 2011 are currently under examination by the Internal Revenue Service. Income tax returns for 2013 have not yet been filed. Most state tax returns for 2010 and subsequent years remain subject to examination.
Treasury Stock
We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders' equity in the consolidated balance sheets. Acquired treasury stock is used for stock grants to employees; refer to Note 11 - Equity-Based Compensation for additional information.
Earnings Per Share
Basic earnings per share (EPS) are computed by dividing net income attributable to QEP by the weighted-average number of common shares outstanding during the reporting period. Diluted EPS includes the potential increase in the number of outstanding shares that could result from the exercise of in-the-money stock options. QEP's unvested restricted shares are considered issued and outstanding, the historical forfeiture rate is minimal and the restricted shares receive dividends.
Unvested equity-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings per share pursuant to the two-class method. The Company's unvested restricted stock awards contain non-forfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company's unvested restricted stock does not have a contractual obligation to share in losses of the Company. The Company's unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings per common share. A reconciliation of the components of basic and diluted shares used in the EPS calculation follows:
Equity-Based Compensation
QEP issues stock options and restricted shares to certain officers, employees and non-employee directors under its Long-Term Stock Incentive Plan (LTSIP). QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock options for accounting purposes. The granting of restricted shares results in recognition of compensation cost measured at the grant-date market price. QEP uses an accelerated method in recognizing equity-based compensation costs with graded-vesting periods. Stock options held by employees generally vest in three equal, annual installments and primarily have a term of seven years. Restricted shares vest in equal installments over a specified number of years after the grant date with the majority vesting in three years. Non-vested restricted shares have voting and dividend rights; however, sale or transfer is restricted. The Company also awards performance share units under its Cash Incentive Plan (CIP) that are paid out in cash depending upon the Company's total shareholder return compared to a group of its peers over a three-year period. The performance share unit's compensation cost is equal to its fair value as of the period end and is classified as a liability. Additionally, QEP Midstream maintains an equity-based compensation plan for officers, directors and employees of the general partner of QEP Midstream and its affiliates. For a summary of LTSIP and CIP transactions see Note 11 - Equity-Based Compensation.
Pension Plans, Other Postretirement Benefits and Defined-Contribution Plans
QEP measures pension plan assets at fair value. Defined-benefit plan obligations and costs are actuarially determined, incorporating the use of various assumptions. Critical assumptions for pension and other postretirement plans include the discount rate, the expected rate of return on plan assets (for funded pension plans), the rate of future compensation increases and the health care cost trend rate. Other assumptions involve demographic factors such as retirement, mortality and turnover. QEP evaluates and updates its actuarial assumptions at least annually.
Comprehensive Income
Comprehensive income is the sum of net income as reported in the Consolidated Statements of Operations and changes in the components of other comprehensive income. Other comprehensive income includes certain items that are recorded directly to equity and classified as AOCI. One component of other comprehensive income is changes in the market value of commodity-based derivative instruments for which the Company previously applied hedge accounting. Income or loss associated with such commodity-based derivative instruments was realized when the gas, oil or NGL underlying the derivative instrument was sold. Comprehensive income also includes changes in the under-funded portion of the Company's defined benefit pension plans and other postretirement benefits plans and changes in deferred income taxes on such amounts. These transactions do not represent the culmination of the earnings process but result from periodically adjusting historical balances to fair value.
Business Segments
Line of business information is presented according to senior management's basis for evaluating performance considering differences in the nature of products, services and regulation. QEP's lines of business are QEP Energy, QEP Field Services, and QEP Marketing and other corporate activities not attributable to a line of business.
Noncontrolling Interests
Noncontrolling interest represent third-party ownership in the net assets of the Company's consolidated subsidiaries and are presented as a component of equity and net income. Changes in QEP's ownership interest in subsidiaries that do not result in deconsolidation are recognized in equity. On August 14, 2013, QEP completed the initial public offering of QEP Midstream. Prior to the IPO QEP's noncontrolling interest related to the outside ownership of Rendezvous Gas Services, L.L.C. Subsequent to the IPO, QEP Midstream's results (which include Rendezvous Gas Services, L.L.C) are consolidated into QEP as it is a majority-owned and controlled subsidiary and the portion not owned by QEP reflected as noncontrolling interest. See Note 3 - QEP Midstream for further information regarding the IPO.
Recent Accounting Developments
In February of 2013, the FASB issued ASU 2013-02, Other Comprehensive Income (Topic 220: Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income), which seeks to improve the reporting of entities by requiring an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respective line items in net income if the amount being reclassified is required under GAAP to be reclassified in its entirety to net income. For other amounts that are not required under GAAP to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference other disclosures required under GAAP that provide additional detail about those amounts. The amendments are effective prospectively for reporting periods beginning on or after December 15, 2012. The
Company adopted this standard in the first quarter of 2013 and noted that it did not have a significant impact on the Company's consolidated financial statements.
In December of 2011, the FASB issued ASU 2011-11, Disclosures about Offsetting Assets and Liabilities, which enhances disclosure requirements regarding an entity’s financial instruments and derivative instruments that are offset or subject to a master netting arrangement. This information about offsetting and related netting arrangements will enable users of financial statements to understand the effect of those arrangements on the entity’s financial position, including the effect of rights of setoff. Additionally, the FASB issued ASU 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which clarifies the implementation of ASU 2011-01. The amendments are required for annual reporting periods beginning after January 1, 2013, and interim periods within those annual periods. The Company adopted this standard effective January 1, 2013. It did not have a significant impact on the Company's consolidated financial statements.
In July of 2012, the FASB issued ASU 2012-02, Intangibles - Goodwill and Other: Testing Indefinite-Lived Intangible Assets for Impairment, which revises the way an entity can test indefinite-lived intangible assets for impairment by allowing an entity to first assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the indefinite-lived intangible asset is impaired. If there is no indication of impairment from the qualitative impairment test, the entity is not required to complete a quantitative impairment test of determining and comparing the fair value with the carrying amount of the indefinite-lived asset. Under the guidance in this ASU, an entity also has the option to bypass the qualitative assessment in any period and proceed directly to performing the quantitative impairment test, while retaining the ability to resume performing the qualitative assessment in any subsequent period. The amendments are effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012. The Company adopted this standard January 1, 2013, which allows the Company to more efficiently complete the annual goodwill impairment test but has not had a significant impact on the Company's consolidated financial statements.
Note 2 - Acquisitions and Divestitures
On September 27, 2012, QEP Energy completed an acquisition of oil and gas properties in the Williston Basin for an aggregate purchase price of $1.4 billion (the 2012 Acquisition). The properties are located in Williams and McKenzie counties of North Dakota, approximately 12 miles west of QEP's then-existing core acreage in the Williston Basin.
The 2012 Acquisition meets the definition of a business combination under ASC 805, Business Combinations, as it included proved properties. QEP allocated the cost of the 2012 Acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Revenues of $300.0 million and $63.7 million and net income of $67.0 million and $14.9 million were generated from the acquired properties during the years ended December 31, 2013 and 2012, respectively, and are included in QEP's Consolidated Statements of Operations. During the year ended December 31, 2012, QEP Energy's acquisition-related costs of $1.1 million are included in "General and administrative" on the Consolidated Statements of Operations.
QEP Energy recorded the 2012 Acquisition on its Consolidated Balance Sheets. The following table presents a summary of the purchase accounting entries:
The following unaudited, pro forma results of operations are provided for the years ended December 31, 2012 and 2011. These supplemental pro forma results of operations are provided for illustrative purposes only and may not be indicative of the actual results that would have been achieved by the acquired properties for the periods presented or that may be achieved by such
properties in the future. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors. The pro forma information is based on QEP's consolidated results of operations for the years ended December 31, 2012 and 2011, on the acquired properties' historical results of operations and on estimates of the effect of the transaction on the combined results. The pro forma results of operations have been prepared by adjusting the historical results of QEP to include the historical results of the acquired properties based on information provided by the seller and the impact of the purchase price allocation. The pro forma results of operations do not include any cost savings or other synergies that may result from the 2012 Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties.
Divestitures
In June 2013, QEP Energy sold its interests in several non-core oil and gas properties located in QEP's Northern Region for total cash proceeds of $138.5 million and recorded a pre-tax gain on sale of $96.2 million. In September 2013, QEP Energy sold its interests in several non-core properties located in QEP's Southern Region for total cash proceeds of $67.3 million and recorded a pre-tax gain on sale of $9.5 million. Both the cash proceeds and gains on sales are subject to post-closing adjustments. During the year ended December 31, 2013, QEP Energy recorded these gains on its Consolidated Statements of Operations in "Net gain from asset sales".
Note 3 - QEP Midstream
QEP Midstream is a publicly traded master limited partnership that was formed by QEP to own, operate, acquire and develop midstream energy assets. QEP Midstream's assets currently consist of ownership interests in four gathering systems and two FERC regulated pipelines, which provide oil and gas gathering and transportation services. These assets are located in, or within close proximity to, the Green River Basin located in Wyoming and Colorado, the Uinta Basin located in eastern Utah, and the Williston Basin located in North Dakota.
