ITEMS 1 and 2. BUSINESS AND PROPERTIES
Nature of Business
QEP Resources, Inc. (QEP or the Company) is an independent crude oil and natural gas exploration and production company with operations in two regions of the United States: the Southern Region (primarily in Texas) and the Northern Region (primarily in North Dakota). Unless otherwise specified or the context otherwise requires, all references to "QEP" or the "Company" are to QEP Resources, Inc. and its wholly-owned subsidiaries on a consolidated basis. QEP was incorporated on May 18, 2010, in the State of Delaware. QEP's corporate headquarters are located in Denver, Colorado and shares of QEP's common stock trade on the New York Stock Exchange (NYSE) under the ticker symbol "QEP".
The following information provides material updates to the development of QEP's business disclosed in its 2019 Annual Report on Form 10-K. Refer to Item 1 of Part I of QEP's 2019 Annual Report on Form 10-K for additional discussion on the developments to QEP's business prior to the year ended December 31, 2020.
Merger
On December 20, 2020, the Company entered into an Agreement and Plan of Merger (Merger Agreement) with Diamondback Energy, Inc. (Diamondback) and Bohemia Merger Sub, Inc., a wholly owned subsidiary of Diamondback (Merger Sub), which provides that, among other things, and subject to the terms and conditions of the Merger Agreement, Merger Sub will be merged with and into QEP, with QEP surviving as a direct, wholly owned subsidiary of Diamondback (Merger). Pursuant to the Merger Agreement, at the effective time of the Merger, each outstanding share of common stock, par value $0.01 per share, of the Company (other than any Excluded Shares, any Converted Shares and Company Restricted Stock Awards (each as defined in the Merger Agreement)) will be converted into the right to receive 0.05 shares of common stock, par value $0.01 per share, of Diamondback (Merger Consideration). The Merger Agreement also addresses the treatment of QEP equity awards in the Merger. Diamondback’s common stock is listed and traded on the NASDAQ Global Select Market under the symbol "FANG". The transaction was unanimously approved by the Boards of Directors of both companies. The Merger is expected to close late in the first quarter of 2021, and is subject to the approval of the Company's stockholders and other customary closing conditions. During the year ended December 31, 2020, the Company incurred $4.5 million of merger costs recognized in "General and administrative" expense on the Consolidated Statements of Operations and $5.0 million of additional merger costs were recognized in "Prepaid expenses" on the Consolidated Balance Sheets as of December 31, 2020.
For additional information regarding the Merger and QEP’s Board’s process and rationale for the Merger, please see the proxy statement and other documents filed with the SEC as they become available.
Strategies
We are focused on creating value for our shareholders through returns-focused operations and superior execution. To achieve these objectives we strive to:
•operate in a safe and environmentally responsible manner;
•allocate capital to those projects that generate the highest returns;
•reduce leverage and strengthen the balance sheet;
•generate Free Cash Flow;
•maintain an inventory of high return oil weighted development projects in our operating areas;
•build contiguous acreage positions that drive operating efficiencies;
•acquire businesses and assets that complement or expand our current business;
•be the operator of our assets, whenever possible;
•be the low-cost driller and producer in the basins where we operate, as compared to our peers;
•actively market our oil production to maximize value and flow assurance;
•utilize derivative contracts to reduce the impact of oil, gas and NGL price volatility;
•attract and retain the best people; and
•maintain a capital structure that provides sufficient financial flexibility to successfully operate and grow the business.
Overview
QEP conducts exploration and production (E&P) activities in two of North America's most productive hydrocarbon resource plays. For the year ended December 31, 2020, the Company reported production of over 30 MMboe, owned interests in over 167,000 gross acres, drilled 72 gross operated and non-operated productive wells and had an extensive inventory of identifiable undeveloped drilling locations between the Permian and Williston basins.
As a result of the reduction of the Company's operational footprint over the past few years, QEP reassessed its organizational needs and significantly reduced its general and administrative expense to ensure its cost structure is competitive with industry peers.
In conjunction with the implementation of the Company's strategic initiatives, QEP incurred costs associated with contractual termination benefits, including severance, accelerated vesting of share-based compensation and other expenses. Refer to Note 3 – Acquisitions and Divestitures and Note 8 – Restructuring in Item 8 of Part II of this Annual Report on Form 10-K for more information.
The Company continues to focus on reducing its operating costs, per well drilling costs, general and administrative costs and managing its liquidity. We believe our plan to generate Free Cash Flow on an annual basis will allow us to further strengthen our balance sheet and ultimately return capital to shareholders.
The following map illustrates the location of substantially all of the Company's operating activities, the location of its Northern and Southern Regions, and related reserve and production data as of and during the year ended December 31, 2020:
QEP sells oil and condensate and NGL volumes to refiners, marketers, midstream service providers and other companies. QEP sells gas volumes to wholesale marketers, industrial users, local distribution companies, midstream service providers and utility companies. The Company regularly evaluates counterparty credit risk and may require parental guarantees, letters of credit or prepayment from companies with perceived higher credit risk. In order to get its oil and condensate, gas and NGL volumes to their ultimate sale point, QEP has contracts with midstream providers for the gathering, transportation, processing and/or fractionation of these products. Disruptions impacting pipelines or other midstream provider facilities can impact QEP's production volumes. In cases where QEP's wells are not connected to sales pipelines, the Company sells its products to buyers at the well and the buyer arranges transportation to the ultimate destination.
Description of Properties
Southern Region
Permian Basin
QEP has 788.3 net productive wells, including its interest in non-operating wells, in the Permian Basin. QEP has multiple targeted formations within its acreage in the Permian Basin and is actively developing oil producing zones, primarily in the Spraberry Shale and Wolfcamp formations. The Company utilizes a "tank-style" completion methodology and continues to test additional formations and evaluate the appropriate density of its development program. During the year ended December 31, 2020, the Company put 50 gross operated wells on production. As of December 31, 2020, QEP had two company-operated rigs drilling in the Permian Basin. QEP has built water infrastructure and centralized gathering infrastructure in the Permian Basin to support its tank-style development.
Other Southern
The remainder of QEP's Southern Region primarily consists of small royalty interests over a few properties.
Northern Region
Williston Basin
QEP has 366.4 net productive wells, including its interests in non-operated wells, in the Williston Basin. During the year ended December 31, 2020, the Company put two gross operated wells on production.
Other Northern
The remainder of QEP's Northern Region leasehold interests and proved reserves are distributed over a number of fields and properties in various states.
Reserves
At December 31, 2020 and 2019, QEP's estimated proved reserves were approximately 363.4 MMboe and 382.3 MMboe, respectively, of which 98% were Company operated in both years. Proved developed reserves represented 45% and 50% of the Company's total proved reserves at December 31, 2020 and 2019, respectively, while the remaining reserves were classified as proved undeveloped. All reported reserves are located in the United States. QEP's estimated proved reserves are summarized in the table below:
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December 31, 2020
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December 31, 2019
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Oil and condensate
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Gas(1)
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NGL
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Total(1)
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Oil and condensate
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Gas(1)
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NGL
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Total(1)
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(MMbbl)
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(Bcf)
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(MMbbl)
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(MMboe)(2)
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(MMbbl)
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(Bcf)
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(MMbbl)
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(MMboe)(2)
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Proved developed reserves
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101.2
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185.0
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32.0
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164.0
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117.5
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217.0
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36.7
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190.4
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Proved undeveloped reserves
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136.7
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183.3
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32.1
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199.4
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137.4
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156.3
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28.5
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191.9
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Total proved reserves
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237.9
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368.3
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64.1
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363.4
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254.9
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373.3
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65.2
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382.3
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____________________________
(1)Generally, gas consumed in operations was excluded from reserves, however, in some cases; produced gas consumed in operations was included in reserves when the volumes replaced fuel purchases.
(2)Natural gas is converted to a crude oil equivalent at the ratio of six Mcf of natural gas to one barrel of crude oil equivalent.
QEP's reserve, production and reserve life index for each of the years ended December 31, 2018 through December 31, 2020 are summarized in the table below:
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Year Ended December 31,
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Year End Reserves
(MMboe)
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Oil and condensate, Gas and NGL Production(2)(3)
(MMboe)
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Reserve Life Index(1)(2)(3)
(Years)
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2018
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658.2
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49.6
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13.3
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2019
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382.3
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31.9
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12.0
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2020
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363.4
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30.3
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12.0
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____________________________
(1)Reserve life index is calculated by dividing year-end proved reserves by production for that year.
(2)The reserve life index for 2019 excludes 0.3 MMboe of production volumes from Haynesville/Cotton Valley due to the divestiture of the Haynesville/Cotton Valley assets in January, 2019. Including production volumes from the divested Haynesville/Cotton Valley assets, the reserve life index is 11.9 years for the year ended December 31, 2019.
(3)The reserve life index for 2018 excludes 2.2 MMboe of production volumes from the Uinta Basin due to the divestiture of the Uinta Basin assets in September 2018. Including production volumes from the divested Uinta Basin assets, the reserve life index is 12.7 years for the year ended December 31, 2018.
Proved Reserves
Estimates of proved reserves and related information are presented in accordance with the requirements of the SEC's rules for the Modernization of Oil and Gas Reporting. These rules permit the use of reliable technologies to estimate and categorize reserves and require the use of the unweighted average of the first-of-the-month commodity prices, adjusted for location and quality differentials, for the prior 12 months (unless contractual arrangements designate the price) to calculate economic producibility of reserves and the discounted cash flows reported as the Standardized Measure of Future Net Cash Flows Relating to Proved Reserves. Refer to Note 15 – Supplemental Oil and Gas Information (unaudited) in Item 8 of Part II of this Annual Report on Form 10-K for more information regarding estimates of proved reserves and the preparation of such estimates.
QEP's proved reserves in its major operating areas are summarized in the table below:
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December 31,
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2020
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2019
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Northern Region
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(MMboe)
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(% of total)
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(MMboe)
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(% of total)
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Williston Basin
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80.2
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22
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%
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116.0
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30
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%
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Other Northern
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—
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—
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%
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—
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—
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%
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Southern Region
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Permian Basin
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283.2
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78
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%
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266.3
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70
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%
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Other Southern
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—
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—
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%
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—
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—
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%
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Total proved reserves
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363.4
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100
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%
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382.3
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100
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%
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QEP's total proved reserves as of December 31, 2020, decreased 18.9 MMboe from December 31, 2019, primarily due to lower commodity prices and production in 2020, partially offset by changes in capital development plans and sequence to continue to focus on Free Cash Flow generation.
Proved Undeveloped Reserves
Significant changes to PUD reserves that occurred during 2020 are summarized in the table below:
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2020
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(MMboe)
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Proved undeveloped reserves at January 1,
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191.9
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Transferred to proved developed reserves
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(30.1)
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Revisions to previous estimates
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37.6
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Proved undeveloped reserves at December 31,
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199.4
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Transfers to proved developed reserves. The costs incurred for the development of PUD reserves were approximately $222.3 million, $426.1 million and $606.5 million for the years ended December 31, 2020, 2019 and 2018, respectively.
QEP's planned and actual transfers of proved undeveloped reserves to proved developed reserves results for the year ended December 31, 2020 are summarized in the table below:
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Planned Transfers to Proved Developed Reserves in 2020 as of December 31, 2019 (PUD conversions)
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Actual Transfers to Proved Developed Reserves in 2020 (PUD conversions)
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Difference
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(MMboe)
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Northern Region
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Williston Basin
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8.5
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0.6
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(7.9)
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Other Northern
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—
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—
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—
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Southern Region
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Permian Basin
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29.5
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29.5
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—
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Other Southern
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—
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—
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—
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Total
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38.0
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30.1
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(7.9)
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QEP transferred 30.1 MMboe of PUD reserves to proved developed reserves in 2020 compared to 38.0 MMboe that were planned for 2020. QEP's PUD reserve conversion rate (the percentage of booked PUD reserves) was 16%, 10% and 12% for the years ended December 31, 2020, 2019 and 2018, respectively. At December 31, 2019, QEP's planned PUD reserve conversion rate for 2020 was 20%. QEP converted 18% and 2%, respectively, of the Permian and Williston basin PUD reserves in 2020. QEP converted fewer PUD reserves than expected in the Williston Basin, primarily due to the Company's decision to reduce completion activity and suspend the refracturing program in the Williston Basin during 2020 in light of market conditions.
All of QEP's proved undeveloped reserves at December 31, 2020 are scheduled to be developed within five years from the date such locations were initially disclosed as proved undeveloped reserves. In accordance with the SEC rules, QEP removes reserves associated with a PUD location from reported proved reserves if such location is scheduled, under the then-current development plan, to be drilled later than five years from the date that such location was first reported as PUD. QEP's five-year development plan generally does not contemplate a uniform (i.e. 20% per year) conversion of PUD reserves in all of its producing regions, and PUD reserve conversion rates will likely differ by producing region.
At December 31, 2020, QEP estimates that its future development costs relating to the development of PUD reserves are approximately $202.6 million in 2021, $289.1 million in 2022 and $365.8 million in 2023. QEP believes cash flow from operations and availability under its revolving credit facility will be sufficient to cover these estimated future development costs.
Revisions to previous estimates. Revisions to previous estimates reflect our ongoing evaluation of our asset portfolio. In 2020, our PUD reserves increased by 37.6 MMboe due to the factors summarized in the table below:
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2020
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(MMboe)
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Revisions due to:
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Changes in year-end prices (price impact to January 1, 2019 balance)
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(2.6)
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Positive performance
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1.9
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Change in development plans
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58.8
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Removal due to five year SEC rule
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(16.9)
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Other
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(3.6)
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Total revisions to prior estimates
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37.6
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In 2020, PUD reserves were revised upward by 37.6 MMboe. The increase was primarily due to our continued corporate strategy of generating Free Cash Flow through capital efficiency. This corporate strategy resulted in the addition of 58.8 MMboe of PUD reserves due to the change in the development sequence in the Permian Basin. This addition was partially offset by the removal of 16.9 MMboe of PUD reserves which will no longer be developed within five years of the initial date of booking the reserves due to the reduction in the capital program over the next five years, primarily in the Permian Basin.
Additional Disclosures
Refer to Note 15 – Supplemental Oil and Gas Information (unaudited) in Item 8 of Part II of this Annual Report on Form 10-K for more information pertaining to QEP's proved reserves as of the end of each of the last three years.
In addition to this filing, QEP will file reserve estimates as of December 31, 2020, with the Energy Information Administration of the Department of Energy (EIA) on Form EIA-23. Although QEP uses the same technical and economic assumptions when it prepares the Form EIA-23 as used to estimate reserves for this Annual Report on Form 10-K, it is obligated to report to the EIA reserves only for wells it operates, not for all of the wells in which it has an interest, and to include the reserves attributable to other owners in such wells.
Third Party Reserve Reports
The Company retained Ryder Scott Company, L.P. (RSC), independent oil and gas reserve evaluation engineering consultants, to prepare the estimates of all of its proved reserves as of December 31, 2020, 2019 and 2018.
Qualifications of Technical Person Preparing Reserve Reports
The individual at RSC who was responsible for overseeing the preparation of QEP's reserve estimates as of December 31, 2020, is a registered Professional Engineer in the States of Colorado and Texas and graduated with a Bachelor of Science degree in Mechanical Engineering from Brigham Young University in 2001. The individual has over 10 years of experience in the petroleum industry, including experience estimating and evaluating petroleum reserves. A more detailed letter, including such individual's professional qualifications, has been filed as part of Exhibit 99.1 to this report.
The individual at QEP responsible for ensuring the accuracy of the reserve estimate preparation material provided to RSC and reviewing the estimates of reserves received from RSC is QEP's Corporate Reserves Manager. This individual is a Licensed Professional Engineer in the State of Texas and graduated with a Bachelor of Science degree in Petroleum Engineering from Texas A&M University. This individual has over 34 years of experience in the petroleum industry, including 17 years of experience in corporate reserves management.