Initial Public Offering
On August 14, 2013, QEP Midstream completed its initial public offering (the IPO) of 20,000,000 common units, representing limited partner interests in QEP Midstream, at a price to the public of $21.00 per common unit. QEP Midstream received net proceeds of $390.7 million from the sale of the common units, after deducting underwriting discounts and commissions, structuring fees and offering expenses of approximately $29.3 million. Following the IPO, the underwriters exercised their over-allotment option to purchase an additional 3,000,000 common units, at a price of $21.00 per common unit, providing additional net proceeds of $58.9 million, after deducting $4.1 million of underwriters' discounts and commissions and structuring fees, to QEP Midstream.
QEP Midstream used the net proceeds to repay its outstanding debt balance with QEP, which was assumed with the assets contributed to QEP Midstream, pay revolving credit facility origination fees and make a cash distribution to QEP, a portion of which was used to reimburse QEP for certain capital expenditures it incurred with respect to assets contributed to QEP Midstream. The following table is a reconciliation of proceeds from the IPO (in millions):
QEP Midstream Partners GP, LLC (the General Partner), a wholly owned subsidiary of QEP, serves as the general partner of QEP Midstream. QEP owns a 57.8% interest in QEP Midstream and consolidates QEP Midstream for financial reporting purposes with the portion not owned by QEP reflected as a reduction to net income and equity as a noncontrolling interest.
The following agreements were entered into between QEP and QEP Midstream in connection with the IPO.
Contribution, Conveyance and Assumption Agreement
On August 14, 2013, in connection with the closing of the IPO, QEP entered into a Contribution, Conveyance and Assumption Agreement (the Contribution Agreement) with QEP Field Services, the General Partner and QEP Midstream Partners Operating, LLC (the Operating Company). Immediately prior to the closing of the IPO, the following transactions, among others, occurred pursuant to the Contribution Agreement:
•
QEP Field Services contributed to the General Partner, as a capital contribution, a limited liability company interest in the Operating Company with a value equal to 2.0% of the equity value of QEP Midstream at the closing of the IPO;
•
the General Partner contributed to QEP Midstream, as a capital contribution, the limited liability company interest in the Operating Company in exchange for (a) 1,090,000 general partner units representing the continuation of an aggregate 2.0% general partner interest in QEP Midstream and (b) all the incentive distribution rights of QEP Midstream;
•
QEP Field Services contributed to QEP Midstream, as a capital contribution, its remaining limited liability company interests in the Operating Company in exchange for (a) 6,701,750 common units representing a 12.3% limited partner interest in QEP Midstream, (b) 26,705,000 subordinated units representing a 49.0% limited partner interest in QEP Midstream and (c) the right to receive a distribution from QEP Midstream; and
•
the public, through the underwriters, contributed $420.0 million in cash (or $390.7 million, net of the underwriters' discounts and commissions, structuring fees and offering expenses of approximately $29.3 million) to QEP Midstream in exchange for the issuance of 20,000,000 common units.
Subsequent to the IPO, the underwriters exercised their over-allotment option to purchase an additional 3,000,000 common units in QEP Midstream, which reduced QEP's limited partner common unit interest in QEP Midstream from 12.3% to 6.8% and QEP's total ownership interest from 63.3% to 57.8%.
Omnibus Agreement
In connection with the IPO, QEP entered into an Omnibus Agreement (the Omnibus Agreement) with QEP Midstream on August 14, 2013, that addresses the following matters:
•
QEP Midstream's payment of an annual amount to QEP, initially in the amount of approximately $13.8 million, for the provision of certain general and administrative services by QEP and its affiliates to QEP Midstream, including a fixed annual fee of approximately $1.4 million for providing certain executive management services by certain officers of the General Partner. The remaining portion of this annual amount reflects an estimate of the costs that QEP and its affiliates expect to incur in providing the services;
•
QEP Midstream's obligation to reimburse QEP for any out-of-pocket costs and expenses incurred by QEP in providing general and administrative services (which reimbursement is in addition to certain expenses of the General Partner and its affiliates that are reimbursed under QEP Midstream's partnership agreement), as well as any other out-of-pocket expenses incurred by QEP on QEP Midstream's behalf; and
•
an indemnity by QEP for certain environmental and other liabilities, and QEP Midstream's obligation to indemnify QEP and its subsidiaries for events and conditions associated with the operation of QEP Midstream's assets that occur after the closing of the IPO.
As long as QEP controls the General Partner, the Omnibus Agreement will remain in full force and effect. If QEP ceases to control the General Partner, either party may terminate the Omnibus Agreement, but the indemnification obligations will remain in full force and effect in accordance with their terms.
Note 4 - Capitalized Exploratory Well Costs
Net changes in capitalized exploratory well costs are presented in the table below and exclude amounts that were capitalized and subsequently expensed in the period. The balances at December 31, 2013, 2012 and 2011, represent the amount of capitalized exploratory well costs that are pending the determination of proved reserves.
Note 5 - Asset Retirement Obligations
QEP records asset retirement obligations when there are legal obligations associated with the retirement of tangible long-lived assets. The Company's ARO liability applies primarily to abandonment costs associated with oil and gas wells, production facilities, midstream assets, and certain other properties. The fair values of such costs are estimated by Company personnel based on abandonment costs of similar assets and depreciated over the life of the related assets. Revisions to the ARO estimates result from changes in expected cash flows or material changes in estimated asset retirement costs. The ARO liability is adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate. Of the $193.6 million and $193.1 million ARO liability for both the years ended December 31, 2013 and 2012, $1.8 million was included as a liability in "Accounts payable and accrued expenses" on the Consolidated Balance Sheet.
The following is a reconciliation of the changes in the Company's ARO for the periods specified below:
Note 6 - Fair Value Measurements
QEP measures and discloses fair values in accordance with the provisions of ASC 820, Fair Value Measurements and Disclosures. This guidance defines fair value in applying GAAP, establishes a framework for measuring fair value and expands disclosures about fair-value measurements, but does not change existing guidance as to whether or not an instrument is carried at fair value. ASC 820 also establishes a fair-value hierarchy. Level 1 inputs are quoted prices (unadjusted) for identical assets or liabilities in active markets that the Company has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability.
QEP has determined that its commodity derivative instruments are Level 2. The Level 2 fair value of commodity derivative contracts (see Note 7 - Derivative Contracts) is based on market prices posted on the respective commodity exchange on the last trading day of the reporting period and industry standard discounted cash flow models. QEP primarily applies the market approach for recurring fair value measurements and maximizes its use of observable inputs and minimizes its use of
unobservable inputs. QEP considers bid and ask prices for valuing the majority of its assets and liabilities measured and reported at fair value. In addition to using market data, QEP makes assumptions in valuing its assets and liabilities, including assumptions about risk and the risks inherent in the inputs to the valuation technique. The Company's policy is to recognize significant transfers between levels at the end of the reporting period.
Certain of the Company's commodity derivative instruments are valued using industry standard models that consider various inputs, including quoted forward prices for commodities, time value, volatility, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable prices at which transactions are executed in the marketplace. The determination of fair value for derivative assets and liabilities also incorporates nonperformance risk for counterparties and for QEP. Derivative contract fair values are reported on a net basis to the extent a legal right of offset with the counterparty exists.
In addition, QEP has interest rate swaps that it has determined are Level 2 financial instruments. The fair values of the interest rate swaps are determined using the market standard methodology of discounting the future expected cash flows that would occur under the contractual terms of the swap. The variable interest rates used in the calculation of projected cash flows are based on an expectation of future interest rates derived from observable market interest rate curves. QEP incorporates credit valuation adjustments to reflect both its nonperformance risk and the respective counterparty's nonperformance risk in the fair value measurements. While the credit valuation adjustments are not observable inputs, they are not significant to the overall valuation and the other inputs used to value the interest rate swaps are observable Level 2 inputs.
The fair value of financial assets and liabilities at December 31, 2013 and 2012, is shown in the tables below:
____________________________
(1)
The Company nets its derivative contract assets and liabilities outstanding with the same counterparty on the Consolidated Balance Sheets as the contracts contain netting provisions. Refer to Note 7 - Derivative Contracts, for additional information regarding the Company's derivative contracts.
____________________________
(1)
The Company nets its derivative contract assets and liabilities outstanding with the same counterparty on the Condensed Consolidated Balance Sheet as the contracts contain netting provisions. Refer to Note 7 - Derivative Contracts, for additional information regarding the Company's derivative contracts.
Fair values related to the Company's oil costless collars were transferred from Level 3 to Level 2 in the second quarter of 2012, due to the enhancements to the Company's internal valuation process, including the use of observable inputs to assess the fair value. There were no other significant transfers in or out of Levels 1, 2 or 3 for the periods presented herein.
During the year ended December 31, 2013, there were no derivative instruments assets or liabilities classified as Level 3. The change in the fair value of Level 3 assets and liabilities for the year ended December 31, 2012 is shown below.