Technologies Used
To estimate proved reserves, the SEC allows a company to use technologies that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. A variety of methodologies were used to determine QEP's proved reserve estimates. The principal methodologies employed are performance, analogy and volumetric methods.
All of the proved producing reserves as of December 31, 2020, attributable to producing wells and/or reservoirs were estimated by performance methods. Volumetric measures are then used, when available, to further corroborate these reserve estimates. Performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of historical production data available through late 2020, in those cases where such data were considered to be definitive. For wells currently producing, forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.
All of QEP's proved developed non-producing and undeveloped reserves as of December 31, 2020 were estimated by analogy to offset producing wells. Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by QEP. Wells or locations that are not currently producing may start producing earlier or later than anticipated in these estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies. The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, 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.
Internal Controls Over Proved Reserve Estimates
At the end of each year, management develops a five-year capital expenditure plan based on QEP's best available data at the time the plan is developed. The Company's capital expenditure plan includes a development plan for converting PUD reserves. The development plan includes only PUD reserves that the Company is reasonably certain will be drilled within five years of booking based upon management's evaluation of a number of qualitative and quantitative factors, including estimated risk-based returns; estimated future location density; current commodity pricing and cost forecasts consistent with SEC guidelines; recent drilling and re-stimulated well results; availability of services, equipment, supplies and personnel; seasonal weather; and changes in drilling and completion techniques and technology. This process is intended to ensure that PUD reserves are only claimed for locations where a final investment decision has been made by the Company.
QEP maintains a Reserves Review Committee comprised of members of QEP's management team and the Company's Corporate Reserves Manager. The Reserves Review Committee meets on a semi-annual basis, including prior to the filing of reserve estimates with the SEC and any public disclosure of reserve estimates. The Reserves Review Committee reviews data that is submitted by the Corporate Reserves Manager to RSC, including cost and pricing assumptions and reserve reconciliations from the previous reserve determinations. The Corporate Reserves Manager's Annual Reserve Summary Report and the Reserve Committee's Certification are provided to the Audit Committee annually. The Audit Committee also meets annually with RSC to review the reserves estimation reporting process and disclosures. QEP's Board annually reviews the Company's five-year capital expenditure plan and approves the capital budget for the first year of the development plan.
Management reviews and revises the development plan throughout the year and may modify the development plan after evaluating a number of factors, including operating and drilling results; current and expected future commodity prices; estimated risk-based returns; estimated well density; advances in technology; cost and availability of services, equipment, supplies and personnel; acquisition and divestiture activity; and our current and projected financial condition and liquidity. Management reviews changes to the development plan with the Audit Committee and the Board quarterly. Changes in the development plan are also considered by management, the Corporate Reserves Manager and the Reserves Review Committee when reserves are estimated at year-end. If changes result in certain PUD reserves no longer being scheduled for development within five years from the date of initial booking, QEP reclassifies those PUD reserves to non-proved reserve categories. In addition, PUD locations and reserves may be removed from the development plan ahead of their five-year life expiration as a result of asset divestitures and acquisitions and associated changes in the priority of development within QEP's portfolio of assets.
Production, Prices and Production Costs
The following table sets forth the production volumes and field-level prices of oil and condensate, gas and NGL produced, and the related production costs, for the years ended December 31, 2020, 2019 and 2018:
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Year Ended December 31,
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2020
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2019
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2018
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Production volumes
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Oil and condensate (Mbbl)
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19,721.6
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21,558.3
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23,932.0
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Gas (Bcf)
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32.5
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33.1
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139.6
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NGL (Mbbl)
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5,185.1
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5,139.0
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4,661.4
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Total equivalent production (Mboe)
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30,324.9
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32,210.3
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51,857.9
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Average field-level price (1)
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Oil (per bbl)
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$
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35.08
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$
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52.54
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$
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59.43
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Gas (per Mcf)
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$
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1.22
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$
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1.58
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$
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2.82
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NGL (per bbl)
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$
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8.82
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$
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11.15
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$
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23.79
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Production costs (per Boe)
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Lease operating expense
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$
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4.67
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$
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5.68
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$
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5.07
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Adjusted transportation and processing costs(2)
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3.85
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3.22
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3.33
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Production and property taxes
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1.91
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2.98
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2.52
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Total production costs
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$
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10.43
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$
|
11.88
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$
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10.92
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____________________________
(1)The average field-level price does not include the impact of settled commodity price derivatives or transportation and processing costs reflected as part of "Oil and condensate, gas and NGL sales" on the Consolidated Statements of Operations.
(2)Adjusted transportation and processing costs (a non-GAAP measure) includes transportation and processing costs that are reflected as part of "Oil and condensate, gas and NGL sales" on the Consolidated Statements of Operations. Management adds these costs together with transportation and processing costs reflected on the Consolidated Statements of Operations to reflect the total operating costs associated with its production. Management believes that this non-GAAP measure is useful supplemental information for investors as it is reflective of the total production costs required to operate the wells for the period. This non-GAAP measure should be considered by the reader in addition to but not instead of, the financial statements prepared in accordance with GAAP. Refer to Operating Expenses and Note 2 – Revenue in Items 7 and 8, respectively, of Part II of this Annual Report on Form 10-K for more information.
A summary of oil and condensate production by major geographical area is shown in the following table:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Change
|
|
|
2020
|
|
2019
|
|
2018
|
|
2020 vs 2019
|
|
2019 vs 2018
|
|
Oil and condensate production volumes (Mbbl)
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
7,137.2
|
|
|
7,992.8
|
|
|
11,229.5
|
|
|
(855.6)
|
|
|
(3,236.7)
|
|
|
Uinta Basin
|
—
|
|
|
—
|
|
|
447.3
|
|
|
—
|
|
|
(447.3)
|
|
|
Other Northern
|
(0.4)
|
|
|
40.9
|
|
|
93.2
|
|
|
(41.3)
|
|
|
(52.3)
|
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
12,584.5
|
|
|
13,522.6
|
|
|
12,137.4
|
|
|
(938.1)
|
|
|
1,385.2
|
|
|
Haynesville/Cotton Valley
|
—
|
|
|
(0.4)
|
|
|
15.6
|
|
|
0.4
|
|
|
(16.0)
|
|
|
Other Southern
|
0.3
|
|
|
2.4
|
|
|
9.0
|
|
|
(2.1)
|
|
|
(6.6)
|
|
|
Total production
|
19,721.6
|
|
|
21,558.3
|
|
|
23,932.0
|
|
|
(1,836.7)
|
|
|
(2,373.7)
|
|
A summary of gas production by major geographical area is shown in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Change
|
|
|
2020
|
|
2019
|
|
2018
|
|
2020 vs 2019
|
|
2019 vs 2018
|
|
Gas production volumes (Bcf)
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
12.0
|
|
|
14.0
|
|
|
15.6
|
|
|
(2.0)
|
|
|
(1.6)
|
|
|
Uinta Basin
|
—
|
|
|
—
|
|
|
10.2
|
|
|
—
|
|
|
(10.2)
|
|
|
Other Northern
|
0.1
|
|
|
0.2
|
|
|
0.9
|
|
|
(0.1)
|
|
|
(0.7)
|
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
20.4
|
|
|
16.9
|
|
|
10.6
|
|
|
3.5
|
|
|
6.3
|
|
|
Haynesville/Cotton Valley
|
—
|
|
|
1.9
|
|
|
102.2
|
|
|
(1.9)
|
|
|
(100.3)
|
|
|
Other Southern
|
—
|
|
|
0.1
|
|
|
0.1
|
|
|
(0.1)
|
|
|
—
|
|
|
Total production
|
32.5
|
|
|
33.1
|
|
|
139.6
|
|
|
(0.6)
|
|
|
(106.5)
|
|
A summary of NGL production by major geographical area is shown in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Change
|
|
|
2020
|
|
2019
|
|
2018
|
|
2020 vs 2019
|
|
2019 vs 2018
|
|
NGL production volumes (Mbbl)
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
2,143.8
|
|
|
2,073.2
|
|
|
2,495.3
|
|
|
70.6
|
|
|
(422.1)
|
|
|
Uinta Basin
|
—
|
|
|
—
|
|
|
99.3
|
|
|
—
|
|
|
(99.3)
|
|
|
Other Northern
|
1.5
|
|
|
1.8
|
|
|
10.5
|
|
|
(0.3)
|
|
|
(8.7)
|
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
3,039.5
|
|
|
3,062.7
|
|
|
2,054.4
|
|
|
(23.2)
|
|
|
1,008.3
|
|
|
Haynesville/Cotton Valley
|
—
|
|
|
—
|
|
|
0.5
|
|
|
—
|
|
|
(0.5)
|
|
|
Other Southern
|
0.3
|
|
|
1.3
|
|
|
1.4
|
|
|
(1.0)
|
|
|
(0.1)
|
|
|
Total production
|
5,185.1
|
|
|
5,139.0
|
|
|
4,661.4
|
|
|
46.1
|
|
|
477.6
|
|
A summary of total oil equivalent production by major geographical area is shown in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Change
|
|
|
2020
|
|
2019
|
|
2018
|
|
2020 vs 2019
|
|
2019 vs 2018
|
|
Total production volumes (Mboe)
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
11,284.9
|
|
|
12,403.8
|
|
|
16,331.3
|
|
|
(1,118.9)
|
|
|
(3,927.5)
|
|
|
Uinta Basin
|
—
|
|
|
—
|
|
|
2,243.5
|
|
|
—
|
|
|
(2,243.5)
|
|
|
Other Northern
|
12.0
|
|
|
71.6
|
|
|
247.1
|
|
|
(59.6)
|
|
|
(175.5)
|
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
19,023.8
|
|
|
19,406.6
|
|
|
15,960.3
|
|
|
(382.8)
|
|
|
3,446.3
|
|
|
Haynesville/Cotton Valley
|
—
|
|
|
310.5
|
|
|
17,050.5
|
|
|
(310.5)
|
|
|
(16,740.0)
|
|
|
Other Southern
|
4.2
|
|
|
17.8
|
|
|
25.2
|
|
|
(13.6)
|
|
|
(7.4)
|
|
|
Total production
|
30,324.9
|
|
|
32,210.3
|
|
|
51,857.9
|
|
|
(1,885.4)
|
|
|
(19,647.6)
|
|
A regional comparison of average field-level prices (excluding the impact of settled commodity price derivatives or transportation and processing costs reflected as part of "Oil and condensate, gas and NGL sales" on the Consolidated Statements of Operations) and average production costs (excluding production and property taxes) per Boe is shown in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Change
|
|
|
2020
|
|
2019
|
|
2018
|
|
2020 vs 2019
|
|
2019 vs 2018
|
|
Average field-level oil price (per bbl)
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
$
|
35.04
|
|
|
$
|
52.52
|
|
|
$
|
62.63
|
|
|
$
|
(17.48)
|
|
|
$
|
(10.11)
|
|
|
Southern Region
|
$
|
35.10
|
|
|
$
|
52.55
|
|
|
$
|
56.34
|
|
|
$
|
(17.45)
|
|
|
$
|
(3.79)
|
|
|
Average field-level oil price
|
$
|
35.08
|
|
|
$
|
52.54
|
|
|
$
|
59.43
|
|
|
$
|
(17.46)
|
|
|
$
|
(6.89)
|
|
|
Average field-level gas price (per Mcf)
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
$
|
1.59
|
|
|
$
|
2.36
|
|
|
$
|
2.71
|
|
|
$
|
(0.77)
|
|
|
$
|
(0.35)
|
|
|
Southern Region
|
$
|
1.00
|
|
|
$
|
1.00
|
|
|
$
|
2.84
|
|
|
$
|
—
|
|
|
$
|
(1.84)
|
|
|
Average field-level gas price
|
$
|
1.22
|
|
|
$
|
1.58
|
|
|
$
|
2.82
|
|
|
$
|
(0.36)
|
|
|
$
|
(1.24)
|
|
|
Average field-level NGL price (per bbl)
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
$
|
6.70
|
|
|
$
|
9.37
|
|
|
$
|
23.56
|
|
|
$
|
(2.67)
|
|
|
$
|
(14.19)
|
|
|
Southern Region
|
$
|
10.31
|
|
|
$
|
12.36
|
|
|
$
|
24.09
|
|
|
$
|
(2.05)
|
|
|
$
|
(11.73)
|
|
|
Average field-level NGL price
|
$
|
8.82
|
|
|
$
|
11.15
|
|
|
$
|
23.79
|
|
|
$
|
(2.33)
|
|
|
$
|
(12.64)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating and adjusted transportation and processing costs (per Boe)
|
|
Northern Region
|
$
|
12.99
|
|
|
$
|
13.70
|
|
|
$
|
12.90
|
|
|
$
|
(0.71)
|
|
|
$
|
0.80
|
|
|
Southern Region
|
$
|
7.95
|
|
|
$
|
7.55
|
|
|
$
|
5.82
|
|
|
$
|
0.40
|
|
|
$
|
1.73
|
|
|
Adjusted average lease operating and transportation and processing costs
|
$
|
8.52
|
|
|
$
|
8.90
|
|
|
$
|
8.40
|
|
|
$
|
(0.38)
|
|
|
$
|
0.50
|
|
Northern Region
Williston Basin
Production volumes decreased 9% to 11,284.9 Mboe during 2020 compared to 2019, primarily as a result of the reduction in operated completion activity and suspension of the refracturing program beginning in the second quarter of 2020 through the end of the year in order to proactively manage Free Cash Flow and preserve liquidity as a result of the COVID-19 pandemic and challenging market conditions. The decrease in production volumes was partially offset by increased non-operated activity during the fourth quarter of 2020.
Production volumes decreased 24% to 12,403.8 Mboe during 2019 compared to 2018, primarily as a result of reduced capital expenditures in 2019 in order to focus on generating Free Cash Flow and natural production decline, partially offset by seven new operated well completions and two refractured operated wells, which were put on production in the fourth quarter of 2019.
During the years ended December 31, 2020, 2019 and 2018, Williston Basin production represented 37%, 39% and 31%, respectively, of QEP's total equivalent production.
Uinta Basin
Due to the divestiture of the Uinta Basin properties in September 2018, there was no production during the years ended December 31, 2020 and 2019.
During the year ended December 31, 2018, Uinta Basin production represented 4% of QEP's total equivalent production.
Other Northern
Production volumes decreased 83% and 71% during the years ended December 31, 2020 and 2019, respectively, primarily due to the continued divestiture of properties during 2020 and 2019.
During the years ended December 31, 2020, 2019 and 2018, Other Northern production represented less than 1% of QEP's total equivalent production.
Southern Region
Permian Basin
Production volumes decreased 2% to 19,023.8 Mboe during 2020 compared to 2019, primarily as a result of the suspension of completion operations in the Permian Basin beginning in March 2020 until the fourth quarter of 2020 in order to proactively manage Free Cash Flow and preserve liquidity as a result of the COVID-19 pandemic and challenging market conditions. This was partially offset by 50 new operated well completions that were put on production during the year ended December 31, 2020.
Production volumes increased 22% to 19,406.6 Mboe during 2019 compared to 2018, primarily as a result of continued horizontal development activities in the Spraberry Shale and Wolfcamp formations.
During the years ended December 31, 2020, 2019 and 2018, Permian Basin production represented 63%, 60%, and 31% respectively, of QEP's total equivalent production.
Haynesville/Cotton Valley
Due to the divestiture of the Haynesville/Cotton Valley properties in January 2019, there was no production during the year ended December 31, 2020.
Production volumes decreased 98% to 310.5 Mboe during 2019 compared to 2018, due to the divestiture of the Haynesville/Cotton Valley properties in January 2019.
During the years ended December 31, 2019 and 2018, Haynesville/Cotton Valley's production represented 1% and 34%, respectively, of QEP's total equivalent production.
Other Southern
Production volumes decreased 76% and 29% during the years ended December 31, 2020 and 2019, respectively, due to the continued divestiture of properties.
During the years ended December 31, 2020, 2019 and 2018, Other Southern production represented less than 1% of QEP's total equivalent production.
Productive Wells
The following table summarizes the Company's operated and non-operated productive wells as of December 31, 2020, all of which are located in the U.S.:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil(1)
|
|
|
Gross
|
|
Net
|
|
Northern Region
|
|
|
|
|
Williston Basin
|
740
|
|
|
366.4
|
|
|
Other Northern
|
—
|
|
|
—
|
|
|
Southern Region
|
|
|
|
|
Permian Basin
|
833
|
|
|
788.3
|
|
|
Other Southern
|
—
|
|
|
—
|
|
|
Total productive wells
|
1,573
|
|
|
1,154.7
|
|
____________________________
(1)These totals represent productive wells as of December 31, 2020, primarily in our core operating areas of the Williston and Permian basins. In addition to the table above, QEP has interests, primarily overriding royalty interests, in a number of wells outside of our core areas that have minimal revenues and reserves.
Although many wells produce both oil and gas, and many gas wells also have allocated NGL volumes from gas processing, a well is categorized as either an oil well or a gas well based upon the ratio of oil to gas produced at the wellhead. As of December 31, 2020, the Company only had oil wells. Additionally, each well completed in more than one producing zone is counted as a single well.
Acreage
The following table summarizes developed and undeveloped acreage in which the Company owns a working interest or a mineral interest as of December 31, 2020. "Undeveloped Acreage" includes leasehold interests that may already 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 or other similar interests. All leasehold acres are located in the U.S.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed Acres(1)
|
|
Undeveloped Acres(2)
|
|
Total Acres
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
North Dakota
|
80,572
|
|
|
64,030
|
|
|
31,897
|
|
|
30,580
|
|
|
112,469
|
|
|
94,610
|
|
|
Texas
|
34,552
|
|
|
34,240
|
|
|
16,172
|
|
|
14,822
|
|
|
50,724
|
|
|
49,062
|
|
|
Other
|
4,065
|
|
|
2,126
|
|
|
—
|
|
|
—
|
|
|
4,065
|
|
|
2,126
|
|
|
Total
|
119,189
|
|
|
100,396
|
|
|
48,069
|
|
|
45,402
|
|
|
167,258
|
|
|
145,798
|
|
____________________________
(1)Developed acreage is leased acreage or mineral interests assigned to productive wells.
(2)Undeveloped acreage is leased acreage and mineral interests 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
The majority of our leasehold acreage is held by production. The Company also has drilling and development agreements with third parties that require drilling obligations be met within the lease term in order to retain leasehold acreage. A portion of the leases covering the acreage summarized in the preceding table will expire at the end of their respective primary lease terms unless the leases are renewed, extended or drilling or production has occurred on the acreage subject to the lease prior to that date. Leases held by production generally remain in effect until production ceases. The following table sets forth the gross and net undeveloped acres subject to leases summarized in the preceding table that will expire during the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Undeveloped Acres Expiring
|
|
|
Gross
|
|
Net
|
|
Year ending December 31,
|
|
|
|
|
2021
|
800
|
|
|
347
|
|
|
2022
|
—
|
|
|
—
|
|
|
2023
|
480
|
|
|
70
|
|
|
2024
|
—
|
|
|
—
|
|
|
2025 and later
|
—
|
|
|
—
|
|
|
Total
|
1,280
|
|
|
417
|
|
Drilling Completion and Production Activities
The following table summarizes the total number of development and exploratory wells drilled (defined to include the number of wells completed at any time during the applicable year, regardless of when drilling was initiated), including both operated and non-operated wells, during the years indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development Wells
|
|
Exploratory Wells
|
|
|
Productive
|
|
Dry
|
|
Productive
|
|
Dry
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Year Ended December 31, 2020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
18
|
|
|
4.8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Other Northern
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
54
|
|
|
48.8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Other Southern
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total
|
72
|
|
|
53.6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Year Ended December 31, 2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
26
|
|
|
8.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Other Northern
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
64
|
|
|
59.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Haynesville/Cotton Valley
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Other Southern
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total
|
90
|
|
|
67.7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Year Ended December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
24
|
|
|
10.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Uinta Basin
|
2
|
|
|
2.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Other Northern
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
106
|
|
|
105.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Haynesville/Cotton Valley
|
16
|
|
|
4.6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Other Southern
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total
|
148
|
|
|
122.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
The following table presents operated and non-operated wells in the process of being drilled or waiting on completion as of December 31, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operated
|
|
Non-operated
|
|
|
Drilling
|
|
Drilling
|
|
Waiting on completion
|
|
Drilling
|
|
Waiting on completion
|
|
|
Rigs
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
2.9
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|
0.1
|
|
|
Other Northern
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin(1)
|
2
|
|
|
8
|
|
|
7.0
|
|
|
48
|
|
|
41.8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Other Southern
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
____________________________
(1)The number of gross operated drilling wells in the Permian Basin includes 6 wells for which surface casing has been set as of December 31, 2020.
Each gross well completed in more than one producing zone is counted as a single well. Delays and well shut-ins resulting from multi-well pad drilling have caused and may continue to cause volatility in QEP's quarterly operating results. In addition, delays in completion of wells could impact planned conversion of PUD reserves to proved developed reserves.
The following table presents the number of operated wells in the process of being drilled or waiting on completion at December 31, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
|
Williston Basin
|
|
|
December 31, 2020
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Well Progress
|
|
|
|
|
|
|
|
|
Drilling
|
8
|
|
|
7.0
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Waiting to be completed
|
42
|
|
|
36.6
|
|
|
4
|
|
|
2.9
|
|
|
|
|
|
|
|
|
|
|
|
Completed, awaiting production
|
6
|
|
|
5.2
|
|
|
—
|
|
|
—
|
|
|
Waiting on completion
|
48
|
|
|
41.8
|
|
|
4
|
|
|
2.9
|
|
The following table presents the number of operated and non-operated wells completed and turned to sales (put on production) for the year ended December 31, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operated Put on Production
|
|
Non-operated Put on Production
|
|
|
Year Ended December 31, 2020
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Northern Region
|
|
|
|
|
|
|
|
|
Williston Basin
|
2
|
|
|
1.5
|
|
|
16
|
|
|
3.3
|
|
|
Other Northern
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Southern Region
|
|
|
|
|
|
|
|
|
Permian Basin
|
50
|
|
|
48.4
|
|
|
4
|
|
|
0.4
|
|
|
Other Southern
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Delivery Commitments
QEP is a party to various long-term agreements that require us to physically deliver oil and condensate and gas with future firm delivery commitments as follows:
|
|
|
|
|
|
|
|
|
Delivery Commitments
|
|
Period
|
(MMboe)(1)
|
|
2021
|
19.8
|
|
|
Thereafter
|
32.6
|
|
____________________________
(1) Includes delivery commitments related to future obligations in an area in which the Company no longer has
production operations. During the year ended December 31, 2019, the Company recognized $7.7 million of firm
transportation expense related to the future obligations in this area.
These commitments are physical delivery obligations with prices based on prevailing index prices for oil and condensate and gas at the time of delivery or contracted gathering arrangements that require delivery of a fixed and determinable quantity of oil and condensate or gas in the future. None of these commitments require the Company to deliver oil and condensate or gas produced specifically from any of the Company's properties. The Company believes that its production and reserves should be adequate to meet its term sales commitments or that it can purchase sufficient volumes of oil and condensate or gas in the market at index-related prices to satisfy its sales commitments. The Company has incurred shortfalls related to some of its gathering and firm transportation commitments and as a result paid contractual obligations of $8.9 million, $8.3 million and $13.4 million for the years ended December 31, 2020, 2019 and 2018, respectively, for deficiencies associated with gathering and firm physical delivery obligations. See also Part II, Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations – Contractual Obligations, in this Annual Report on Form 10-K for discussion of firm transportation commitments related to oil and condensate and gas deliveries.
In addition, at December 31, 2020, the Company did not have a significant amount of production from QEP's owned properties that was subject to priorities or curtailments that may affect quantities delivered to its customers, priority allocations or price limitations imposed by federal or state regulatory agencies, or any other factors beyond the Company's control that may affect its ability to meet its contractual obligations other than those discussed in Part I, Item 1A – Risk Factors, in this Annual Report on Form 10-K.
Seasonality
QEP drills and completes wells throughout the year, but adverse weather conditions can impact drilling, completion and field operations, which can impact overall production volumes. Seasonal anomalies can minimize or exaggerate the impact on these operations, while extreme weather events can materially constrain our operations for short periods of time.
Significant Customers
QEP's five largest customers accounted for 63%, 66% and 49%, in the aggregate, of QEP's revenues for the years ended December 31, 2020, 2019 and 2018, respectively. The following table presents the percentages by customer that accounted for 10% or more of QEP's total revenues. Management believes that the loss of any of these customers, or any other customer, would not have a material effect on the financial position or results of operations of QEP, since there are numerous potential purchasers of its production. Refer to Part I, Item 1A- Risk Factors, in this Annual Report on Form 10-K for additional discussion of QEP's competition.
|
|
|
|
|
|
|
|
Year Ended December 31, 2020
|
|
|
Valero Marketing & Supply Company
|
30
|
%
|
|
Phillips 66 Company
|
12
|
%
|
|
|
|
|
Year Ended December 31, 2019
|
|
|
Occidental Energy Marketing
|
21
|
%
|
|
Valero Marketing & Supply Company
|
18
|
%
|
|
Plains Marketing LP
|
17
|
%
|
|
|
|
|
Year Ended December 31, 2018
|
|
|
Occidental Energy Marketing
|
16
|
%
|
|
Plains Marketing LP
|
12
|
%
|
Competition
QEP faces competition in every facet of its business, including the acquisition of producing leaseholds, wells and undeveloped leaseholds, the marketing of oil and condensate, gas and NGL products and the procurement of goods, services and labor. The Company's competitors include national oil companies, major integrated oil and gas companies, independent oil and gas companies, individual producers, gas marketers and major pipeline companies, as well as participants in other industries supplying energy, fuel and services to consumers.
Human Capital Measures
Employees
At QEP, people are our most important asset. At December 31, 2020 and 2019, QEP had 257 and 248 employees, respectively. As of December 31, 2020, 52 employees were in the Permian Basin operating area, 39 employees were in the Williston Basin operating area and 166 employees were in our Denver corporate headquarters. None of QEP's employees are represented by unions or covered by collective bargaining agreements.
Health, Safety & Environment (HSE)
QEP strives to minimize our impact to the environment where we operate, and we focus on the protection of the health, safety and well-being of our employees, contractors, families, friends and neighbors. These are fundamental responsibilities of our company and of each employee. We believe that no aspect of our operations is of greater importance. Our adherence to industry regulations and state-of-the-art well construction methods, paired with ongoing water, air and land conservation initiatives, help to ensure we conduct our business with respect and care for the environment, and manage risks to drive sustainable business growth. Our HSE program includes the following results and practices:
•During the year ended December 31, 2020, QEP had zero recordable injuries for employees. During the year ended December 31, 2019, the total recordable injury rate (TRIR) for employees was 0.32.
•All employees and contractors performing work on QEP sites are required to participate in orientations prior to the commencement of work.
•Employees and contractors working for QEP have the authority and the responsibility to stop any job or work that they feel is unsafe or poses a threat to the environment.
•Our governance model ensures that we are upholding our commitment to HSE and includes: (1) integration of HSE metrics in QEP’s pay and annual incentive plan; (2) monthly and quarterly reviews of HSE performance, including key performance indicators, with our Board, management and employees; (3) compliance testing through an internal audit program; and (4) organizational focus on continuous improvement.
•QEP’s HSE Policy is posted on our website.
Culture
Respectful, resourceful and responsible are the foundation of our values as we work to achieve our vision and mission. QEP’s culture model, “How We Work Together,” consists of the following pillars: transparency, humility, inclusion, alignment and execution, in addition to our core focus on HSE.
Inclusion & Diversity
Consistent with our values, QEP is committed to providing an inclusive work environment that recognizes the contributions of individuals with varied backgrounds, perspectives and personal attributes. We seek to promote inclusion and diversity (I&D) in our workforce through our focus on inclusion in our culture model and through training and development. We strive to improve our record on I&D through our promotion and hiring practices.
At December 31, 2020, women and minorities accounted for approximately 32% and 18%, respectively, of our total workforce and two of the seven seats on our Board were held by women, including our Board Chair. Female Board directors also chair one-third of our Board Committees.
QEP invested in several company-wide initiatives in 2020 to further our focus on I&D, including:
•I&D training completed by QEP employees and our Board;
•Launching our first I&D employee survey to identify areas where QEP is doing well and areas where we can continue to evolve and improve;
•Fostering communications among employees of varied backgrounds, perspectives and experiences, through various QEP sponsored employee programs; and
•Supporting I&D through our community volunteering and investment program, QEP Cares.
Recruiting & Hiring Practices
At QEP, we strive to recruit and hire qualified employees who are seeking challenging opportunities in a fast-paced, results-focused culture that values safety and rewards performance. QEP is proud of its work environment that respects the dignity and diversity of each individual and considers applications for employment without regard to the applicant’s race, color, national origin, sex, religion, creed, age, sexual orientation, gender identity, marital status, disability, protected veterans or any other characteristics protected by law. QEP’s equal employment opportunity policy applies to all persons involved in our operations and activities, including recruiting, hiring, training, transfers, promotions and benefits.
Compensation and Benefits
QEP strives to be an employer of choice in our industry. We offer a flexible and competitive compensation and benefits program, designed to help employees and their families grow personally, professionally and financially, including:
•Industry-competitive, performance-based compensation;
•Annual incentive plan based on company-wide performance targets and individual contributions;
•Long-term incentives, including stock-based compensation plans to share in QEP’s success;
•Industry-competitive benefits designed for flexibility and meeting personal needs, including comprehensive health and welfare plans and a 401(k) program with company contributions and matching; and
•Company matching charitable giving programs and volunteer paid time off.
Training & Development
QEP invests in our employees’ professional growth to build strong teams and develop leaders for today and the future. We build our dynamic team of industry leading professionals by engaging them in interesting and rewarding work and by providing training and development opportunities. In addition to ongoing operations and compliance training, in 2020 we delivered courses in safety, professional development, performance management, information technology skills, business functional skills, I&D and leadership skills.
Due to the COVID-19 pandemic, we adjusted our training delivery methods by offering virtual training whenever possible to ensure employees were able to participate safely. Additionally, QEP is proud to offer an education reimbursement benefit to employees to complete applicable post-secondary courses.
Succession Planning
In 2020, QEP conducted a comprehensive succession planning process that involved assessment of talent across the organization. We evaluated employee performance and potential as well as readiness of potential successors for key roles and developmental needs. Succession planning informs our executives and Board in making compensation, development and promotional decisions. The succession process includes creating development plans to ensure our leaders are ready to take the next step in their careers and evaluating our bench strength for key positions as well as talent gaps within the organization. Succession planning occurs annually to ensure the continuity of our business and to provide challenging and rewarding career opportunities for our employees.