The following table discloses the fair value and related carrying amount of certain financial instruments not disclosed in other notes to the consolidated financial statements in this Annual Report on Form 10-K:
The carrying amounts of cash and cash equivalents and checks outstanding in excess of cash balances approximate fair value. The carrying amount of checks outstanding in excess of cash balances approximates fair value. The fair value of fixed-rate long-term debt is based on the trading levels and dollar prices for the Company's debt at the end of the quarter. The carrying amount of variable-rate long-term debt approximates fair value because the floating interest rate paid on such debt was set for periods of one month.
The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs are used in the calculation of asset retirement obligations include plugging cost estimates and reserve lives. A reconciliation of the Company's asset retirement obligations is presented in Note 5 - Asset Retirement Obligations.
Nonrecurring Fair Value Measurements
The provisions of the fair value measurement standard are also applied to the Company's nonrecurring, non-financial measurements. The Company utilizes fair value on a non-recurring basis to review its proved oil and gas properties and its goodwill for potential impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. During the years ended December 31, 2013 and 2012, the Company recorded impairments on certain oil and gas properties resulting in a write down of the associated carrying value to fair value. The fair value of the property was measured utilizing the income approach and utilizing inputs which are primarily based upon internally developed cash flow models. Given the unobservable nature of the inputs, proved oil and gas property impairments are considered Level 3 within the fair value hierarchy. During the years ended December 31, 2013 and 2012, the Company recorded $1.2 million and $107.6 million, respectively, of impairments related to certain of its proved properties. The proved properties were written down to their estimated fair values of zero and $71.9 million at the time of the impairments during December 31, 2013 and 2012, respectively.
Acquisitions of proved and unproved properties are also measured at fair value on a nonrecurring basis. The Company utilized a discounted cash flow model to estimate the fair value of acquired property as of the acquisition date which utilized the following inputs to estimate future net cash flows: estimated quantities of oil, gas and NGL reserves; estimates of future commodity prices; and estimated production rates, future operating and development costs which were based on the Company's historic experience with similar properties. Due to the unobservable characteristics of the inputs, the fair value of the properties are considered Level 3 within the fair value hierarchy. Refer to Note 2 - Acquisitions and Divestitures for additional information on the fair value of acquired properties.
Note 7 - Derivative Contracts
QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. In the normal course of business, QEP uses commodity price derivative instruments to reduce the impact of potential downward movements in commodity prices on cash flow, returns on capital investment, and other financial results. However, these instruments typically limit gains from favorable price movements. The volume of production subject to commodity derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. QEP may enter into commodity derivative contracts for up to 100% of forecasted production from proved reserves. In addition, QEP may enter into commodity derivative contracts on a portion of its extracted NGL volumes in its midstream business and a portion of its gas sales and purchases for marketing transactions. QEP does not enter into commodity derivative instruments for speculative purposes.
QEP uses commodity derivative instruments known as fixed-price swaps to realize a known price for a specific volume of production delivered into a regional sales point. QEP's commodity derivative instruments do not require the physical delivery of gas, oil, or NGL between the parties at settlement. Swap transactions are settled in cash with one party paying the other for the net difference in prices, multiplied by the contract volume, for the settlement period. Gas price derivative instruments are typically structured as fixed-price swaps at regional price indices. Oil price derivative instruments are typically structured as NYMEX fixed-price swaps based at Cushing, Oklahoma. QEP also has oil price derivative swaps that use Intercontinental Exchange, Inc. (ICE), Brent oil prices as the reference price. NGL price derivative instruments are typically structured as Mont Belvieu, Texas fixed-price swaps.
QEP enters into commodity derivative transactions that do not have margin requirements or collateral provisions that would require payments prior to the scheduled settlement dates. Commodity derivative contract counterparties are normally financial institutions and energy trading firms with investment-grade credit ratings. QEP routinely monitors and manages its exposure to counterparty risk by requiring specific minimum credit standards for all counterparties and avoids concentration of credit exposure by transacting with multiple counterparties.
Effective January 1, 2012, QEP elected to de-designate all of its gas, oil and NGL derivative contracts that were previously designated as cash flow hedges and discontinue hedge accounting prospectively. As a result of discontinuing hedge accounting, the mark-to-market values at December 31, 2011, were fixed in AOCI as of the de-designation date and reclassified into the Consolidated Statement of Operations as the transactions settled and affected earnings. During the year ended December 31, 2013, the remaining portion of unrealized gains fixed in AOCI of $77.6 million, net of tax, were settled and reclassified to the Consolidated Statements of Operations. All realized and unrealized gains and losses from derivative instruments incurred after January 1, 2012, are presented in the Consolidated Statements of Operations in "Realized and unrealized gains on derivative contracts" below operating income.
QEP also uses interest rate swaps to mitigate a portion of its exposure to interest rate volatility risk. During the second quarter of 2012, QEP entered into variable-to-fixed interest rate swap agreements having a combined notional principal amount of $300.0 million to minimize the interest rate volatility risk associated with its $300.0 million term loan. QEP locked in a fixed interest rate of 1.07% in exchange for a variable interest rate indexed to the one-month LIBOR rate. The interest rate swaps settle monthly and will mature in March of 2017.
QEP Energy's Derivative Contracts
The following table sets forth QEP Energy's quantities and average prices for its commodity derivative contracts as of December 31, 2013:
The following table sets forth QEP Energy's oil basis swaps as of December 31, 2013:
QEP Marketing Derivative Contracts
QEP Marketing enters into commodity derivative transactions to lock in a margin on gas volumes placed into storage and for marketing transactions in which QEP Marketing sells gas volumes at a fixed price. The following table sets forth QEP Marketing's volumes and swap prices for its commodity derivative contracts as of December 31, 2013:
QEP's Derivative Contracts
The following table sets forth QEP's notional amounts and interest rates for its interest rate swaps outstanding as of December 31, 2013:
QEP Derivative Financial Statement Presentation
The following table presents the balance sheet location of QEP's outstanding derivative contracts on a gross contract basis as opposed to the net contract basis presentation in the Consolidated Balance Sheets and the related fair values at the balance sheet dates:
The effects of the change in fair value and settlement of QEP's derivative contracts recorded in "Realized and Unrealized gains on derivatives" on the Consolidated Statements of Operations are summarized in the following tables:
The following table presents the change in the fair value and settlement of QEP's derivative contracts that were designated as cash flow hedges in 2011:
Note 8 - Restructuring Costs
During the first quarter of 2012, QEP began incurring costs related to the closure of its Oklahoma City office and the subsequent consolidation of its Southern Region operations into a single regional office located in Tulsa. During the second half of 2012, QEP incurred additional restructuring and reorganization costs related to consolidating various corporate and accounting functions to the Denver corporate headquarters. The creation of one office for QEP’s Southern Region as well as the consolidation of corporate and accounting functions was intended to increase efficiency, team-based collaboration and organizational productivity over the long term. As part of the reorganization, QEP incurred costs associated with the severance, retention and relocation of employees, additional pension expenses, exit costs associated with the termination of operating leases arising from office space that will no longer be utilized by the Company and other expenses. All remaining restructuring costs related to the office consolidations were incurred during 2013.
In December 2013, QEP announced its plan to pursue a separation of its midstream business, QEP Field Services. In connection with this announcement, the Board of Directors approved an employee retention plan to provide substantially all QEP Field Services' employees as of December 1, 2013, with a one-time lump sum cash payment on December 31, 2014, conditioned on continued employment with QEP Field Services or a successor through the payment date unless the employee is terminated without cause prior to such date.
The following table summarizes, by line of business, each major type of cost expected to be incurred and the total amounts recorded in "General and administrative" expense on the Consolidated Statements of Operations for the respective periods indicated:
The following is a reconciliation of the restructuring liability, by line of business, which is included within “Accounts payable and accrued expenses” on the Consolidated Balance Sheets:
Note 9 - Debt
As of the indicated dates, the principal amount of QEP’s debt, including amounts outstanding under its and QEP Midstream's revolving credit facilities, QEP's term loan and QEP's senior notes consisted of the following:
Of the total debt outstanding on December 31, 2013, the revolving credit facility due August 25, 2016, QEP's Midstream's revolving credit facility due August 14, 2018, the term loan due April 18, 2017, the 6.05% Senior Notes due September 1, 2016, and the 6.80% Senior notes due April 1, 2018 will mature within the next five years.
Credit Facilities
QEP's Credit Facility
QEP's revolving credit facility, which matures in August 2016, provides for loan commitments of $1.5 billion from a group of financial institutions. The credit facility provides for borrowings at short-term interest rates and contains customary covenants and restrictions. The credit facility also contains an accordion provision that would allow for the amount of the facility to be increased to $2.0 billion and for the maturity to be extended for two additional one-year periods, with the agreement of the lenders.
During the year ended December 31, 2013 and 2012, QEP's weighted-average interest rate on borrowings from its credit facility was 2.22% and 2.08%, respectively. At December 31, 2013 and 2012, QEP was in compliance with the covenants under the credit agreement. At December 31, 2013, there was $480.0 million outstanding and QEP had $3.8 million in letters of credit outstanding under the credit facility. At December 31, 2012, there was $690.0 million outstanding and QEP had $4.1 million in letters of credit outstanding under the credit facility.
QEP Midstream's Credit Facility
On August 14, 2013, QEP Midstream entered into a $500.0 million senior secured revolving credit facility with a group of financial institutions, which matures on August 14, 2018. QEP Midstream's credit facility contains an accordion provision that allows for the amount of the facility to be increased to $750.0 million with the agreement of the lenders. QEP Midstream's credit facility is available for QEP Midstream's working capital, capital expenditures, permitted acquisitions and general corporate purposes, including distributions. Substantially all of QEP Midstream's assets, excluding equity in and assets of certain joint ventures and unrestricted subsidiaries, are pledged as collateral under the credit facility. In addition, the credit facility contains restrictions and events of default customary for agreements of this nature.
There have been no borrowings under QEP Midstream's credit facility, and at December 31, 2013, QEP Midstream was in compliance with the covenants under the QEP Midstream credit facility agreement.
QEP is not a borrower or guarantor of QEP Midstream's credit facility. In addition, QEP is not subject to any of the restrictions or covenants contained in QEP Midstream's credit agreement. Outstanding indebtedness under QEP Midstream's credit facility is not included in the definition of indebtedness under QEP's credit facility.
Term Loan
QEP's $300.0 million term loan facility provides for borrowings at short-term interest rates and contains covenants, restrictions and interest rates that are substantially the same as QEP’s revolving credit facility. The term loan matures in April 2017, and the maturity date may be extended one year with the agreement of the lenders. During the years ended December 31, 2013 and 2012, QEP's weighted-average interest rate on borrowings from the term loan was 2.22% and 2.05%, respectively. At December 31, 2013 and December 31, 2012, QEP was in compliance with the covenants under the term loan credit agreement.
Senior Notes
At December 31, 2013, the Company had $2,221.8 million principal amount of senior notes outstanding with maturities ranging from September 2016 to May 2023 and coupons ranging from 5.25% to 6.875%. The senior notes pay interest semi-annually, are unsecured senior obligations and rank equally with all of our other existing and future unsecured and senior obligations. QEP may redeem some or all of its senior notes at any time before their maturity at a redemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption. The indenture governing QEP's senior notes contains customary events of default and covenants that may limit QEP's ability to, among other things, place liens on its property or assets.
Note 10 - Commitments and Contingencies
QEP is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. QEP assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its consolidated financial statements. In accordance with ASC 450, Contingencies, an accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, QEP may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matter. QEP's litigation loss contingencies are discussed below. QEP is unable to estimate reasonably possible losses in excess of recorded accruals for these contingencies for the reasons set forth above. QEP believes, however, that the resolution of pending proceedings will not have a material effect on QEP's consolidated financial position, results of operations or cash flows.
Environmental Claims
In October 2009, QEP received a cease and desist order from the U.S. Army Corps of Engineers (COE) to refrain from unpermitted work resulting in the discharge of dredged and/or fill material into waters of the United States at three sites located in Caddo and Red River Parishes, Louisiana. Region 6 of the U.S. Environmental Protection Agency (EPA) has assumed lead responsibility for enforcement of the cease and desist order and any possible future orders for the removal of unauthorized fills and/or civil penalties under the Clean Water Act. On June 28, 2013, the EPA issued to QEP an Administrative Complaint for the alleged violations. QEP and the EPA reached an agreement to settle the alleged violations through an Administrative Order, under the terms of which QEP paid an administrative penalty of $0.2 million. The Administrative Order is final. In 2012, QEP completed a field audit, which identified 112 additional instances affecting approximately 90 acres where work may have been conducted in violation of the Clean Water Act. QEP has disclosed each of these instances to the EPA under the EPA's Audit Policy (to reduce penalties) and to the COE. QEP is working with the EPA and the COE to resolve these matters, which will require the Company to undertake certain mitigation and permitting activities, and may require QEP to pay a monetary penalty.
In July 2010, QEP received a Notice of Potential Penalty (NOPP) from the Louisiana Department of Environmental Quality (LDEQ) regarding the assumption of ownership and operatorship of a single facility in Louisiana prior to transferring the facility's air quality permit. In 2011, QEP completed an internal audit, which identified 424 facilities in Louisiana for which QEP both failed to submit a complete permit application and to receive approval from the LDEQ prior to construction, modification, or operation. QEP has corrected and disclosed all instances of non-compliance to the LDEQ and is working with the LDEQ to resolve the NOPP. The LDEQ has assumed lead responsibility for enforcement of the NOPP and may require the Company to pay a monetary penalty.
Litigation
Chieftain Royalty Company v. QEP Energy Company, Case No CIV-11-0212-R, U. S. District Court for the Western District of Oklahoma. This statewide class action was filed in January 2011 on behalf of QEP's Oklahoma royalty owners asserting various claims for damages related to royalty valuation on all of QEP's Oklahoma wells operated by QEP or from which QEP marketed gas. These claims include breach of contract, breach of fiduciary duty, fraud, unjust enrichment, tortious breach of contract, conspiracy, and conversion, based generally on asserted improper deduction of post-production costs. The Court certified the class as to the breach of contract, breach of fiduciary duty and unjust enrichment claims. The parties successfully mediated the case in January 2013. On February 13, 2013, the parties executed a Stipulation and Agreement of Settlement (the Chieftain Settlement Agreement) providing for a cash payment from QEP to the class in the amount of $115.0 million. In consideration for the settlement payment, QEP received a full release of all claims regarding the calculation, reporting and payment of royalties from the sale of gas and its constituents for all periods prior to February 28, 2013, and all class members are enjoined from asserting claims related to such royalties. As part of the Chieftain Settlement Agreement, the parties also agreed on the methodology for the calculation and payment of future royalties payable by QEP, or its successors and assigns, under all class leases for the life of such leases. On May 31, 2013, the Court issued its order approving the settlement, which is now final.
Questar Gas Company v. QEP Field Services Company, Civil No. 120902969, Third Judicial District Court, State of Utah. QEP Field Services' former affiliate, Questar Gas Company (QGC), filed this complaint in state court in Utah on May 1, 2012, asserting claims for breach of contract, breach of implied covenant of good faith and fair dealing, and an accounting and declaratory judgment related to a 1993 gathering agreement (the 1993 Agreement) executed when the parties were affiliates. Specific monetary damages are not asserted. Under the 1993 Agreement, certain of QEP Field Services' systems provide gathering services to QGC charging an annual gathering rate which is based on cost of service. QGC is disputing the annual calculation of the gathering rate. The annual gathering rate has been calculated in the same manner under the 1993 Agreement since it was amended in 1998, without any prior objection or challenge by QGC. At the closing of the IPO, the assets and agreement discussed above were assigned to QEP Midstream. QGC netted the disputed amount from its monthly payments of the gathering fees to QEP Field Services and has continued to net such amounts from its monthly payment to QEP Midstream. As of December 31, 2013, QEP Midstream has deferred revenue of $8.5 million related to the QGC disputed amount. QEP Field Services has filed counterclaims seeking damages and a declaratory judgment relating to its gathering services under the 1993 Agreement. QGC may seek to amend its complaint to add QEP Midstream as a defendant in the litigation. QEP Midstream has been indemnified by QEP for costs, expenses and other losses incurred by QEP Midstream in connection with the QGC dispute, subject to certain limitations, as set forth in the Omnibus Agreement (defined above in "Note 3 - QEP Midstream").
Rocky Mountain Resources, LLC v. QEP Energy Company, Wexpro Company, Ultra Resources, Inc. and Lance Oil & Gas Company, Inc., Civil No. 2011-7816, District Court of Sublette County, Wyoming. Rocky Mountain Resources, LLC (“Rocky Mountain”) filed its Complaint on March 30, 2011 seeking determination of the existence of a 4% overriding royalty interest in State of Wyoming oil and gas Lease No. 79-0645 covering Section 16, T32-N R-109-W, Sublette County, Wyoming. QEP and the other defendants are current lessees of Lease 79-0645. Rocky Mountain alleges that the Defendants have received benefits from Lease 79-0645 and have failed to pay Rocky Mountain monies associated with the claimed 4% overriding royalty interest since the issuance of the lease by the State of Wyoming in 1980. Rocky Mountain asserts claims for quiet title, declaratory judgment, breach of contract, breach of duty of good faith, conversion, constructive trust and prejudgment interest. Specific monetary damages are not asserted.
Gatti et al v. State of Louisiana et al, 589,350 (19th JDC, Parish of East Baton Rouge, Louisiana). In this putative class action arising out of the unitization practices and orders of the Louisiana Commissioner of Conservation ("Commissioner"), Plaintiffs seek to represent a class of all Haynesville Shale mineral owners (alleged to be over 50,000 in number) against the Commissioner and all Haynesville Shale unit operators. Plaintiffs filed their complaint on April 8, 2010, and claim that the Commissioner exceeded his statutory authority in creating and perpetuating units larger than the area that can be efficiently and economically drained by a single well. They seek declaratory relief that would nullify all such improper orders, along with an unspecified amount of monetary damages from the unit operators sufficient to compensate the putative class members for the alleged dilution of their true interest in unit production as a result of "oversized" units and the "cloud on title" caused by having excessive and improperly sized units purport to hold their mineral leases via unit operations. All defendants filed exceptions to the Plaintiffs' petition on the primary ground that Plaintiffs had failed to comply with the exclusive statutory judicial review procedure (Louisiana Revised Statutes 30:12), which the trial court granted, dismissing the action in its entirety. On January 15, 2014, the Louisiana First Circuit Court of Appeal reversed and reinstated Plaintiffs' claims. Defendants intend to seek review of the Louisiana Supreme Court, which review is discretionary.