Information about our Executive Officers
The name, age, period of service, title and business experience of each of QEP's executive officers as of February 17, 2021, are listed below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Timothy J. Cutt
|
|
60
|
|
President and Chief Executive Officer (January 2019 to present). Prior to joining QEP, Mr. Cutt was the Chief Executive Officer of Cobalt International Energy, a development-stage petroleum exploration and production company (2016 to 2018). Cobalt International voluntarily filed a petition for relief under Chapter 11 of the United States Bankruptcy Code on December 14, 2017, and a plan to sell all the assets of the company was approved on April 10, 2018. Prior to joining Cobalt International, Mr. Cutt served as President of the Petroleum Division of BHP Billiton, a global natural resources company (2013 to 2016), and prior to that he also served as President of Production for BHP Billiton's Petroleum Division (2007 to 2011). Prior to joining BHP Billiton, Mr. Cutt served in various roles at ExxonMobil in the prior 25 years, including President of ExxonMobil de Venezuela (2005 to 2007), President ExxonMobil Canada Energy (2004 to 2005), President Hibernia Management & Development Company (2001 to 2004) and Regional Coordinator, North America (2000 to 2001).
|
|
Christopher K. Woosley
|
|
51
|
|
Executive Vice President, General Counsel and Corporate Secretary (January 2020 to present). Senior Vice President and General Counsel (2017 to 2019). Vice President and General Counsel (2012 to 2016).Corporate Secretary (2016 to 2017). Senior Attorney (2010 to 2012). Prior to joining QEP, Mr. Woosley was a partner in the law firm Cooper Newsome & Woosley PLLP (2003 to 2010).
|
|
William J. Buese
|
|
49
|
|
Vice President, Chief Financial Officer and Treasurer (January 2020 to present). Vice President Finance and Treasurer (2014-2019). Director of Finance (2012-2014). Prior to joining QEP, Mr. Buese was Director, Finance at MarkWest Energy Partners, LP, and served in various finance, treasury, accounting and investor relations roles (2005-2012). Prior to joining MarkWest, Mr. Buese was employed in a non-energy-related industry for more than 10 years.
|
Joseph T. Redman
|
|
43
|
|
Vice President, Energy (2019 to present). Vice President, Western Region (2017 to 2019). General Manager (2012-2017). Operations and Engineering Manager (2010-2012). Previous titles with Questar Corporation: Staff Petroleum Engineer/Supervisor ((2010). Senior Petroleum Engineer (2008-2010). Reservoir Engineer (2006-2008). Prior to joining Questar, Mr. Redman worked in the pipeline industry.
|
There is no family relationship between any of the listed officers or between any of them and the Company's Board of Directors. The executive officers serve at the pleasure of the Company's Board of Directors. There is no arrangement or understanding under which any of the officers were selected.
Government Regulation
QEP's business operations are subject to a wide range of local, state, tribal and federal statutes, rules, orders and regulations. The regulatory environment in which the oil and gas industry operates increases the cost of doing business and consequently affects profitability. The following discussion of certain laws and regulations should not be considered an exhaustive review of all regulatory considerations affecting QEP's operations. See additional discussion of regulations under Part I, Item 1A – Risk Factors, in this Annual Report on Form 10-K. Moreover, uncertainty about the future course of regulation exists because of the recent change in the U.S. presidential administration. In January 2021, the current administration issued an executive order directing all federal agencies to review and take action to address any federal regulations, orders, guidance documents, policies and any similar agency actions promulgated during the prior administration that may be inconsistent with the administration’s policies. As a result, it is unclear the degree to which certain recent regulatory developments may be modified or rescinded. The executive order also established an Interagency Working Group on the Social Cost of Greenhouse Gases (Working Group), which is called on to, among other things, develop methodologies for calculating the “social cost of carbon,” “social cost of nitrous oxide” and “social cost of methane." Recommendations from the Working Group are due beginning June 1, 2021, and final recommendations no later than January 2022. Further regulation of air emissions, as well as uncertainty regarding the future course of regulation, could eventually reduce the demand for oil and natural gas. Also in January 2021, the current administration issued an executive order focused on addressing climate change (2021 Climate Change Executive Order). Among other things, the 2021 Climate Change Executive Order directed the Secretary of the Interior to pause new oil and natural gas leasing on public lands or in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices, consider whether to adjust royalties associated with coal, oil, and gas resources extracted from public lands and offshore waters, or take other appropriate action, to account for corresponding climate costs. The 2021 Climate Change Executive Order also directs the federal government to identify "fossil fuel subsidies" to take steps to ensure that, to the extent consistent with applicable law, federal funding is not directly subsidizing fossil fuels. Legal challenges to the suspension have already been filed and are currently pending.
Regulation of Exploration and Production Activities
The regulation of oil and gas E&P activities is a broad and increasingly complex area, notably including laws and regulations governing the potential discharge or release of materials into the environment or otherwise relating to environmental protection. These laws and regulations include, but are not limited to, the following:
Clean Air Act. The federal Clean Air Act and similar state laws regulate the emission of air pollutants from equipment and facilities employed by QEP in its business, including, but not limited to, engines, tanks and dehydrators. In 2012 and 2016, the Environmental Protection Agency (EPA) adopted various regulations specific to oil and gas exploration, production, gathering and processing, which impose air quality controls and work practices, and govern source determination and permitting requirements, and methane emissions. In September 2018, the EPA announced proposed revisions to the various regulations which may reduce compliance burdens on some facilities. In August 2019, the EPA proposed two options for further revising its methane regulations. In August 2020, the EPA adopted deregulatory amendments to the 2016 rule intended to streamline implementation, reduce duplicative EPA and state requirements and decrease the burden of compliance. In particular, the amendments removed the transmission and storage segments from the oil and natural gas source category and rescinded the methane-specific requirements for production and processing facilities. Several lawsuits were filed challenging these amendments, and the U.S. Court of Appeals for the D.C. Circuit ordered an administrative stay of these amendments shortly after they were finalized. Although the administrative stay was lifted in October 2020, which brought the amendments into effect, the amendments may still be subject to reversal under the current presidential administration. In January 2021, the administration issued an executive order calling on the EPA to, among other things, consider a proposed rule suspending, revising or rescinding the deregulatory amendments by September 2021. Regulatory uncertainty surrounding the implementation of such revisions and the potential for legal challenges to them pose some complications for QEP's ongoing operations and compliance efforts. Additionally, many states are adopting air permitting and other air quality control regulations specific to oil and gas exploration, production, gathering and processing that are more stringent than existing requirements under federal regulations. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues.
In June 2016, the EPA issued a Federal Implementation Plan (FIP) to implement the Federal Minor New Source Review Program on tribal lands for oil and gas production. The FIP primarily impacts QEP's operations on the Fort Berthold Reservation in the Williston Basin. The FIP creates a permit-by-rule process for minor sources that also incorporates emission limits and other requirements under various federal air quality standards, applying them to a range of equipment and processes used in oil and gas production and gathering.
Greenhouse Gas Regulations and Climate Change Legislation. In recent years, the EPA has adopted and substantially expanded regulations for the measurement and annual reporting of carbon dioxide, methane and other GHG emitted from certain large facilities, including onshore oil and gas production, processing, transmission, storage and distribution facilities. In addition, both houses of Congress have considered legislation to reduce emissions of GHG, and a number of states have taken, or are considering taking, legal measures to reduce emissions of GHG, primarily through the development of GHG inventories, GHG permitting, state or regional GHG cap and trade programs, and/or mandates for the use of renewable energy. Many states and local governments are undertaking efforts to meet climate goals which could restrict development of oil and gas as well as lessen demand depending on the specific initiatives. Foreign governments' pursuit of climate change goals could also impact demand and reduce prices on U.S. oil and natural gas. In January 2021, President Biden issued the 2021 Climate Change Executive Order that, among other things, sets goals of a carbon pollution free power sector by 2035 and a net zero economy by 2050. It also commenced the process for the U.S. reentering the Paris Climate Agreement, although the emissions pledges in connection with that effort have not yet been updated. The 2021 Climate Change Executive Order starts a process of developing a U.S. emissions target as well as a climate finance plan.
Bureau of Land Management Venting and Flaring Regulations. In November 2016, the Department of the Interior's Bureau of Land Management (BLM) finalized a rule to further control the venting, flaring and emission of natural gas on BLM and tribal leases (2016 Waste Prevention Rule). In September 2018, the BLM finalized a rule that revised and replaced the 2016 Waste Prevention Rule, effective November 2018 (2018 Revised Waste Prevention Rule). The Revised Waste Prevention Rule rescinds certain provisions of the 2016 Waste Prevention Rule, revises other provisions of the 2016 Waste Prevention Rule, and adds provisions deeming gas vented or flared in accordance with applicable state or tribal requirements to be royalty free. In July and October 2020, after several years of litigation, federal courts struck down both the BLM’s 2016 Waste Prevention Rule and its 2018 Revised Waste Prevention Rule. The effect of these orders combined is to essentially reinstate the previous rule, Notice to Lessees and Operators of Onshore Federal and Indian Oil and Gas Leases: Royalty or Compensation for Oil and Gas Lost (NTL-4A). The 2021 Climate Change Executive Order directs the Secretary of Interior to impose a moratorium on new oil and natural gas leases on public lands, or offshore waters to the extent possible, and launch a rigorous review of all existing leasing and permitting practices related to fossil fuel development on public lands. This moratorium may include restrictions of approving right-of-ways that could help build out midstream infrastructure needed to help reduce flaring.
Other BLM Regulations. In November 2016, the BLM finalized regulations that update and replace Onshore Orders No. 3 (Site Security), No. 4 (Measurement of Oil) and No. 5 (Measurement of Gas). These regulations increase compliance burdens on federal lessees and operators like QEP by requiring such lessees or operators to obtain numbers for all onshore points of federal royalty measurement from the BLM, adjusting recordkeeping requirements, and by imposing new oil and gas measurement equipment standards, among other requirements, for production from federal and Indian leases. Although these regulations took effect in January 2017, the BLM has delayed the requirement to obtain numbers for all onshore points of federal royalty measurement.
Clean Water Act and Safe Drinking Water Act. The federal Clean Water Act and similar state laws regulate discharges of wastewater, oil, fill material, and other pollutants into regulated "Waters of the United States" (or WOTUS). These laws also require the preparation and implementation of Spill Prevention, Control, and Countermeasure Plans in connection with on-site storage of significant quantities of oil. The scope of what areas constitute jurisdictional WOTUS regulated under the Clean Water Act has been the subject of litigation and related administrative matters since the EPA and the U.S. Army Corps of Engineers (Corps) in 2015 proposed to revise and expand the definition of WOTUS (2015 WOTUS Rule). However, in October 2019, the EPA and the Corps published a final rule repealing the 2015 WOTUS Rule and re-codifying the longstanding and familiar regulatory text that existed prior to the 2015 Rule. In January 2020, a new WOTUS rule (Navigable Waters Protection Rule) was finalized which replaced the 2015 rule. Under the final rule, the following four categories of waters would be defined as WOTUS: traditional navigable waters and territorial seas; perennial and intermittent tributaries to those waters; lakes, ponds and impoundments of jurisdictional waters. A federal district court issued a preliminary injunction preventing the Navigable Waters Protection Rule from taking effect in Colorado, but the rule is otherwise effective in every other state. Additional litigation and administrative proceedings are expected in the future. In addition, in April 2020, the U.S. Supreme Court issued a decision finding that point source discharges to navigable waters through groundwater are subject to regulation under the Clean Water Act. The U.S. Supreme Court specifically held that the Clean Water Act requires a permit if the addition of the pollutants through groundwater is the “functional equivalent” of a direct discharge from the point source into navigable waters. Areas regulated under comparable state laws are generally defined more broadly. The federal Safe Drinking Water Act (SDWA) and comparable state statutes strictly regulate the disposal of wastes via underground injection wells, including the disposal of produced water and other fluids generated during oil and gas production well development, to protect drinking water resources.
In January 2017, the Corps issued revised and renewed streamlined general nationwide permits (NWP) that are available to satisfy permitting requirements for certain work in streams, wetlands and other waters of the United States under Section 404 of the Clear Water Act and Section 10 of the Rivers and Harbors Act. The new NWPs took effect in March 2017, or when certified by each state, whichever was later. The oil and gas industry broadly utilizes NWPs 12, 14, and 39 for the construction, maintenance and repair of pipelines, roads, and drill pads, respectively, and related structures in waters of the United States that impact less than a half-acre of waters of the United States and meet the other criteria of each NWP. Other regional and statewide general permits are available in certain states that also authorize such activities under those statutes. In April 2020, the U.S. District Court for the District of Montana vacated the Corps’ 2017 issuance of NWP 12 (the general permit issued by the Corps for pipelines and utility projects). In May 2020, the court narrowed its ruling, vacating and enjoining the use of NWP 12 only as it relates to construction of new oil and gas pipelines. The Corps appealed the decision to the U.S. Court of Appeals for the Ninth Circuit and the litigation is ongoing. In July 2020, the U.S. Supreme Court granted in part and denied in part the Corps’ application for stay of the order issued by the district court. The U.S. Supreme Court stayed the lower court order except as it applies to the Keystone XL pipeline. The stay is to remain in place pending disposition of the appeal currently pending before the Ninth Circuit. In January 2021, the Corps released the final version of a rule renewing twelve of its NWPs, including NWP 12. The new rule splits NWP 12 into three parts; NWP 12 will continue to be available for oil and gas pipelines, while new NWP 57 will be available for electric utility line and telecommunications activities, and a new NWP 58 will be available for utility line activities for water and other substances. The new rule also eliminates preconstruction notice requirements for NWP 12 for several conditions that used to require such notice, but also now requires new oil and gas pipeline projects that exceed 250 miles in length to give preconstruction notice and obtain approval before proceeding. We cannot predict at this time how the new rule will be implemented, because permits are issued by the local Corps district offices, or whether it will remain in place following the review required by the Biden executive orders. However, if new oil and gas pipeline projects are unable to utilize NWP 12 or identify an alternate means of Clean Water Act compliance, such projects could be significantly delayed, which could have an adverse impact on our operations.
Oil Pollution Act of 1990. The federal Oil Pollution Act of 1990 (OPA) and regulations issued under the OPA impose strict, joint and several liability on "responsible parties" for removal costs and damages to natural resources resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States.
Comprehensive Environmental Response, Compensation and Liability Act of 1980. The federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA or Superfund) and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons who contributed to the release of a "hazardous substance" into the environment. Such responsible persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances released into the environment and for damage to natural resources. Such liability is in addition to claims for personal injury and property damage caused by the release of hazardous substances into the environment, which may also be made by third parties.
Resource Conservation and Recovery Act. The Resource Conservation and Recovery Act (RCRA) is the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements on a person who is either a "generator" or "transporter" of hazardous waste or an "owner" or "operator" of a hazardous waste treatment, storage or disposal facility. RCRA and many state counterparts specifically exclude from the definition of hazardous waste "drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of oil, gas or geothermal energy." Any repeal or modification of this RCRA oil and gas exploration and production waste exemption would increase the volume of hazardous waste QEP is required to manage and dispose of and would cause QEP, as well as its competitors, to incur increased operating expenses. In December 2016, the U.S. District Court for the District of Columbia approved a consent decree between the EPA and a coalition of ENGOs. The consent decree requires the EPA to review and determine whether it will revise the RCRA regulations for exploration and production waste to treat such waste as hazardous waste. The EPA concluded in 2019 that they did not need to regulate "drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of oil, gas or geothermal energy" after they reviewed the RCRA regulations for exploration and production waste. The EPA concluded that states were adequately regulating exploration and production waste under the subsection “D” provision of RCRA. The subsection “D” provision that provides for EPA exemption and provides for state management of said waste is reviewable by the EPA every three years.
Hydraulic Fracturing Regulations. QEP's current and future production and oil and gas reserves are derived from reservoirs that require hydraulic fracture stimulation to be commercially viable. Hydraulic fracture stimulation involves pumping fluid at high pressure into tight sand or shale reservoirs to artificially induce fractures. The artificially induced fractures allow better connection between the wellbore and the surrounding reservoir rock, thereby enhancing the productive capacity and ultimate hydrocarbon recovery of each well. The fracture stimulation fluid is typically composed of over 99% water and sand, with the remaining constituents consisting of chemical additives designed to optimize the fracture stimulation treatment and production from the reservoir. QEP discloses the contents of hydraulic fracturing fluids and submits information regarding its wells and the
fluids used in them, to the national online disclosure registry, FracFocus (www.fracfocus.org), and to state registries where required.
QEP obtains water for fracture stimulations from a variety of sources, including industrial water wells and surface water sources. When technically and economically feasible, QEP recycles flow-back and produced water for use in fracture stimulation, which reduces water consumption from surface and groundwater sources and reduces produced water disposal volumes. QEP transports both fresh and produced water by pipeline instead of truck when feasible to avoid truck traffic and emissions. QEP believes that the employment of fracture stimulation technology does not present any significant additional risks other than those associated with the disposal of waste water (see Item 1A - Risk Factors for more information) and those generally associated with oil and gas drilling, completion and production operations, such as the risk of spills, releases, discharges, accidents and injuries to persons and property.
Almost all oil and gas producing states require disclosure of the chemicals used in hydraulic fracturing and some form of reporting after a well is fractured. Some states have adopted additional requirements for hydraulic fracturing, such as notice to the surface owner or others, wellbore testing, ground water sampling, waste handling, and seismic monitoring. Other states rely for this purpose upon their existing regulatory programs for permitting wells, ensuring wellbore integrity, managing waste, and overseeing oil and gas development. A few states have imposed moratoria on hydraulic fracturing, but QEP does not operate in those states.
Federal regulation of hydraulic fracturing is currently limited but evolving. The EPA has regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the SDWA, but QEP does not use diesel fuel in any of its hydraulic fracturing fluids. In recent years, the EPA has adopted pretreatment standards under the Clean Water Act for hydraulic fracturing effluent, issued an advance notice of proposed rulemaking under the Toxic Substances Control Act to obtain data on hydraulic fracturing chemicals, and published a multi-year study on potential impacts to drinking water from hydraulic fracturing. Also, in 2016, the Occupational Safety and Health Administration (OSHA) adopted employee-protection requirements regarding silica, which is used in hydraulic fracturing fluids.
Tribal Lands and Minerals. Various federal agencies within the U.S. Department of the Interior, particularly the BLM and the Bureau of Indian Affairs (BIA), along with certain Native American tribes, promulgate and enforce regulations pertaining to oil and gas operations on Native American tribal lands and minerals where QEP operates. These regulations include, but are not limited to, such matters as lease provisions, drilling and production requirements, surface use restrictions, environmental standards, royalty considerations and taxes. In March 2016, the BIA implemented regulations significantly altering the procedure for obtaining rights-of-way on tribal lands. In certain cases, these new regulations have increased the time and cost required to obtain necessary rights-of-ways for operation on tribal lands for QEP and its competitors. The 2021 Climate Change Executive Order creates a moratorium on new oil and natural gas leases on public lands, or offshore waters to the extent possible, and launches a rigorous review of all existing leasing and permitting practices related to fossil fuel development on public lands. The executive order does not restrict energy activities on lands that the U.S. holds in trust for tribes. It is unclear how it impacts allotted lands and whether the executive order exempting tribal lands will continue to be exempt from the 2021 Climate Change Executive Order.
Endangered Species Act and National Environmental Policy Act. To develop federal or Indian leases, QEP must obtain authorizations from federal agencies, such as drilling permits and rights-of-way. Prior to issuing such authorizations, federal agencies must comply with both the Endangered Species Act and National Environmental Policy Act (NEPA). The Endangered Species Act restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal or permanent ban in affected areas. NEPA requires that federal agencies assess the direct, indirect and cumulative environmental impacts of their authorizations. This analysis is done in Environmental Assessments or Environmental Impact Statements prepared for a lead agency under the Council on Environmental Quality (CEQ) and other agency regulations, usually for the BLM in the areas where QEP operates. In January 2020, the CEQ announced a notice of proposed rulemaking to update procedural provisions and modernization of NEPA. The rulemaking was finalized in July 2020.
Emergency Planning and Community Right-to-Know Act and Occupational Safety and Health Act. Pursuant to the Emergency Planning and Community Right-to-Know Act (EPCRA), facilities that store, use or release certain chemicals are subject to various reporting requirements. EPCRA requirements include emergency planning notification, emergency release notification, and emergency and chemical inventory reporting to state and local emergency planning committees and emergency response departments. In January 2017, the EPA proposed to add natural gas processing facilities to the list of industrial facilities that must report under EPCRA's Toxic Release Inventory, but the proposed rule has not been finalized. OSHA establishes workplace standards for the protection of the health and safety of employees, including the implementation of a hazard communication program designed to inform all downstream users, including employees, about hazardous chemicals in the workplace, potential harmful effects of these chemicals, and appropriate control measures.
Transportation Regulations
Regulation of the Transportation and Sale of Natural Gas. The FERC regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 (Natural Gas Act) and the Natural Gas Policy Act of 1978 and regulations issued under those Acts. Under the Energy Policy Act of 2005, the FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. The gathering of natural gas is exempt from FERC regulation under the Natural Gas Act (referred to as "non-jurisdictional" gatherer and gathering lines/systems). However, there is no bright-line test for determining jurisdictional status. Under FERC's current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Our gas gathering system is not currently subject to state public utility regulations.
Regulation of Interstate Crude Oil Pipelines. Some of QEP's crude oil pipelines are subject to regulation by the Texas Railroad Commission (TRRC). The applicable state statutes require that pipeline rates be nondiscriminatory and provide no more than a fair return on the aggregate value of the pipeline property used to render services. QEP's crude oil pipelines (specifically the rates, terms and conditions for shipments) may also be subject to FERC regulation if QEP's crude oil pipelines provide part of the movement in interstate or foreign commerce for shippers (pursuant to the Interstate Commerce Act, as it existed on October 1, 1977, the Energy Policy Act of 1992 and related rules). QEP does not control the entire transportation path of all crude oil shipped on QEP's pipelines. Therefore, FERC regulation could be triggered by QEP's customers' transportation decisions.
Regulation of Pipeline Safety. QEP operates one crude oil pipeline subject to regulation by the Department of Transportation, through the Pipeline and Hazardous Materials Safety Administration (PHMSA), pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended (NGPSA), with respect to natural gas and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (HLPSA), with respect to crude oil. The NGPSA and HLPSA, as amended, govern the design, installation, testing, construction, operation, replacement and management of natural gas as well as crude oil, NGL and condensate pipeline facilities. The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 and the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 amended the NGPSA in an effort to reform PHMSA and to close potential gaps in federal pipeline safety regulation, as well as to increase the penalties for violations. Following those acts, PHMSA has proposed numerous changes to its regulations under the NGPSA, including expanding the scope of safety regulation of gathering pipelines. Historically, our pipeline safety compliance costs have not had a material adverse effect on our results of operations. However, we may incur additional compliance costs if PHMSA adopts new pipeline safety regulations in the future. For instance, in October 2019, PHMSA submitted three major rules to the Federal Register, including rules focused on: the safety of gas transmission pipelines (the first of three parts of the so-called PHMSA gas “Mega Rule” which took effect July 1, 2020); the safety of hazardous liquid pipelines; and enhanced emergency order procedures. PHMSA is expected to issue the second and third parts of the gas Mega Rule soon.
Transporting Crude Oil by Rail. QEP sells crude oil to customers that may transport crude oil by rail. In 2015, the U.S. Department of Transportation issued a final rule regarding the safe transportation of flammable liquids by rail. The final rule imposes certain requirements on "offerors" of crude oil, including sampling, testing and certification requirements to improve classification of energy products placed into transport.
Crude Oil Export. The Consolidated Appropriations Act of 2016 (HR 2029) included a provision to end the export ban on domestic crude oil. The Consolidated Appropriations Act of 2016 (HR 2029) passed both houses of Congress and was signed by President Obama in 2015. While QEP does not export crude oil, any restrictions by Congress or the President to limit crude oil exports could reduce domestic prices received by QEP.
State Regulations
The states where QEP operates have promulgated extensive and complex regulations that govern oil and gas development within their respective boundaries. These regulations generally increase the cost of constructing, operating, producing and abandoning wells, and violations may result in civil penalties and affect QEP's ability to operate. The following are examples of these state regulations.
Texas. In 2014, the TRRC adopted new permit rules for injection wells to address seismic activity concerns within the state. Among other things, the rules require companies seeking permits for produced water disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the TRRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. Also in 2014, the TRRC adopted additional well integrity, casing, and cementing requirements for hydraulically fractured wells. In 2016, the TRRC conformed its administrative practices and procedures for horizontally drilled and hydraulically fractured well fields to those applicable to other types of oil and gas well development. Natural gas flaring in Texas has increased over the past years and the TRRC may implement regulations or restrictions on flaring of natural gas which could increase production costs to QEP or restrict production of crude oil.
North Dakota. The North Dakota Industrial Commission (NDI Commission), North Dakota's chief energy regulator, issued an order in 2014 to reduce the volume of natural gas flared from oil wells in the Bakken and Three Forks formations. In connection with that order, the NDI Commission required operators to develop gas capture plans that describe how much natural gas is expected to be produced, how it will be delivered to a processor and where it will be processed. Production caps or penalties may be imposed on certain well operators that cannot meet the capture goals. In addition, pursuant to Commission Order No. 25417, QEP is required to condition crude oil produced in the Bakken Petroleum System to remove lighter, volatile hydrocarbons and reduce the vapor pressure of crude oil prior to rail transport.
ITEM 1A. RISK FACTORS
Described below are certain risks that we believe are applicable to our business and the oil and gas industry in which we operate. Investors should read carefully the following factors as well as the cautionary statements referred to in "Forward-Looking Statements" herein. If any of the risks and uncertainties described below or elsewhere in this Annual Report on Form 10-K actually occur, the Company's business, financial condition or results of operations could be materially adversely affected.
Risk Factor Summary
•The prices for oil, gas and NGL are volatile, and declines in such prices could adversely affect QEP's earnings, cash flows, asset values and stock price.
•The outbreak of COVID-19 and recent oil market developments could adversely impact our financial condition and results of operations.
•Lack of availability of refining, gas processing, storage, gathering or transportation capacity will likely impact results of operations.
•Lower oil, gas and NGL prices or negative adjustments to oil, gas and NGL reserves may result in significant impairment charges.
•Oil and gas reserve estimates are imprecise, may prove to be inaccurate, and are subject to revision. Any significant inaccuracies in QEP's reserve estimates or underlying assumptions may negatively affect the quantities and present value of QEP's reserves.
•QEP may be required to write down its proved undeveloped reserve estimates if it is unable to convert those reserves into proved developed reserves within five years.
•Shortages of qualified personnel and/or oilfield equipment and services as well as QEP's inability to retain or motivate key personnel or transfer knowledge from retiring personnel could negatively impact results of operations.
•Multi-well pad drilling may result in volatility in QEP operating results and delay conversion of PUD reserves.
•Certain of QEP's leaseholds are subject to lease and other agreements that will expire over the next several years unless production in paying quantities is established and maintained on the acreage or on units containing the acreage, certain drilling obligations are satisfied, or the leases are otherwise renewed or extended.
•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.
•Because the exchange ratio is fixed and because the market price of Diamondback common stock will fluctuate, QEP stockholders cannot be certain of the precise value of the Merger Consideration they will receive in the Merger.
•The Merger may not be completed and the Merger Agreement may be terminated in accordance with its terms. Failure to complete the Merger could negatively impact the price of shares of our common stock, as well as our future business and financial results.
•Our stockholders will have a reduced ownership and voting interest in the combined company after the Merger compared to their current ownership in QEP and will exercise less influence over the combined company’s management.
•If the Merger does not qualify as a “reorganization” under Section 368(a) of the Internal Revenue Code of 1986, as amended (Code), our stockholders may be subject to U.S. federal income tax upon the receipt of Diamondback common stock in the Merger.
•We are subject to business uncertainties while the Merger is pending, which could adversely affect our business.
•The Merger Agreement limits our ability to pursue alternatives to the Merger, which may discourage certain other companies from making favorable alternative transaction proposals and, in specified circumstances, could require us to pay Diamondback a termination fee.
•Our directors and executive officers may have interests in the Merger that are different from, or in addition to, the interests of our stockholders.
•We will incur significant transaction and merger-related costs in connection with the Merger, which may be in excess of those anticipated.
•Completion of the Merger may trigger change in control or other provisions in certain agreements to which we or our subsidiaries are a party.
•We may be targets of securities class action and derivative lawsuits that could result in substantial costs and may delay or prevent the Merger from being completed.
•Shares of Diamondback common stock received by our stockholders as a result of the Merger will have different rights from shares of our common stock.
•QEP's certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, even if an acquisition or merger may be in QEP shareholders' best interests.
•Substantially all of our producing properties and operations are located in the Permian and Williston basins, making us vulnerable to risks associated with operating in a limited number of basins.
•QEP may be unable to divest assets on financially attractive terms, resulting in reduced cash proceeds.
•QEP is partially dependent on its revolving credit facility and continued access to capital markets to successfully execute its operating strategies.
•A downgrade in QEP's credit rating could negatively impact QEP's cost of and access to capital.
•QEP's use of derivative instruments to manage exposure to uncertain prices could result in financial losses or reduce its income.
•QEP is involved in legal proceedings that could result in substantial liabilities and materially and adversely impact the Company's financial condition.
•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.
•Regulatory requirements to reduce gas flaring and to further restrict emissions could have an adverse effect on our operations.
•QEP may not be able to obtain the permits and approvals necessary to continue and expand its operations.
•Our operations on the Fort Berthold Indian Reservation of the Three Affiliated Tribes in North Dakota are subject to various federal, state, local and tribal regulations and laws, any of which may increase our costs and have an adverse impact on our ability to effectively conduct our operations.
•Federal and state hydraulic fracturing legislation or regulatory initiatives could increase QEP's costs and restrict its access to oil and gas reserves.
•Legislation or regulatory initiatives intended to address induced seismicity could restrict QEP's drilling and production activities as well as QEP's ability to dispose of produced water gathered from such activities, which could have a material adverse effect on QEP's business.
•Climate change and climate change legislation and regulatory initiatives, including renewable energy mandates could result in increased operating costs and decreased demand for the oil and natural gas that we produce.
•A change in the jurisdictional characterization of some of our assets by federal, state, or local regulatory agencies or a change in policy by those agencies could result in increased regulation of our assets, which could cause our revenues to decline and operating expenses to increase.
•The taxation of independent producers is subject to change, and changes in tax law could increase our cost of doing business.
•If we were to experience an "ownership change," we could be limited in our ability to use certain tax attributes arising prior to the ownership change to offset future taxable income.
Risks Related to the Business
The prices for oil, gas and NGL are volatile, and declines in such prices could adversely affect QEP's earnings, cash flows, asset values and stock price. Historically, oil, gas and NGL prices have been volatile and unpredictable, and that volatility is expected to continue. Volatility in oil, gas and NGL prices is due to a variety of factors that are beyond QEP's control, including:
•changes in local, regional, domestic and foreign supply of and demand for oil, gas and NGL;
•the impact of an abundance of oil, gas and NGL from unconventional sources on the global and local energy supply;
•the level of imports and/or exports of, and the price of, foreign oil, gas and NGL;
•localized supply and demand fundamentals, including the proximity, cost and availability of pipelines and other transportation facilities, and other factors that result in differentials to benchmark prices from time to time;
•the availability of refining and storage capacity;
•domestic and global economic and political conditions;
•changes in government energy policies, including imposed price controls or product subsidies or both;
•periods of civil unrest;
•speculative trading in crude oil and natural gas derivative contracts;
•the continued threat of terrorism and the impact of military and other action;
•the activities of the Organization of Petroleum Exporting Countries (OPEC) and other oil producing countries such as Russia and Saudi Arabia, including the ability of members of OPEC and Russia to maintain oil price and production controls;
•events in the Middle East, Africa, South America and Russia;
•the strength of the U.S. dollar relative to other currencies;
•weather conditions, natural disasters and epidemic or pandemic disasters such as the recent outbreak of COVID-19;
•domestic and international laws, regulations and taxes, including regulations, legislation or executive orders relating to climate change, induced seismicity or oil and gas exploration and production activities, including, but not limited to hydraulic fracturing;
•technological advances affecting energy consumption and energy supply;
•conservation efforts;
•the price, availability and acceptance of alternative energy sources, including coal, nuclear energy, renewables and biofuels;
•demand for electricity and natural gas used as fuel for electricity generation;
•pandemic and health events that could reduce demand of petroleum products;
•pandemic events that could impair our employees' and contractors' abilities to drill and produce oil and gas;
•the level of global oil, gas and NGL inventories and exploration and production activity; and
•the quality of oil and gas produced.