Commitments
Subsidiaries of QEP have contracted for firm transportation services with various third-party pipelines. Market conditions, drilling activity and competition may prevent full utilization of the contractual capacity. In addition, QEP has contracts with third parties who provide drilling services and fractionation contracts. Annual payments and the corresponding years for transportation contracts, drilling contracts and fractionation contracts are as follows (in millions):
QEP rents office space throughout its scope of operations from third-party lessors. Rental expense from operating leases amounted to $7.8 million, $7.3 million and $5.0 million during the years ended December 31, 2013, 2012 and 2011, respectively. Minimum future payments under the terms of long-term operating leases for the Company's primary office locations are as follows (in millions):
Note 11 - Equity-Based Compensation
QEP issues stock options and restricted shares under its LTSIP and awards performance-based share units under its CIP to certain officers, employees, and non-employee directors. QEP recognizes expense over time as the stock options, restricted shares, and performance-based share units vest. Deferred equity-based compensation is included in additional paid-in capital in the Consolidated Balance Sheets. There were 12.0 million shares available for future grants under the LTSIP at December 31, 2013. Equity-based compensation expense is recognized in "General and administrative" on the Consolidated Statements of Operations. During the year ended December 31, 2013, QEP recognized $27.1 million in total compensation expense related to equity-based compensation compared to $25.6 million and $22.0 million during the years ended December 31, 2012 and 2011, respectively.
QEP Midstream maintains a unit-based compensation plan for officers, directors and employees of the general partner of QEP Midstream and its affiliates and any consultants, affiliates of the General Partner, or other individuals who perform services for QEP Midstream. The QEP Midstream 2013 Long-Term Incentive Plan (the QEP Midstream LTIP) permits various types of awards, including awards of restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. Awards granted during 2013 under the QEP Midstream LTIP will be settled with QEP Midstream units. During the year ended December 31, 2013, QEP's equity-based compensation expense included $0.5 million in equity-based compensation related to QEP Midstream's LTIP.
Stock Options
QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock option awards at the date of the grant. Fair-value calculations rely upon subjective assumptions used in the mathematical model and may not be representative of future results. The Black-Scholes-Merton model is intended for measuring the value of options traded on an exchange. The Company utilizes the "simplified" method to estimate the expected term of the stock options granted as there is limited historical exercise data available in estimating the expected term of the stock options. QEP uses a historical volatility method to estimate the fair value of stock options awards and the risk-free interest rate is based on the yield on U.S. Treasury strips with maturities similar to those of the expected term of the stock options. The stock options typically vest in equal installments over a three-year period from the grant date and are exercisable immediately upon vesting through the seventh anniversary of the grant date. To fulfill options exercised, QEP either reissues treasury stock or issues new shares.
The calculated fair value of options granted and major assumptions used in the model at the date of grant are listed below:
Stock option transactions under the terms of the LTSIP are summarized below:
The total intrinsic value (the difference between the market price at the exercise date and the exercise price) of options exercised was $4.3 million, $9.6 million and $2.7 million during the years ended December 31, 2013, 2012 and 2011, respectively. The Company realized $1.4 million, $4.6 million, and $0.4 million of income tax benefits for the years ended December 31, 2013, 2012 and 2011. respectively, which increased its Additional Paid-in-Capital (APIC) pool by $6.5 million as of December 31, 2013. As of December 31, 2013, $2.9 million of unrecognized compensation cost related to stock options granted under the LTSIP is expected to be recognized over a weighted-average period of 1.95 years. During the year ended December 31, 2012, QEP issued shares for stock option exercises from its treasury stock. During the year end December 31, 2013, QEP received $2.0 million in cash in relation to the exercise of stock options.
Restricted Shares
Restricted share grants typically vest in equal installments over a three-year period from the grant date. The grant date fair value is determined based on the closing bid price of the Company's common stock on the grant date. The total fair value of restricted stock that vested during the years ended December 31, 2013, 2012 and 2011, was $19.8 million, $16.7 million and $11.7 million, respectively. The Company realized income tax expense of $0.1 million and $0.3 million for the years ended December 31, 2013 and 2012, respectively, and income tax benefit of $1.0 million during 2011. Restricted stock increased the Company's APIC pool by $0.8 million as of December 31, 2013. The weighted average grant-date fair value of restricted stock granted during the years was $30.06 per share, $30.54 per share and $38.50 per share for the years ended December 31, 2013, 2012 and 2011, respectively. As of December 31, 2013, $17.4 million of unrecognized compensation cost related to restricted shares granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 1.99 years.
Transactions involving restricted shares under the terms of the LTSIP are summarized below:
Performance Share Units
The performance share units' cash payouts are dependent upon the Company's total shareholder return compared to a group of its peers over a three-year period. The awards are denominated in share units but delivered in cash at the end of the performance period. The weighted average grant-date fair values of the performance share units granted during the years ended December 31, 2013, 2012 and 2011, were $30.12, $30.75, and $39.07 per unit, respectively. As of December 31, 2013, $6.4 million of unrecognized compensation cost classified as a liability, or the fair market value, related to performance shares granted under the CIP is expected to be recognized over a weighted-average vesting period of 1.83 years.
Transactions involving performance share units under the terms of the CIP are summarized below:
Note 12 - Employee Benefits
Defined Benefit Pension Plans and Other Postretirement Benefits
The Company maintains a closed, defined-benefit pension plan providing coverage to 128, or 13%, of QEP's active employees and to 86 participants that are retired, or terminated and vested. Pension-plan benefits are based on the employee's age at retirement, years of service and highest earnings in a consecutive 72 semi-monthly pay period during the 10 years preceding retirement. QEP pension plans include a qualified and a nonqualified retirement plan. Postretirement health care benefits and life insurance are provided only to employees hired before January 1, 1997. Of the 128 active, pension eligible employees, 90 are also eligible for the postretirement medical and life insurance plans when they retire. Currently, 29 retirees are enrolled in this plan. The Company has capped its exposure to increasing medical costs by paying a fixed dollar monthly contribution toward these retiree benefits. The Company's contribution is prorated based on an employee's years of service at retirement; only those employees with 25 or more years of service receive the maximum company contribution. At December 31, 2013 and 2012, QEP's accumulated benefit obligation exceeded the fair value of its qualified retirement plan assets. At December 31, 2013 and 2012, QEP's nonqualified retirement plan was unfunded.
During the year ended December 31, 2012, the Company recognized a $2.2 million loss on curtailment as part of its restructuring and related termination benefits. A curtailment is recognized immediately when there is a significant reduction in, or an elimination of, defined benefit accruals for present employees' future services. For additional information regarding the Company's restructuring see Note 8 - Restructuring Costs. During the year ended December 31, 2013, the Company made contributions of $8.1 million to its funded qualified pension plan. Contributions to funded qualified plans increase plan assets. During the year ended December 31, 2013, the Company made payments of $3.4 million of benefits pursuant to its unfunded nonqualified retirement plan. Payments to the unfunded nonqualified plans are used to fund current benefit payments. During 2014, the Company expects to contribute approximately $8.1 million to its funded pension plan, pay approximately $5.5 million of benefits under its unfunded nonqualified pension plan and pay approximately $0.2 million for retiree health care and life insurance benefits. The accumulated postretirement benefit obligation for all defined-benefit pension plans was $101.0 million and $106.9 million at December 31, 2013 and 2012, respectively.
The following table sets forth changes in the benefit obligations and fair value of plan assets for the Company's pension and other postretirement benefit plans for the years ended December 31, 2013 and 2012, as well as the funded status of the plans and amounts recognized in the financial statements at December 31, 2013 and 2012:
The following table sets forth the Company's pension and other postretirement benefit cost and amounts recognized in other comprehensive income (before tax) for the respective years ended December 31:
The estimated portion of net actuarial loss and net prior service cost for the pension plans that will be amortized from AOCI into net periodic benefit cost in 2014 is $5.0 million, which represents amortization of prior service cost recognition. The estimated portion to be recognized in net periodic cost for other postretirement benefits from AOCI in 2014 is $0.4 million, which represents amortization of prior service cost recognition. Amortization of prior service costs and actuarial losses/gains out of AOCI are recognized in the Consolidated Statements of Operations in "General and administrative."
Following are the weighted-average assumptions (weighted by the plan level benefit obligation for pension benefits) used by the Company to calculate pension and other postretirement benefit obligations at December 31, 2013 and 2012:
The discount rate assumptions used by the Company represents an estimate of the interest rate at which the pension and other postretirement obligations could effectively be settled on the measurement date.