Declines in oil, gas and NGL prices would not only reduce revenue, but could also reduce the amount of oil, gas and NGL that we can economically produce and therefore potentially lower our oil and gas reserve quantities. In addition, a decline in oil and gas prices and volatility could negatively impact our ability to execute our operating and development plans and the ability to generate Free Cash Flow.
The long-term effect of factors impacting the prices of oil, gas and NGL is uncertain. Substantial or prolonged declines in these commodity prices may have the following effects on QEP's business:
•adversely affect QEP's financial condition and liquidity and QEP's ability to finance planned capital expenditures, borrow money, repay debt and raise additional capital;
•reduce the amount of oil, gas and NGL that QEP can produce economically;
•reduce the carrying value of QEP's oil and gas properties due to recognizing additional impairments of proved and unproved properties;
•cause QEP to delay, postpone or cancel some of its capital projects;
•cause QEP to divest properties to generate funds to meet cash flow or liquidity requirements;
•reduce QEP's revenues, operating income or cash flows;
•limit QEP's ability to generate Free Cash Flow;
•reduce the amounts of QEP's estimated proved oil, gas and NGL reserves;
•limit QEP's access to, or increasing the cost of, sources of capital such as equity and long-term debt;
•cause additional counterparty credit risk;
•decrease the value of QEP's common stock; and
•increase shareholder activism.
Alternatively, higher oil prices may result in increased volatility in commodity prices, inflation, slower economic growth, a global recession or more international conflicts. Higher oil prices may also result in higher costs for QEP and significant mark-to-market losses being incurred in QEP's commodity derivatives, which may in turn cause us to experience net losses.
QEP's operations are subject to operational hazards and unforeseen interruptions for which QEP may not be adequately insured and that could adversely affect our business, financial condition and results of operations. There are operational risks associated with the exploration, production, gathering, transporting, and storage of oil, gas and NGL, including:
•pandemic health events, injuries and/or deaths of employees, supplier personnel, or other individuals;
•fires, explosions and blowouts;
•earthquakes and other natural disasters;
•aging infrastructure and mechanical problems;
•unexpected drilling conditions, including abnormally pressured formations or loss of drilling fluid circulation;
•pipe, cement or casing failures;
•equipment malfunctions, mechanical failures or accidents;
•theft or vandalism of oilfield equipment and supplies, especially in areas of increased activity;
•adverse weather conditions;
•plant, pipeline, railway and other facility accidents and failures;
•truck and rail loading and unloading problems;
•delays imposed by or resulting from compliance with regulatory requirements;
•delays in or limits on the issuance of drilling permits on our federal leases, including as a result of government shutdowns;
•delays imposed by or resulting from legal proceedings;
•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;
•security breaches, cyberattacks, piracy, or terrorist acts;
•flaring of natural gas, including, where required, accurate and timely payment of royalty on flared gas;
•pipeline takeaway and refining and processing capacity issues; and
•title problems.
QEP could incur substantial losses as a result of pandemic health events, injury to or loss of life, pollution or other environmental damage, damage to or destruction of property or equipment, regulatory compliance investigations, fines or curtailment of operations, or attorneys' 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.
Consistent with industry practice, QEP generally indemnifies drilling contractors and oilfield service companies (collectively, contractors) against certain losses suffered by QEP as the operator and certain 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 in addition to claims for personal injury or death suffered by QEP's employees and certain others. QEP's drilling contracts and oilfield service agreements, however, often provide that the contractor will indemnify QEP for claims related to injury and death of employees of the contractor and its subcontractors and for property damage suffered by the contractor and its subcontractors.
QEP's insurance coverage may not be sufficient to cover 100% of potential losses arising as a result of the foregoing risks. QEP has limited or no coverage for certain other risks, such as political risk, lost reserves, business interruption, cyber risk, earthquakes, war and terrorism. 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. QEP could sustain significant losses and substantial liability for uninsured risks. The occurrence of a significant event against which QEP is not fully insured could have a material adverse effect on its financial condition, results of operations and cash flows.
The outbreak of COVID-19 and recent oil market developments could adversely impact our financial condition and results of operations. On January 30, 2020, the WHO announced a global health emergency because of a new strain of coronavirus known as COVID-19 due to the risks it imposes on the international community as the virus spreads globally. In March 2020, the WHO classified the COVID-19 outbreak as a pandemic, based on the rapid increase in exposure globally. COVID-19 has had and continues to have adverse repercussions across regional and global economies and financial markets which necessarily adversely affects the jurisdictions in which we operate and in turn, our business. The governments of many countries, including the United States, have reacted by instituting lockdowns, business shutdowns, quarantines and restrictions on travel. Businesses have also implemented countermeasures and safety measures to reduce the risk of transmission. Such actions have not only disrupted businesses but have had a material and adverse effect on industries and local, regional and global economies.
The crude oil market experienced a dramatic decline in oil prices in response to concerns about oil demand due to the global economic impacts of COVID-19. In addition, policy disputes in the first quarter 2020 between OPEC and Russia resulted in Saudi Arabia significantly discounting the price of its crude oil, as well as Saudi Arabia and Russia significantly increasing their oil supply. These actions led to significant weakness in oil prices and caused us to reduce our capital and operating budgets as well as slow our development plan. In addition, the potential spread of the virus into our workforce and the workforces of our counterparties could continue to have an adverse impact on our operations.
The total magnitude and duration of potential social, economic and labor instability as a direct result of COVID-19 cannot be estimated at this time. Should any of these potential impacts continue for an extended period of time, it will have a negative impact on the demand for our oil and natural gas products and have an adverse effect on our financial position and results of operations. The COVID-19 pandemic had an adverse effect on our business results in 2020. To the extent the COVID-19 pandemic adversely affects our business and financial results, it may also have the effect of heightening many of the other risks described in this “Risk Factors” section, such as those relating to our indebtedness, our need to generate sufficient cash flows to service our indebtedness and our ability to comply with the covenants contained in the agreements that govern our indebtedness.
Due to safety concerns related to the COVID-19 pandemic, many of our employees are working remotely for an indefinite time period, which may result in increased exposure to cyber and other operational risks.
Lack of availability of refining, gas processing, storage, gathering or transportation capacity will likely impact results of operations. The lack of availability of satisfactory oil, gas and NGL gathering and transportation, including trucks, railways and pipelines, gas processing, storage or refining capacity may hinder QEP's access to oil, gas and NGL markets or delay production from its wells. QEP's ability to market its production depends in substantial part on the availability, proximity and capacity of gathering, transportation, gas processing facilities, storage or refineries owned and operated by third parties. Although QEP has some contractual control over the transportation of its production through firm transportation and gas processing arrangements, third-party systems may be temporarily unavailable due to market conditions, mechanical failures, accidents, lack of contracted capacity on such systems or other reasons such as temporary suspension of service due to legal challenges (such as the pending litigation regarding the Dakota Access Pipeline, a major pipeline running out of the Williston Basin) and/or the pipeline’s failure to comply with applicable laws and regulations. If gathering, transportation, gas processing or storage facilities do not exist near producing wells; if gathering, transportation, gas processing, storage or refining capacity is limited; or if gathering, transportation, gas processing or refining capacity is unexpectedly disrupted, completion activity could be delayed, sales could be reduced, gas flaring and transportation costs could increase, or production could be shut-in, each of which could reduce profitability. The curtailments arising from these circumstances may last from a few days to several months, and in many cases, QEP is provided with limited, if any, notice as to when these circumstances will arise and their duration. Furthermore, if QEP were required to shut-in wells, it might also be obligated to pay certain demand charges for gathering and processing services, as well as 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. In addition, rail accidents involving crude oil carriers have resulted in regulations, and may result in additional regulations, on transportation of oil by railway. QEP might be required to install or contract for additional treating or processing equipment for transport of crude oil by rail, 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.
Lower oil, gas and NGL prices or negative adjustments to oil, gas and NGL reserves may result in significant impairment charges. Lower commodity prices may not only decrease QEP's revenues, operating income and cash flows but also may reduce the amount of oil, gas and NGL that QEP can produce economically. GAAP requires QEP to write down, as a non-cash charge to earnings, the carrying value of its oil and gas properties in the event QEP has impairments. QEP performs impairment tests on its assets whenever events or changes in circumstances warrant a review of its assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of its assets, the carrying value may not be recoverable, and, therefore, a write-down may be required. During the year ended December 31, 2020, the Company recorded unproved property impairment charges of $8.7 million related to anticipated leasehold expirations. During the year ended December 31, 2019, there were no impairments on its oil and gas related properties. During the year ended December 31, 2018, QEP recorded impairment charges of $1,524.6 million on its proved properties and $36.3 million on its unproved properties. Refer to Part I, Item 8, Note 1 – Summary of Significant Accounting Policies, of this Annual Report on Form 10-K for more information.
If forward oil prices decline from December 31, 2020 levels or we experience negative changes to the estimated reserve quantities, we have proved and unproved properties at risk for impairment. The actual amount of impairment incurred, if any, for these properties will depend on a variety of factors including, but not limited to, subsequent forward price curve changes, the additional risk-adjusted value of probable and possible reserves associated with the properties, weighted-average cost of capital, operating cost estimates and future capital expenditure estimates.
The Company may not be able to economically find and develop new reserves. The Company's liquidity and profitability depends not only on prevailing prices for oil, gas and NGL, but also on its ability to find, develop and acquire oil and gas reserves that are economically recoverable. Producing oil and gas reservoirs are generally characterized by declining production rates that vary depending on reservoir characteristics. Because oil and gas production volumes from unconventional wells typically experience relatively steep declines in the first year of operation and continue to decline over the economic life of the well, QEP must continue to invest significant capital to find, develop and acquire oil and gas reserves to replace those depleted by production. Failure to find or acquire additional reserves would cause reserves and production to decline materially from their current levels.
Oil and gas reserve estimates are imprecise, may prove to be inaccurate, and are subject to revision. Any significant inaccuracies in QEP's reserve estimates or underlying assumptions may negatively affect the quantities and present value of QEP's reserves. QEP's proved oil and gas reserve estimates are prepared annually by independent reservoir engineering consultants. Oil and gas reserve estimates are subject to numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and timing of development expenditures. The accuracy of these estimates depends on the quality of available data and on engineering, geological and geophysical interpretation and judgment. Reserve estimates are imprecise and will change as more information becomes available. Estimates of economically recoverable reserves and future net cash flows prepared by different engineers or by the same engineers at different times may vary significantly. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. In addition, the estimation process involves economic assumptions relating to commodity prices, operating costs, severance and other taxes, capital expenditures and remediation costs. Actual results most likely will vary from the estimates. Any significant variance from these assumptions could affect the recoverable quantities of reserves attributable to any particular property, the classifications of reserves, the estimated future net cash flows from proved reserves and the present value of those reserves.
Investors should not assume that QEP's presentation of the Standardized Measure of Discounted Future Net Cash Flows relating to Proved Reserves in this Annual Report on Form 10-K is reflective of the current market value of the estimated oil and gas reserves. In accordance with SEC disclosure rules, the estimated discounted future net cash flows from QEP's proved reserves are based on the first-of-the-month prior 12-month average prices and current costs on the date of the estimate, holding the prices and costs constant throughout the life of the properties and using a discount factor of 10% per year. QEP's cost estimates do not include any future costs related to proposed climate change regulations. Actual future production, prices and costs may differ materially from those used in the current estimate, and future determinations of the Standardized Measure of Discounted Future Net Cash Flows using similarly determined prices and costs may be significantly different from the current estimate. Therefore, reserve quantities may change when actual prices increase or decrease. In addition, the 10% discount factor QEP uses when calculating discounted future net cash flows in accordance with SEC disclosure rules, may not be the most appropriate discount factor that is based on interest rates in effect from time to time and risks associated with the Company or the oil and gas industry in general.
In addition, realization or recognition of proved undeveloped reserves will depend on QEP's development schedule and plans. A change in future development plans for proved undeveloped reserves could cause the discontinuation of the classification of those reserves as proved. See Items 1 and 2. Business and Properties – Proved Reserves in this Annual Report on Form 10-K.
QEP may be required to write down its proved undeveloped reserve estimates if it is unable to convert those reserves into proved developed reserves within five years. SEC rules require that, subject to limited exceptions, proved undeveloped (PUD) reserves may only be classified as proved reserves if they are from locations scheduled to be drilled within five years after the date of booking. Recovery of PUD reserves requires the expenditure of significant capital and successful drilling operations. QEP may be required to write down its PUD reserves if it is not successful in drilling PUD wells within the required five-year time frame. During 2020 and 2019, QEP removed 16.9 MMboe and 25.8 MMboe, respectively, of PUD reserves that were no longer in the 2020 and 2019 forecasted capital expenditure plans, respectively, and would not be drilled and completed within five years of the initial date of booking of the reserves. The majority of the 2020 PUD write-downs were due to the Company's decision to reduce completion activity and suspend the refracturing program in the Williston Basin in 2020 in light of the market conditions and continued focus on Free Cash Flow generation. There is no assurance that we may not change our development plan again in the future, resulting in further write-downs. At December 31, 2020, approximately 55% of QEP's estimated proved reserves were PUD reserves. These reserve estimates reflect the Company's plans to make significant capital expenditures to convert its PUDs into proved developed reserves, requiring an estimated $1.6 billion during the five years ending December 31, 2025. The estimated development costs may not be accurate; timing to incur such costs may change; development may not occur as scheduled; and results may not be as estimated.
Our use of seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations. Even when properly used and interpreted, seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether producible hydrocarbons are, in fact, present in those structures in economic quantities. In addition, the use of 3-D seismic and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.
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, acquisition and production. QEP faces competition from:
•large multi-national, integrated oil companies;
•U.S. independent oil and gas companies;
•service companies engaging in oil and gas exploration and production activities; and
•private investing in oil and gas assets.
QEP faces competition in a number of areas such as:
•acquiring desirable producing properties or new leases for future exploration;
•acquiring or increasing access to gathering, processing and transportation services and capacity;
•marketing its oil, gas and NGL production;
•obtaining the equipment and expertise necessary to operate and develop properties; and
•attracting and retaining employees with certain critical skills.
Certain of QEP's competitors have financial and other resources in excess of those available to QEP. Such companies may be able to pay more for 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 ability to execute its strategy, QEP's financial condition and its results of operations.
Shortages of qualified personnel and/or oilfield equipment and services as well as QEP's inability to retain or motivate key personnel or transfer knowledge from retiring personnel could negatively impact results of operations. QEP's performance largely depends on the talents and efforts of highly skilled individuals. The oil and gas industry has long suffered a skills shortage, recognized by many to be a threat to future growth. This skills shortage has been exacerbated by depressed oil and gas prices over the past several years and the resulting loss of skilled workers through layoffs in the oil and gas industry during these years. The demand for and availability of qualified and experienced personnel to drill wells and conduct field operations, in addition to geologists, geophysicists, engineers, landmen and other professionals in the oil and gas industry, will create challenges for QEP and its competitors and may cause periodic and problematic personnel shortages. In periods of high commodity prices, there have also been regional shortages of drilling rigs and other equipment. Any cost increases could impact profit margin, cash flow and operating results or restrict QEP's ability to drill wells and conduct operations.