Following are the weighted-average assumptions (weighted by the net period benefit cost for pension benefits) used by the Company in determining the net periodic pension and other postretirement benefit cost for the years ended December 31:
In selecting the assumption for expected long-term rate of return on assets, the Company considers the average rate of return expected on the funds to be invested to provide benefits. This includes considering the plan's asset allocation, historical returns on these types of assets, the current economic environment and the expected returns likely to be earned over the life of the plan. No plan assets are expected to be returned to the Company in 2014. Historical health care cost trend rates are not applicable to
the Company, because the Company's medical costs are capped at a fixed amount. As the Company's medical costs are capped at a fixed amount, the sensitivity to increase and decreases in the health-care inflation rate is not applicable.
Plan Assets
The Company's Employee Benefits Committee (EBC) oversees investment of qualified pension plan assets. The EBC uses a third-party asset manager to assist in setting targeted-policy ranges for the allocation of assets among various investment categories. The EBC allocates pension-plan assets among broad asset categories and reviews the asset allocation at least annually. Asset-allocation decisions consider risk and return, future-benefit requirements, participant growth and other expected cash flows. These characteristics affect the level, risk and expected growth of postretirement-benefit assets. The EBC uses asset-mix guidelines that include targets for each asset category, return objectives for each asset group and the desired level of diversification and liquidity. These guidelines may change from time to time based on the committee's ongoing evaluation of each plan's risk tolerance. The EBC estimates an expected overall long-term rate of return on assets by weighting expected returns of each asset class by its targeted asset allocation percentage. Expected return estimates are developed from analysis of past performance and forecasts of long-term return expectations by third-parties. Responsibility for individual security selection rests with each investment manager, who is subject to guidelines specified by the EBC. The EBC sets performance objectives for each investment manager that are expected to be met over a three-year period or a complete market cycle, whichever is shorter. Performance and risk levels are regularly monitored to confirm policy compliance and that results are within expectations. Performance for each investment is measured relative to the appropriate index benchmark for its category. QEP securities may be considered for purchase at an investment manager's discretion, but within limitations prescribed by ERISA and other laws. There was no direct investment in QEP shares for the periods disclosed. The majority of retirement-benefit assets were invested as follows:
Equity securities: Domestic equity assets were mostly invested in a stock index fund, and a smaller portion was invested in an actively managed product, with a diversification goal representative of the whole U.S. stock market. Foreign equity securities consisted of developed and emerging market foreign equity assets that were invested in funds that hold diversified portfolio of common stocks of corporations in developed and emerging foreign countries.
Debt securities: Investment grade intermediate-term debt assets are invested in funds holding a diversified portfolio of debt of governments, corporations and mortgage borrowers with average maturities of 5 to 10 years and investment grade credit ratings. Investment grade long-term debt assets are invested in a diversified portfolio of debt of corporate and non-corporate issuers, with an average maturity of more than ten years and investment grade credit ratings.
Although the actual allocation to cash and short-term investments is minimal (less than 1%), larger cash allocations may be held from time to time if deemed necessary for operational aspects of the retirement plan. Cash is invested in a high-quality, short-term temporary investment fund that purchases investment-grade quality short-term debt issued by governments and corporations.
Commingled funds: The EBC made the decision to invest all of the retirement plan assets in commingled funds as these funds typically have lower expense ratios and are more tax efficient than mutual funds. While commingled funds are classified as Level 3 assets because there are calculations involved in determining the net asset value of the funds, the underlying assets can be traced back to observable asset values and these commingled funds are audited annually by an independent accounting firm.
The fair value measurement provision of ASC 820, Fair Value Measurements, defines fair value in applying generally accepted accounting principles as well as establishes a framework for measuring fair value and for making disclosures about fair-value measurements. Fair value measurement establishes a fair-value hierarchy. Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for an asset, either directly or indirectly. Level 3 inputs are unobservable and significant to the fair value measurement. The Company's Level 3 investments are public investment vehicles valued using the net asset value (NAV) of the fund, but are considered Level 3 because they are commingled funds. The NAV is based on the value of the underlying assets owned by the fund excluding transaction costs, and minus liabilities.
The following table sets forth by level, within the fair value hierarchy, the fair value of pension and postretirement benefit assets:
The following table presents a summary of changes in the fair value of QEP's Level 3 investments:
Expected Benefit Payments
As of December 31, 2013, the following future benefit payments are expected to be paid:
Employee Investment Plan
QEP employees may participate in the QEP Employee Investment Plan (EIP), a defined-contribution plan. The EIP allows eligible employees to purchase shares of QEP common stock or other investments through payroll deduction at the current fair market value on the transaction date. For the year ended December 31, 2013, the Company made discretionary matching
contributions equal to 100% of employees' contributions up to a maximum of 8% of their qualifying earnings. Employees in the closed QEP Resources, Inc. Retirement Plan (pension) are eligible for a 6% match. For the years ended December 31, 2012 and 2011, the Company made discretionary matching contributions equal to 100% of employees' contributions up to a maximum of 6% of their qualifying earnings. The Company may contribute a discretionary portion beyond the Company's discretionary matching contribution to employees not in the QEP Resources, Inc. Retirement Plan (pension), and for the years ended December 31, 2012 and 2011, the Company made such discretionary contributions equal to 2% of each eligible employee's compensation. The Company recognizes expense equal to its yearly contributions, which amounted to $6.9 million, $6.4 million and $5.8 million during the years ended December 31, 2013, 2012 and 2011, respectively.
Note 13 - Income Taxes
Details of income tax expenses and deferred income taxes from continuing operations are provided in the following tables. The components of income tax expenses were as follows:
The difference between the statutory federal income tax rate and the Company's effective income tax rate is explained as follows:
Significant components of the Company's deferred income taxes were as follows:
The amounts and expiration dates of net operating loss and tax credit carryforwards at December 31, 2013 are as follows:
Note 14 - Operations by Line of Business
QEP’s lines of business include oil and gas exploration and production (QEP Energy), midstream field services (QEP Field Services), which includes the ownership and operation of QEP Midstream, and marketing and corporate (QEP Marketing & Resources). The lines of business are managed separately and therefore the financial information is presented separately due to the distinct differences in the nature of operations of each line of business, among other factors. QEP owns a 57.8% ownership interest in QEP Midstream and it is consolidated under the voting interest model in QEP Field Services' operating results. The outside ownership interest in QEP Midstream is presented separately as a noncontrolling interest.
The following table is a summary of operating results for the year ended December 31, 2013, by line of business:
____________________________
(1)
The impact of QEP's settled derivative contracts, for the year ended December 31, 2013, is reflected below operating income.
(2)
Net income attributable to QEP for the year ended December 31, 2013, includes the impact of unrealized gains and losses from changes in the fair value of the commodity derivative contracts.
The following table is a summary of operating results for the year ended December 31, 2012, by line of business:
____________________________
(1)
The impact of QEP's settled derivative contracts, for the year ended December 31, 2012, was reflected below operating (loss) income.
(2)
Net (loss) income attributable to QEP for the year ended December 31, 2012, includes the impact of unrealized gains and losses from changes in the fair value of the commodity derivative contracts.
The following table is a summary of operating results for the year ended December 31, 2011, by line of business:
____________________________
(1)
Revenues for the year ended December 31, 2011, reflect the impact of QEP's settled derivative contracts. See Note 7 - Derivative Contracts, for detailed information on derivative contract settlements in the year ended December 31, 2011.
(2)
Under hedge accounting, realized gains and losses from realized commodity derivative contract settlements were included in revenues and operating income during the year ended December 31, 2011.
(3)
Under hedge accounting, unrealized gains and losses from changes in the fair value were deferred in AOCI during the year ended December 31, 2011.
Note 15 - Subsequent Event
In February 2014, QEP Energy acquired oil and gas properties in the Permian Basin of Texas for an aggregate purchase price of $950.0 million, subject to customary purchase price adjustments (the Permian Basin Acquisition). The acquired properties consist of approximately 26,500 net acres of producing and undeveloped oil and gas properties and approximately 260 vertical producing wells in the Permian Basin, which creates a new core area of operation for QEP Energy. The Permian Basin Acquisition was funded with cash on hand, $300.0 million from the Company’s expanded Term Loan and approximately $600.0 million from its revolving credit facility. Based on the timing of the Permian Basin Acquisition, QEP has not completed its initial accounting for the Permian Basin Acquisition and thus full disclosures required under GAAP will not be included until the first quarter 2014.
In February 2014, to fund a portion of the purchase price for the Permian Basin Acquisition, the Company increased the term loan from $300.0 million to $600.0 million. There were no changes to the maturity date, pricing or covenants in the term loan credit agreement.
Note 16 - Quarterly Financial Information (unaudited)
The following table provides a summary of unaudited quarterly financial information:
____________________________
(1)
Includes net gains/losses from asset sales and losses due to impairments.
Note 17 - Supplemental Oil and Gas Information (Unaudited)
The Company is making the following supplemental disclosures of oil and gas producing activities, in accordance with ASC 932, Extractive Activities - Oil and Gas, as amended by ASU 2010-03, Oil and Gas Reserve Estimation and Disclosures, and SEC Regulation S-X. The Company uses the successful efforts accounting method for its oil and gas exploration and development activities. All properties are located in the United States.
Capitalized Costs
The aggregate amounts of costs capitalized for oil and gas exploration and development activities and the related amounts of accumulated depreciation, depletion and amortization are shown below:
Costs Incurred
The costs incurred in oil and gas exploration and development activities are displayed in the table below. Development costs are net of the change in accrued capital costs for $21.4 million and ARO additions and revisions of $17.2 million during the year ended December 31, 2013. The costs incurred to advance the development of reserves that were classified as proved undeveloped were approximately $645.9 million in 2013, $513.0 million in 2012, and $533.6 million in 2011.
Results of Operations
Following are the results of operations of QEP Energy's oil and gas exploration and development activities, before allocated corporate overhead and interest expenses.
___________________________
(1)
Revenue for the year ended December 31, 2011, reflect the impact of QEP's settled derivative contracts which during the years ended December 31, 2013 and 2012, are reflected below operating income (loss) on the Consolidated Statements of Operations. See Note 7 - Derivative Contracts.
Estimated Quantities of Proved Oil and Gas Reserves
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 compliance oversight of a multi-functional reserves review committee responsible to the Company's Board of Directors. QEP Energy's estimated proved reserves have been prepared by Ryder Scott Company, L.P., independent reservoir engineering consultants, in accordance with the SEC's Regulation S-X and ASC 932 as amended. The individuals performing reserves estimates possess professional qualifications and demonstrate competency in reserves estimation and evaluation. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.
All of QEP Energy's proved undeveloped reserves at December 31, 2013, are scheduled to be developed within five years from the date such locations were initially disclosed as proved undeveloped reserves, except for 120 Bcfe located within the northern portion of the Company's Pinedale Anticline leasehold in western Wyoming. Long-term development of gas reserves in the Pinedale Anticline Project Area (PAPA) is governed by the Bureau of Land Management's September 2008, Record of Decision (ROD) on the Final Supplemental Environmental Impact Statements. Under the ROD, QEP Energy is allowed to drill and complete wells year-round in designated concentrated development areas defined in the PAPA. The ROD contains additional requirements and restrictions on the sequence of development of the PAPA, which requires the Company to develop its leasehold from the south to the north. These restrictions result in protracted, phased development of the PAPA that is beyond the control of the Company. The Company has an ongoing development plan for the PAPA and the financial capability to continue development in the manner estimated.
As of December 31, 2013, all of the Company's oil and gas reserves are attributable to properties within the United Sates. A summary of the Company's change in quantities of proved oil and gas reserves for the years ended December 31, 2011, 2012 and 2013 are as follows:
____________________________
(1)
Revisions of previous estimates in 2013 include positive impacts due to 80.0 Bcfe pricing revisions, negative performance revisions of 265.5 Bcfe, 42.0 Bcfe negative operating cost revisions and 101.0 Bcfe other negative revisions. Pricing revisions were primarily due to increased gas prices which increased reserves by 68.4 Bcfe. Negative performance revisions were driven by a 129.5 Bcfe decrease in Pinedale reserves and 112.7 Bcfe decrease in Haynesville reserves related to reserve adjustments based on additional production history, well performance and current pricing causing a revised future development plan which includes lower density drilling in some areas and a change in well spacing assumptions in these areas.
(2)
Extensions and discoveries in 2013 increased proved reserves by 783.8 Bcfe, primarily related to extensions and discoveries in the Williston Basin of 217.6 Bcfe, in Pinedale of 265.3 Bcfe, and 175.9 Bcfe in Haynesville. Extension and discoveries in Pinedale and Haynesville relate to certain less densely spaced wells with higher estimates of recoverable oil and gas, which were booked to replace wells removed from the Company's reserves through negative revisions caused by a change in well spacing assumptions in these areas. Of these extensions and discoveries 687.6 Bcfe related to new PUD locations.
(3)
Revisions of previous estimates in 2012 include negative impacts due to 80.0 Bcfe pricing revisions, 35.6 Bcfe performance revisions, 27.6 Bcfe operating cost revisions and 29.1 Bcfe other revisions. The 152.4 Bcfe pricing revisions were due to lower gas prices which reduced gas reserve volumes by 147.7 Bcf. Negative performance revisions were driven by a 56.0 Bcfe decrease in Pinedale reserves. Pinedale reserve adjustments are based on additional production history, well performance and current pricing causing a revised future development plan which includes lower density drilling in some flank areas, resulting in 25 proved undeveloped (PUD) locations being eliminated. Reserve decreases are partially offset by a 35.9 Bcfe positive impact from revisions in the Uinta Basin, due to the installation of the Iron Horse Cryogenic plant to increase liquid recoveries and improved well performance in the Red Wash Mesaverde field.
(4)
Extensions and discoveries in 2012 increased proved reserves by 572.5 Bcfe, primarily related to extensions and discoveries in the Uinta Basin of 258.3 Bcfe, in Pinedale of 151.6 Bcfe, and 162.6 Bcfe in the Williston Basin, Midcontinent and other Legacy areas of operation combined. All of these extensions and discoveries related to new well completions and the associated new PUD locations as part of the Company's development drilling plans.
(5)
Purchase of reserves in place primarily relate to the Company's $1.4 billion 2012 Acquisition as discussed in Note 2 - Acquisitions and Divestitures.
(6)
Revisions of previous estimates in 2011 include 173.7 Bcfe negative impact due to performance revisions offset by 150.2 Bcfe positive impact from other revisions. The 173.7 Bcfe performance revisions were due to the reduction of gas volumes of 209.8 Bcf, partially offset by an increase in NGL volumes of 33.2 MMbbls, which is included in other revisions. The primary reason for the increase in the NGL volumes, or 31.8 MMbbls, relates to the completion of the Blacks Fork II plant and the fee-based processing agreement entered into between QEP Energy and QEP Field Services for QEP Energy's Pinedale production, offset by a reduction in the dry gas reserve related to shrink of about 59.6 Bcf. The remaining performance related reduction in the gas reserves was primarily related to the removal of certain PUD locations in the Haynesville/Cotton Valley area to recognize the 80-acre increased density development plan.
(7)
Extensions and discoveries increased proved reserves by 881.6 Bcfe, primarily related to extensions and discoveries at the Haynesville/Cotton Valley area (358.8 Bcfe), Uinta Basin area (189.1 Bcfe) and Pinedale Anticline area (161.2 Bcfe). All of these extensions and discoveries related to new well completions and associated new PUD locations. Estimates of the quantity of proved reserves from the Company's Pinedale Anticline leasehold in western Wyoming have changed substantially over time as a result of numerous factors including, but not limited to, additional development drilling activity, producing well performance and the development and application of reliable technologies. The continued analysis of new data has led to progressive increases in estimates of original gas-in-place at Pinedale and to a better understanding of the appropriate well density to maximize the economic recovery of the in-place volumes. With the application of the amendments of ASC 932 in ASU 2010-03, reserves associated with Pinedale increased density drilling are included in extensions and discoveries for the years ended December 31, 2011 and 2010, because each new well drilled recovers incremental reserves that would otherwise be unrecoverable.
Standardized Measure of Future Net Cash Flows Relating to Proved Reserves
Future net cash flows were calculated at December 31, 2013, 2012 and 2011, by applying prices, which were the simple average of the first-of-the-month commodity prices, adjusted for location and quality differentials, for each of the 12 months during 2013, 2012 and 2011, with consideration of known contractual price changes. The prices used do not include any impact of QEP's commodity derivatives portfolio. The following table provides the average benchmark prices per unit, before location and quality differential adjustments, used to calculate the related reserve category:
Year-end operating expenses, development costs and appropriate statutory income tax rates, with consideration of future tax rates, were used to compute the future net cash flows. All cash flows were discounted at 10% to reflect the time value of cash flows, without regard to the risk of specific properties. The estimated future costs to develop booked proved undeveloped reserves are approximately $852.6 million in 2014, $1,183.8 million in 2015 and $1,094.4 million in 2016.
The assumptions used to derive the standardized measure of future net cash flows are those required by accounting standards and do not necessarily reflect the Company's expectations. The information may be useful for certain comparative purposes, but should not be solely relied upon in evaluating QEP or its performance. Furthermore, information contained in the following table may not represent realistic assessments of future cash flows, nor should the standardized measure of future net cash flows
be viewed as representative of the current value of the Company's reserves. Management believes that the following factors should be considered when reviewing the information below:
•
Future commodity prices received for selling the Company's net production will likely differ from those required to be used in these calculations.
•
Future operating and capital costs will likely differ from those required to be used in these calculations.
•
Future market conditions, government regulations, reservoir conditions and risks inherent in the production of oil and gas may cause production rates in future years to vary significantly from those rates used in the calculations.
•
Future revenues may be subject to different production, severance and property taxation rates.
•
The selection of a 10% discount rate is arbitrary and may not be a reasonable factor in adjusting for future economic conditions or in considering the risk that is part of realizing future net cash flows from the reserves.