In connection with the successful completion of the Uinta Basin and Haynesville divestitures, as well as its initiative to significantly reduce its general and administrative expense to ensure that it is competitive with industry peers, QEP experienced a reduction in headcount in 2018 and 2019. Additionally, in 2019, QEP's President and Chief Executive Officer, its Executive Vice President of Operations, and its Executive Vice President and Chief Financial Officer, each of whom had long tenure with the Company, departed the Company.
Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application. Our operations involve utilizing some of the latest drilling and completion techniques. Risks that we face while drilling horizontal wells include, but are not limited to, the following:
•spacing of wells to maximize production rates and recoverable reserves;
•landing the wellbore in the desired drilling zone;
•staying in the desired drilling zone while drilling horizontally through the formation;
•running casing the entire length of the wellbore; and
•being able to run tools and other equipment consistently through the horizontal wellbore.
Risks that we face while completing our wells include, but are not limited to, our inability to:
•fracture stimulate the planned number of stages;
•run tools the entire length of the wellbore during completion operations;
•successfully clean out the wellbore after completion of the final fracture stimulation stage;
•prevent unintentional communication with other wells; and
•design and maintain efficient artificial lift throughout the life of the well.
QEP began testing the restimulation, or refracturing, of wells in the Williston Basin during 2017. Refracturing an existing well is technically more challenging than fracturing a new well and may result in the loss of the existing producing well.
If our drilling and completion activities do not meet our anticipated results or we are unable to execute our drilling and completion program because of capital constraints, lease expirations, limited access to gathering systems, limited takeaway capacity and/or declines in crude oil and natural gas prices or unconventional wells are not achieving production expectations, the return on our investment for certain projects may not be as attractive as we anticipate. Further, as a result of any of these developments, we could incur material write-downs of our oil and gas properties and the value of our undeveloped acreage could decline in the future.
Multi-well pad drilling may result in volatility in QEP operating results and delay conversion of PUD reserves. QEP utilizes multi-well pad drilling where practical. For example, in the Permian Basin, QEP utilizes "tank-style" development, in which we drill and complete all wells in a given "tank" before any individual well is turned to production. In the Williston Basin, QEP drills multiple wells from a single pad. Wells drilled on a pad are not brought into production until all wells on the pad are drilled and cased and the drilling rig is moved from the location. In addition, existing wells that offset newly drilled wells may be temporarily shut-in during the drilling and completion process. As a result, multi-well pad drilling delays the completion of wells, the commencement of production from new wells, and may negatively affect the production from existing offset wells, all of which may cause volatility in QEP's operating results from period to period. This may lead to additional volatility in QEP's operating results. Finally, delays in completion of wells may impact planned conversion of PUD reserves to proved developed.
Certain of QEP's leaseholds are subject to lease and other agreements that will expire over the next several years unless production in paying quantities is established and maintained on the acreage or on units containing the acreage, certain drilling obligations are satisfied, or the leases are otherwise renewed or extended. Leases on oil and gas properties typically have a primary 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 or the lease is renewed or extended. Other agreements relating to leasehold may obligate QEP to meet certain drilling obligations to maintain leases in effect. If a lease expires or is not renewed before expiration, or if QEP does not meet contractual drilling obligations, QEP will lose its right to develop the related reserves. While QEP seeks to actively manage its leasehold inventory by drilling sufficient wells and otherwise meeting drilling obligations necessary 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. Under the terms of certain of our leases and the laws in the states in which we operate, production from our wells must be maintained in paying quantities. If we fail to maintain certain levels of production or otherwise fail to comply with the terms of our leases (e.g. paying royalties in a timely and correct manner), it is possible for us to lose our leases.
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 has identified and scheduled well locations to build its multi-year development plan for its existing leaseholds. These well locations represent a significant part of QEP's future development strategy. QEP's ability to drill and develop these locations is impacted by a number of uncertainties, including the ongoing review and analysis of geologic and engineering data, oil and gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, potential interference between infill and existing wells, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water and water disposal and recycling facilities, regulatory approvals and other factors. Because of these factors, QEP does not know if the potential well locations it 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.
Renegotiation of gathering, processing and transportation agreements may result in higher costs and/or delays in selling production. Substantially all of QEP’s production depends on the availability of gathering, transportation, gas processing, or storage facilities owned and operated by midstream service providers under agreements which expire periodically. If QEP agrees to renew or extend its midstream agreements, the costs QEP pays for midstream services may increase. If QEP and any of its midstream service providers cannot agree on revised terms to these agreements, the midstream service providers may assert that continued performance of their obligations under these contracts is uneconomic and attempt to terminate or alter the agreements, which could hinder QEP's access to oil, gas and NGL markets, increase costs and/or delay completion of or production from its wells. Disputes over termination or changes to such agreements could result in arbitration or litigation, causing uncertainty about the status of the agreements and further delays.
QEP has limited control over the activities on properties it does not operate, which could adversely affect our production, revenues and returns on capital. As of December 31, 2020, QEP operates 97% of its net productive oil and natural gas wells. Other companies operate some of the properties in which QEP has an interest. QEP has limited ability to influence or control the operation or future development of these non-operated properties, including compliance with environmental, safety and other regulations, or the amount or timing of capital expenditures that QEP is required to fund with respect to them. The failure of an operator of QEP's wells to adequately perform operations, an operator's breach of the applicable agreements with QEP or an operator's failure to act in ways that are in QEP's best interest could reduce QEP's production and revenues. QEP's dependence on the operator and other working interest owners to complete these projects and QEP's limited ability to influence or control the operation and future development of these properties could adversely affect the realization of QEP's targeted returns on capital in drilling or acquisition activities, lead to unexpected future costs, or adversely affect the timing of activities. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator's decisions with respect to the timing and amount of capital expenditures, the period of time over which the operator seeks to generate a return on capital expenditures, inclusion of other participants in drilling wells, and the use of technology, as well as the operator's expertise and financial resources and the operator's relative interest in the field. Operators may also opt to decrease operational activities following a significant decline in, or a sustained period of low, oil or natural gas prices. Because we do not have a majority interest in most wells we do not operate, we may not be in a position to remove the operator in the event of poor performance. Accordingly, while we use reasonable efforts to cause the operator to act in a prudent manner, we are limited in our ability to do so.
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 United States. Companies in the oil and gas industry, such as QEP, are often the target of activist efforts from both individuals and environmental nongovernmental organizations (ENGOs) 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, ENGOs and other environmental activists continue to advocate for increased regulation of 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:
•delay or denial of drilling and other necessary permits;
•shortening of lease terms or reduction in lease size;
•bans on hydraulic fracturing;
•bans on crude oil and natural gas exports;
•restrictions on installation or operation of gathering, processing or pipeline facilities;
•restrictions on flaring of natural gas;
•more stringent setback requirements from houses, schools, businesses and other improvements and landscape features;
•towns, cities, states and counties imposing bans on certain activities, including hydraulic fracturing;
•restrictions on the use of certain operating practices, such as hydraulic fracturing, or the disposition of related waste materials, such as hydraulic fracturing fluids and produced water;
•reduced access to water supplies or restrictions on produced water disposal;
•increased severance and/or other taxes;
•cyberattacks;
•legal challenges or lawsuits;
•negative publicity about QEP;
•disinvestment and other targeted activist shareholder campaigns;
•increased costs of doing business;
•reduction in demand for QEP's production;
•other adverse effects on QEP's ability to develop its properties and increase production;
•increased regulation of rail transportation of crude oil;
•opposition to the construction of new oil and gas pipelines;
•postponement of state and federal oil and gas lease sales; and
•delays in or challenges to issuance of federal and tribal oil and gas leases.
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, which could have a material adverse effect on its business, financial condition and results of operations.
We may incur losses as a result of title defects in the properties in which we invest. The existence of a material title deficiency can render a lease worthless. In the course of acquiring the rights to develop oil or natural gas, it is standard procedure for us and the lessor to execute a lease agreement with payment, subject to title verification. There is no certainty, however, that a lessor has valid title to their lease's oil and gas interests. In those cases, such leases are generally voided, and payment is not remitted to the lessor. As such, title failures may result in fewer net acres to us. Prior to the drilling of an oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Accordingly, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.
Failure to fund continued capital expenditures could adversely affect QEP's properties. QEP's exploration, development and acquisition activities require capital expenditures to achieve production and cash flows. Historically, QEP has funded its capital expenditures through a combination of cash flows from operations, its revolving credit facility, debt issuances, equity offerings and sales of assets. Future cash flows from operations are subject to a number of variables, such as the level of production from existing wells, prices of oil, gas and NGL, and QEP's success in finding, developing and producing new reserves. Our failure to fund capital expenditures may delay or prevent the development of our properties, which may adversely impact our ability to retain leaseholds that are held by production, increase lease expirations, and decrease production and reserves from our properties.
Our business could be negatively affected as a result of actions of activist shareholders, and such activism could impact the strategic direction of QEP and the trading value of our securities. Shareholders may from time to time attempt to effect changes, engage in proxy solicitations or advance shareholder proposals. Activist shareholders may make strategic proposals, suggestions or requested changes concerning our operations, strategy, management, assets or other matters. For example, in response to a January 2019 proposal from Elliott Management Corporation to acquire all shares of our common stock, our Board of Directors engaged in a comprehensive review of strategic alternatives and concluded that the best alternative for QEP’s shareholders was to move forward as an independent company. Responding to additional actions by activist shareholders could be costly and time-consuming, disrupting our operations and diverting the attention of our management and employees. Such activities could interfere with our ability to execute our strategic plan or realize long-term value from our assets.
Risks Related to the Merger
Because the exchange ratio is fixed and because the market price of Diamondback common stock will fluctuate, QEP stockholders cannot be certain of the precise value of the Merger consideration they will receive in the Merger. If the Merger is completed, at the effective time of the Merger, each issued and outstanding eligible share of QEP common stock will be converted into the right to receive the Merger Consideration. The exchange ratio for the Merger Consideration is fixed at 0.050 of a share of Diamondback common stock for each share of QEP common stock and there will be no adjustment to the Merger Consideration for changes in the market price of Diamondback common stock or QEP common stock prior to the completion of the Merger.
If the Merger is completed, there will be a time lapse between the date of signing the Merger Agreement, the date on which our stockholders vote to approve the Merger and the date on which our stockholders entitled to receive the Merger Consideration actually receive the Merger Consideration. The market value of shares of Diamondback common stock will fluctuate, possibly materially, during and after these periods as a result of a variety of factors, including general market and economic conditions, changes in Diamondback’s businesses, operations and prospects and regulatory considerations and any impact of the ongoing COVID-19 pandemic. Such factors are difficult to predict and in many cases may be beyond the control of Diamondback and us. The actual value of any Merger Consideration received by our stockholders at the completion of the Merger will depend on the market value of the shares of Diamondback common stock at that time. Consequently, at the time our stockholders decide whether to approve the Merger proposal, they will not know the actual market value of any Merger Consideration they will receive when the Merger is completed.
The Merger may not be completed and the Merger Agreement may be terminated in accordance with its terms. Failure to complete the Merger could negatively impact the price of shares of our common stock, as well as our future business and financial results. The Merger is subject to a number of conditions that must be satisfied, including the approval by our stockholders of the Merger Agreement, or, to the extent permitted by applicable law, waived, in each case prior to the completion of the Merger. These conditions to the completion of the Merger, some of which are beyond our control and the control of Diamondback, may not be satisfied or waived in a timely manner or at all, and, accordingly, the Merger may be delayed or may not be completed.
In addition, if the Merger is not completed by June 30, 2021, or, in certain instances, on or before September 30, 2021, either we or Diamondback may choose not to proceed with the Merger by terminating the Merger Agreement, and the parties can mutually decide to terminate the Merger Agreement at any time, before or after stockholder approval. Further, either we or Diamondback may elect to terminate the Merger agreement in certain other circumstances.
If the transactions contemplated by the Merger Agreement are not completed for any reason, our ongoing business, financial condition and financial results may be adversely affected. Without realizing any of the benefits of having completed the Merger, we will be subject to a number of risks, including the following:
• we will be required to pay our costs relating to the Merger, which are substantial, such as legal, accounting, financial advisory and printing fees, whether or not the Merger is completed;
• we may owe a termination fee of $17 million to Diamondback, as further described below;
• time and resources committed by our management to matters relating to the Merger could otherwise have been devoted to pursuing other beneficial opportunities;
•we may experience negative reactions from financial markets, including negative impacts on the price of our common stock, including to the extent that the current market price reflects a market assumption that the Merger will be completed;
•we may experience negative reactions from employees, customers or vendors; and
•since the Merger Agreement restricts the conduct of our business prior to completion of the Merger, we may not have been able to take certain actions during the pendency of the Merger that would have benefitted us as an independent company and the opportunity to take such actions may no longer be available.
If the Merger Agreement is terminated and our board seeks another Merger or business combination, we may not be able to find a party willing to offer equivalent or more attractive consideration than the consideration Diamondback has agreed to provide in the Merger. If the Merger Agreement is terminated under specified circumstances, we may be required to pay Diamondback a termination fee of $17 million. If the Merger Agreement is terminated because of a failure of our stockholders to approve the proposals required to complete the Merger, we may be required to reimburse Diamondback for any reasonable, documented, out-of-pocket expenses paid or incurred by Diamondback in connection with the Merger, in an amount not to exceed $7.5 million.
Our stockholders will have a reduced ownership and voting interest in the combined company after the Merger compared to their current ownership in QEP and will exercise less influence over the combined company’s management. Currently, our stockholders have the right to vote in the election of our board and the power to approve or reject any matters requiring stockholder approval under Delaware law and our organizational documents. Upon completion of the Merger, each of our stockholders who receives shares of Diamondback common stock in the Merger will become a stockholder of Diamondback with a percentage ownership of Diamondback that is smaller than such stockholder’s current percentage ownership of QEP. Even if all former QEP stockholders voted together on all matters presented to Diamondback stockholders from time to time, the former QEP stockholders would exercise significantly less influence over on the management and policies of Diamondback post-Merger than they now have on the management and policies of QEP.
If the Merger does not qualify as a “reorganization” under Section 368(a) of the Internal Revenue Code of 1986, as amended (Code), our stockholders may be subject to U.S. federal income tax upon the receipt of Diamondback common stock in the Merger. We and Diamondback intend for the Merger to be treated as a “reorganization” within the meaning of Section 368(a) of the Code for U.S. federal income tax purposes. However, it is not a condition to our obligation or Diamondback’s obligation to complete the Merger that the Merger qualifies as a “reorganization.” Moreover, neither we nor Diamondback intend to request any ruling from the Internal Revenue Service (the “IRS”) regarding any matters relating to the Merger, and, consequently, there can be no assurance that the IRS will not assert, or that a court would not sustain, a position to the contrary to our and Diamondback’s intended tax treatment. If the IRS were to challenge the “reorganization” status of the Merger successfully or the form or structure of the Merger was changed in a manner such that it did not qualify as a “reorganization,” the tax consequences would differ from those currently intended, and holders of QEP common stock could be subject to U.S. federal income tax upon the receipt of Diamondback common stock in the merger.
We are subject to business uncertainties while the Merger is pending, which could adversely affect our business. Uncertainty about the effect of the Merger on employees, industry contacts and business partners may have an adverse effect on our business. These uncertainties may impair our ability to attract, retain and motivate key personnel until the Merger is completed and for a period of time thereafter and could cause industry contacts, business partners and others that deal with us to seek to change their existing business relationships with us. Employee retention may be particularly challenging during the pendency of the Merger, as employees may experience uncertainty about their roles with Diamondback following the Merger. In addition, the Merger Agreement restricts us from entering into certain corporate transactions and taking other specified actions without the consent of Diamondback. These restrictions may prevent us from pursuing attractive business opportunities that may arise prior to the completion of the Merger.