The standardized measure of future net cash flows relating to proved reserves is presented in the table below:
The principal sources of change in the standardized measure of future net cash flows relating to proved reserves is presented in the table below:
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
As disclosed in the Company's Current Report on Form 8-K, filed with the SEC on November 17, 2011, and its Current Report on Form 8-K/A, filed with the SEC on February 28, 2012, the Company changed its independent registered public accountants effective for the fiscal year ended December 31, 2012. There were no disagreements with QEP's former independent registered public accounting firm.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
The Company's Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the design and operation of the Company's disclosure controls and procedures (as such term is defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 as amended), as of December 31, 2013. Based on such evaluation, such officers have concluded that, as of December 31, 2013, the Company's disclosure controls and procedures are designed and effective to ensure that information required to be included in the Company's reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms and that information required to be disclosed in reports filed or submitted by the Company under the Exchange Act is accumulated and communicated to the Company's management including its principal executive officer and principal financial officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.
In designing and evaluating the Company's disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that the Company's controls will succeed in achieving their goals under all potential future conditions.
Changes in Internal Controls
There were no changes in the Company's internal controls over financial reporting that occurred during the quarter ended December 31, 2013, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.
Management's Assessment of Internal Control Over Financial Reporting
The Company's management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f). The Company's internal control over financial reporting is a process designed under the supervision of QEP's chief executive officer and chief financial officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements. Also, projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or processes may deteriorate.
As of December 31, 2013, management assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established in Internal Control-Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission in 1992. Based on the assessment, management determined that the Company maintained effective internal control over financial reporting as of December 31, 2013, based on those criteria. Management included in its assessment of internal control over financial reporting all consolidated entities.
PricewaterhouseCoopers, LLP, the independent registered public accounting firm that audited the consolidated financial statements included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of internal control over financial reporting as of December 31, 2013, which is included in the consolidated financial statements in Item 8 of Part II of this Annual Report on Form 10-K.
ITEM 9B. OTHER INFORMATION
Amendment of the Executive Severance Compensation Plan
On February 23, 2014, QEP's Board of Directors approved revisions to its executive severance plan, now named the QEP Resources, Inc. Executive Severance Compensation Plan - CIC (the CIC Severance Plan). The revisions are effective immediately. The CIC Severance Plan amends the QEP Resources, Inc. Executive Severance Plan adopted in February 2012 and amended in May 2012 (the Original Plan), to (i) rename the Original Plan the "QEP Resources, Inc. Executive Severance Plan - CIC" to clarify that it applies only in the event of a change in control and to distinguish it from the QEP Resources, Inc. Basic Severance Compensation Plan (the Basic Severance Plan); (ii) remove references in the Original Plan relating to Questar Corporation benefits arrangements, as such references are no longer relevant to the operation of the plan; (iii) include a more flexible provision relating to performance-based long-term incentive awards that applies whether the awards are settled in cash or stock; (iv) clarify that severance under the CIC Severance Plan is (a) payable if a participant is terminated upon consummation of a change in control or at any time during the third anniversary of the change in control, and (b) not payable if a participant’s employment is terminated by the Company due to disability; (v) conform the Original Plan to the Basic Severance Plan by (a) adding a requirement that the Company pay the participant’s attorneys’ fees if the participant brings a legal proceeding to enforce his or her rights under the CIC Severance Plan and prevails on at least one material claim, and (b) clarifying the mechanism that applies if the participant’s exposure to the tax is miscalculated, which includes an indemnification by the Company of the participant for expenses incurred in connection with any related tax dispute.
Like the Original Plan, the CIC Severance Plan establishes two tiers of participants with different compensation in the event of termination following a change in control. Tier 1 Participants include the chief executive officer, chief financial officer and any other officer so designated by the Company's Board of Directors. Tier 2 Participants include all other officers of the Company. In the event of termination of employment following a change in control, Tier 1 Participants will receive three times the sum of their base salary and three-year average annual bonus, and Tier 2 Participants will receive two times the sum of their base salary and three-year average annual bonus. All participants will receive prorated bonuses under the applicable annual cash incentive plan in respect of the year in which the change in control occurs based on satisfaction of the performance goals achieved for such year. Additionally, following termination of employment following a change in control, participants shall receive a payment in cash or shares of Company common stock, as applicable, for each grant of performance share units held by the participant as of the termination date, based on the level of achievement of the applicable performance goals as of immediately prior to the change in control; and accelerated vesting (in full) of all stock options, stock appreciation rights, restricted stock grants and other equity incentive awards (other than any performance share units), with stock options remaining exercisable until the earlier of one year post-termination or their original expiration date. Finally, health and welfare benefits continue for three years for Tier 1 Participants and for two years for Tier 2 Participants. If a termination would entitle a participant to severance payments and benefits under both the Basic Severance Plan and the CIC Severance Plan, severance pay and benefits will be provided only under the CIC Severance Plan.
The foregoing description of the CIC Severance Plan is not complete and is qualified in its entirety by reference to the text of the full CIC Severance Plan, which is attached as Exhibit 10.9 to this Form 10-K and is incorporated herein by reference.
Completion of Acquisition of Assets
On February 24, 2014, QEP, through its wholly owned subsidiary QEP Energy, closed its previously announced transaction with Enervest Holding, L.P., Enervest Energy Institutional Fund XII-A, L.P., Enervest Energy Institutional Fund XII-WIB, L.P., and Enervest Energy Institutional Fund XII-WIC, L.P. (the Sellers). QEP acquired certain oil and natural gas interests (the Acquired Properties) in Martin and Andrews counties in west Texas pursuant to the related purchase and sale agreement with the Seller. The aggregate consideration paid to the Sellers for the acquisition was approximately $950.0 million (the Purchase Price). The Purchase Price is subject to final purchase price adjustments to be determined based on an effective date of November 1, 2013.
The Acquired Properties consist of approximately 26,500 net acres of producing and undeveloped oil and gas properties and approximately 260 vertical producing wells in the Permian Basin. The Acquired Properties have estimated aggregate net proved reserves of approximately 47 MMBoe based upon internal estimates.
The Purchase Price was funded with cash on hand, $300.0 million from the Company’s expanded Term Loan and approximately $600.0 million from its revolving credit facility. The purchase and sale agreement will be filed with the Company's Quarterly Report on Form 10-Q for the quarter ending March 31, 2014.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by Item 10 concerning QEP's directors and nominees for directors and other corporate governance matters will be presented in the Company's definitive Proxy Statement prepared for the solicitation of proxies in connection with the Company's Annual Meeting of Stockholders to be held on May 13, 2014, which will be filed with the Securities and Exchange Commission no later than 120 days subsequent to December 31, 2013 (Proxy Statement), and is incorporated by reference herein.
Information about the Company's executive officers can be found in Item 1 of Part I in this Annual Report on Form 10-K.
Information concerning compliance with Section 16(a) of the Exchange Act will be set forth in the Proxy Statement and is incorporated herein by reference.
The Company has a Code of Conduct that applies to all of its directors, officers (including its chief executive officer and chief financial officer) and employees. QEP has posted the Code of Conduct on its website, www.qepres.com. Any waiver of the Code of Conduct for executive officers must be approved by the Company's Board of Directors. QEP will post on its website any amendments to or waivers of the Code of Conduct that apply to executive officers.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 will be set forth in the Proxy Statement and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by Item 12 will be set forth in the Proxy Statement and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by Item 13 will be set forth in the Proxy Statement and is incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by Item 14 will be set forth in the Proxy Statement and is incorporated herein by reference.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Financial statements and financial statement schedules filed as part of this report are listed in the index included in Item 8 of Part II Financial Statements and Supplementary Data of this report.
(b) Exhibits. The following is a list of exhibits required to be filed as a part of this report in Item 15(b).
____________________________
*
Filed herewith
**
These interactive data files are furnished and deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Act of 1934, as amended, and otherwise are not subject to liability under those sections.
+
Indicates a management contract or compensatory plan or arrangement
(c) Financial Statement Schedule:
QEP RESOURCES, INC.
Schedule of Valuation and Qualifying Accounts
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on February 25, 2014.
QEP RESOURCES, INC.
(Registrant)
/s/ Charles B. Stanley
Charles B. Stanley,
Chairman, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on February 25, 2014.
/s/ Charles B. Stanley
Chairman, President and Chief Executive Officer
Charles B. Stanley
(Principal Executive Officer)
/s/ Richard J. Doleshek
Executive Vice President, Chief Financial Officer, Treasurer,
Richard J. Doleshek
and Chief Accounting Officer (Principal Financial and Accounting Officer)
*Charles B. Stanley
Chairman of the Board; Director
*Phillips S. Baker, Jr.
Director
*L. Richard Flury
Director
*David Trice
Director
*Robert E. McKee III
Director
*M. W. Scoggins
Director
*Julie A. Dill
Director
*Robert F. Heinemann
Director
*Thomas C. O’Connor
Director
*William L. Thacker III
Director
February 25, 2014
*By
/s/ Charles B. Stanley
Charles B. Stanley, Attorney in Fact