The Merger Agreement limits our ability to pursue alternatives to the Merger, which may discourage certain other companies from making favorable alternative transaction proposals and, in specified circumstances, could require us to pay Diamondback a termination fee. The Merger Agreement contains provisions that may discourage a third party from submitting a competing proposal to us that might result in greater value to our stockholders than the Merger or, in the event that a third party competing proposal is made, a third party may propose to pay a lower per share price to acquire us than it might otherwise have proposed to pay. These provisions include generally prohibit us from soliciting or, subject to certain exceptions relating to the exercise of fiduciary duties by our board, entering into discussions with any third party regarding any competing proposal. Further, even if our board withholds, withdraws, qualifies or modifies its recommendation with respect to the Merger, unless the Merger Agreement has been terminated in accordance with its terms, we will still have an obligation to submit the Merger proposal to a vote of our stockholders. The Merger Agreement further provides that under specified circumstances, including after a change of recommendation by our board and a subsequent termination of the Merger agreement by Diamondback in accordance with its terms, we may be required to pay Diamondback a cash termination fee in the amount of $17 million.
Our directors and executive officers may have interests in the Merger that are different from, or in addition to, the interests of our stockholders. Our directors and executive officers may have interests in the Merger that are different from, or in addition to, the interests of our stockholders generally. These interests include, among others, the treatment of outstanding equity and equity-based awards pursuant to the Merger Agreement, potential severance and other benefits upon a qualifying termination in connection with the Merger, and rights to ongoing indemnification and insurance coverage.
We will incur significant transaction and merger-related costs in connection with the Merger, which may be in excess of those anticipated. We have incurred and expect to continue to incur a number of non-recurring costs associated with negotiating and completing the Merger, combining the operations of the two companies and achieving desired synergies. These fees and costs have been, and will continue to be, substantial. The substantial majority of non-recurring expenses will consist of transaction costs related to the Merger and include, among others, employee retention costs, fees paid to financial, legal and accounting advisors, severance and benefit costs, and filing fees.
We will also incur transaction fees and costs related to the integration of the companies, which may be substantial. Moreover, we may incur additional unanticipated expenses in connection with the Merger and the integration, including costs associated with any stockholder litigation related to the Merger. Although we expect that the elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses, should allow Diamondback and QEP to offset integration-related costs over time, this net benefit may not be achieved in the near term, or at all.
Completion of the Merger may trigger change in control or other provisions in certain agreements to which we or our subsidiaries are a party. The completion of the Merger may trigger change in control or other provisions in certain agreements to which we or our subsidiaries are a party. If we are unable to negotiate waivers of those provisions, the counterparties may exercise their rights and remedies under such agreements, potentially terminating the agreement or seeking monetary damages. Additionally, even if we are able to negotiate waivers, the counterparties may require a fee for such waivers or seek to renegotiate the agreements on terms less favorable to the combined company.
We may be targets of securities class action and derivative lawsuits that could result in substantial costs and may delay or prevent the Merger from being completed. Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into Merger Agreements. Even if the lawsuits are without merit, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on our liquidity and financial condition. Any such lawsuit could also seek, among other things, injunctive relief or other equitable relief, including a request to rescind parts of the Merger Agreement already implemented or to otherwise enjoin us and Diamondback from consummating the Merger. If a plaintiff is successful in obtaining an injunction prohibiting completion of the Merger, then that injunction may delay or prevent the Merger from being completed, which may adversely affect our business, financial position and results of operation.
One of the conditions to the closing of the Merger is that no injunction by any court or other tribunal of competent jurisdiction has been entered and continues to be in effect and no law has been adopted or is effective, in either case, that prohibits or makes illegal the consummation of the Merger. Consequently, if a lawsuit is filed and a plaintiff is successful in obtaining an injunction prohibiting consummation of the Merger, then that injunction may delay or prevent the Merger from being completed within the expected timeframe or at all, which may adversely affect our business, financial position, and results of operations.
Shares of Diamondback common stock received by our stockholders as a result of the Merger will have different rights from shares of our common stock. Upon completion of the Merger, our stockholders will no longer be stockholders of QEP, and our stockholders who receive the Merger consideration will become Diamondback stockholders, and their rights as Diamondback stockholders will be governed by the terms of Diamondback’s charter and bylaws. There will be important differences between the current rights of our stockholders and the rights to which such stockholders will be entitled as Diamondback stockholders.
Risks Related to the Company
QEP's certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, even if an acquisition or merger may be in QEP shareholders' best interests. QEP's certificate of incorporation authorizes its Board of Directors to issue preferred stock without shareholder approval. If QEP's Board of Directors elects to issue preferred stock, it could be more difficult for a third party to acquire QEP. In addition, some provisions of QEP's certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of QEP, even if the transaction would be beneficial to QEP shareholders, including:
•authorization for the issuance of "blank check" preferred stock that our board of directors could issue to increase the number of outstanding shares to discourage a takeover attempt;
•advance notice requirements for shareholder proposals and nominations for elections to the Board of Directors to be acted upon at meetings of shareholders;
•the inability of QEP shareholders who own less than 25% or more of outstanding shares of QEP’s common stock to call special meetings; and
•the inability of QEP shareholders to act by written consent.
In addition, Delaware law imposes restrictions on mergers and other business combinations between QEP and any holder of 15% or more of QEP's outstanding common stock.
Any provision of our certificate of incorporation or bylaws or Delaware law that has the effect of delaying or deterring a change in control could limit the opportunity for our stockholders to receive a premium for their shares of our common stock and could also affect the price that some investors are willing to pay for our common stock.
If we cannot meet the continued listing requirements of the NYSE, the NYSE may delist our common stock. The New York Stock Exchange (NYSE) has several listing requirements set forth in the NYSE Listed Company Manual. For example, Section 802.01C of the NYSE Listed Company Manual requires that a company’s common stock trade at a minimum average closing price of $1.00 per share over a consecutive 30-trading day period. Pursuant to the rules of the NYSE, companies who fail to maintain this listing requirement have a six month period in which to regain compliance or be delisted. In addition, our common stock could also be delisted if (i) our average market capitalization over a consecutive 30 trading-day period is less than $15 million, or (ii) our common stock trades at an “abnormally low” price, which the NYSE has historically viewed to be $0.16 per share. If either event were to occur, we would not have an opportunity to cure the deficiency, and, as a result, our common stock would be suspended from trading on the NYSE immediately, and the NYSE would begin the process to delist our common stock, subject to our right to appeal under NYSE rules. There is no assurance that any appeal we undertake in these or other circumstances would be successful, nor is there any assurance that we will continue to comply with the other NYSE continued listing standards.
Failure to maintain our NYSE listing could negatively impact us and our stockholders by reducing the willingness of investors to hold our common stock because of the resulting decreased price, liquidity and trading of our common stock, limited availability of price quotations, and reduced news and analyst coverage. These developments may also require brokers trading in our common stock to adhere to more stringent rules and may limit our ability to raise capital by issuing additional shares in the future. Delisting may adversely impact the perception of our financial condition and cause reputational harm with investors and parties conducting business with us. In addition, the perceived decreased value of employee equity incentive awards may reduce their effectiveness in encouraging performance and retention.
There may be future dilution of QEP's common stock, which could adversely affect the market price of QEP's common stock. QEP is not restricted from issuing additional shares of its common stock. In the future, QEP may issue shares of its common stock to raise cash for future capital expenditures, acquisitions or for general corporate purposes. QEP may also acquire interests in other companies by using a combination of cash and its common stock or just its common stock. QEP may also issue securities convertible into, exchangeable for or that represent the right to receive its common stock. Lastly, QEP currently issues restricted share awards, restricted share units and performance share units to its employees and directors as part of their compensation. Any of these events will dilute QEP shareholders' ownership interest in QEP and may reduce QEP's earnings per share and have an adverse effect on the price of QEP's common stock. In addition, sales of a substantial amount of QEP's common stock in the public market, or the perception that these sales may occur, could reduce the market price of QEP's common stock.
Substantially all of our producing properties and operations are located in the Permian and Williston basins, making us vulnerable to risks associated with operating in a limited number of basins. As a result of our lack of diversification in asset type and our limited geographic diversification, any delays or interruptions of production caused by such factors as governmental regulation; density and proration requirements of state regulators; transportation capacity constraints; curtailment of production or interruption of transportation; price fluctuations; natural disasters; or shutdowns of the pipelines connecting our production to refineries would have a significantly greater impact on our results of operations than if we possessed more diverse assets and locations. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian and Williston basins, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.
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 operations. 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:
•incorrect estimates or assumptions about reserves, exploration potential or potential drilling locations;
•incorrect assumptions regarding future revenues, including future commodity prices and differentials, or regarding
future development and operating costs;
•difficulty integrating the operations, systems, management and other personnel and technology of the acquired business or assets with QEP's own;
•the assumption of unidentified or unforeseeable liabilities, resulting in a loss of value;
•the inability to hire, train or retain qualified personnel to manage and operate QEP's growing business and assets; or
•a decrease in QEP's liquidity to the extent it uses a significant portion of its available cash or borrowing capacity to finance acquisitions or operations of the acquired properties.
Organizational modifications due to acquisitions, divestitures or other strategic changes can alter the risk and control environments; disrupt ongoing business; distract management and employees; increase expenses; result in additional liabilities, investigations and litigation; harm QEP's strategy; 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 agreement and the indentures governing QEP's senior notes impose certain limitations on QEP's ability to enter into mergers, business combinations and divestiture transactions. QEP's credit agreement also limits QEP's ability to incur certain indebtedness, which could limit QEP's ability to engage in acquisitions.
QEP may be unable to divest assets on financially attractive terms, resulting in reduced cash proceeds. Over the past several years, QEP has relied on proceeds from asset divestitures to help fund acquisitions, make capital expenditures and to repay debt. QEP's success in divesting assets depends, in part, upon QEP's ability to identify suitable buyers or joint venture partners; assess potential transaction terms; negotiate agreements; and, if applicable, obtain required approvals. Various factors could materially affect QEP's ability to dispose of assets on terms acceptable to QEP. Such factors include, but are not limited to: current and forecasted commodity prices; current laws, regulations and permitting processes impacting oil and gas operations in the areas where the assets are located; covenants under QEP's credit agreement; tax impacts; willingness of the purchaser to assume certain liabilities such as asset retirement obligations and firm transportation contracts; QEP's willingness to indemnify buyers for certain matters; and other factors.
In addition, QEP's credit agreement contains limitations on the amount of assets that it is permitted to divest each year. If QEP seeks to sell more assets than is permitted under the credit agreement and is unable to receive waivers of such restrictions, then it may be unable to divest these assets.
QEP is required to pay fees to some of its midstream service providers based on minimum volumes regardless of actual volume throughput. QEP has contracts with some third-party service providers for gathering, processing and transportation services with minimum volume delivery commitments under which QEP is obligated to pay certain fees on minimum volumes regardless of actual volume throughput. As of December 31, 2020, QEP's aggregate long-term contractual obligation under these agreements was $70.9 million. These fees could be significant and may have a material adverse effect on QEP's results of operations.
QEP is partially dependent on its revolving credit facility and continued access to capital markets to successfully execute its operating strategies. If QEP is unable to make capital expenditures or acquisitions because it is unable to obtain 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 QEP may not be able to obtain financing at a reasonable cost in the future. QEP is largely dependent on its credit facility to successfully execute its commodity price and interest rate risk mitigation strategies. If QEP is unable to successfully extend the maturity date or amend the terms of its credit facility, it may not be able to obtain adequate access to the necessary credit from its lending group to enter into its preferred amount of derivative contracts with respect to its forecasted annual production. Over the last few years, conditions in the global capital markets have been volatile, making terms for certain types of financing 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 oil, gas 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. In the past, QEP has utilized cash and its revolving credit facility to meet short-term funding needs. At year end 2020, QEP had no outstanding borrowings under its revolving credit facility. QEP's failure to obtain additional financing could result in a curtailment of its operations relating to exploration and development of its prospects, which in turn could lead to a possible reduction in QEP's oil or gas production, reserves and revenues, not having sufficient liquidity to meet future financial obligations and could negatively impact QEP's results of operations.
QEP's debt and other financial commitments may limit its financial and operating flexibility. QEP's total debt was approximately $1.6 billion at December 31, 2020. QEP also has various commitments for leases, drilling contracts, derivative contracts, firm transportation, and purchase obligations for services, products and properties. 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 repurchase shares of its common stock, 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 and proceeds from the divestiture of its assets to payments on its debt or to comply with any restrictive terms of its debt. QEP may be at a competitive disadvantage as compared to similar companies that have less debt. Higher levels of debt may make QEP more vulnerable to general adverse economic and industry conditions. Additionally, the agreement governing QEP's revolving credit facility and the indentures governing QEP's senior notes contain a number of covenants that impose constraints on the Company, including requirements to comply with certain financial covenants and restrictions on QEP's ability to dispose of assets, make certain investments, incur liens and additional debt, and engage in transactions with affiliates. If commodity prices decline and QEP reduces its level of capital spending and production declines or QEP incurs additional impairment expense or the value of the Company's proved reserves declines, the Company may not be able to incur additional indebtedness, may need to repay outstanding indebtedness and may not be in compliance with the financial covenants in its credit agreement in the future. Refer to Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations in Part II of this Annual Report on Form 10-K and Note 9 – Debt, in Item 8 of Part II of this Annual Report on Form 10-K for more information regarding the financial covenants and our revolving credit agreement.
A downgrade in QEP's credit rating could negatively impact QEP's cost of and access to capital. Downgrades of QEP's credit rating may make it more difficult or expensive for QEP to raise capital from financial institutions or other sources and could require QEP to provide financial assurance of its performance under certain contractual arrangements and derivative agreements. Refer to Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations in Part II of this Annual Report on Form 10-K and Note 9 – Debt, in Item 8 of Part II of this Annual Report on Form 10-K for additional information regarding the financial covenants and our revolving credit agreement.
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 oil, gas and NGL prices, and to protect cash flow and returns on capital from downward commodity price movements. QEP's derivative transactions are limited in duration, usually for periods of one to two years. QEP's derivatives portfolio may be inadequate to protect it from prolonged declines in the price of oil or natural gas. To the extent the Company enters into commodity derivative transactions, it may forgo some or all of the benefits of commodity price increases. 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 and realized gains and losses in prior periods and may continue to incur these types of gains and losses in the future.
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 and joint working interest owners. This counterparty credit risk is heightened during times of economic uncertainty, tight credit markets and low commodity prices. 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 or collection issues in QEP receiving proceeds from commodity sales or reimbursement of joint venture costs. Credit enhancements, such as parental guarantees, letters of credit or prepayments, have been obtained from some but not all counterparties. 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 monitors creditworthiness of its trade creditors, joint venture partners, derivative counterparties and financial institutions on an ongoing basis. However, if one of them were to experience a sudden change in liquidity, it could impair such a party's ability to perform under the terms of QEP's contracts. QEP is unable to predict sudden changes in creditworthiness or ability of these parties to perform and could incur significant financial losses.
QEP is involved in legal proceedings that could result in substantial liabilities and materially and adversely impact the Company's financial condition. Like many oil and gas companies, the Company is involved in various legal proceedings, including threatened claims, such as title, royalty, and contractual disputes. The cost to settle legal proceedings (pending or threatened) or satisfy any resulting judgment against the Company in such proceedings could result in a substantial liability or the loss of interests, which could materially and adversely impact the Company's cash flows, operating results and financial condition. Judgments and estimates to determine accruals or the range of reasonably possible loss related to legal proceedings could change from one period to the next, and such changes could be material. Current accruals may be insufficient. Legal proceedings could result in negative publicity about the Company. In addition, legal proceedings distract management and other personnel from their primary responsibilities.
The Company's ability to declare and pay dividends is subject to certain considerations. Dividends are authorized and determined by the Company's Board of Directors in its sole discretion. Decisions regarding the payment of dividends are subject to a number of considerations, including:
•cash available for distribution;
•the Company's results of operations and anticipated future results of operations;
•the Company's financial condition, especially in relation to the anticipated future capital needs;
•the level of cash reserves the Company may establish to fund future capital expenditures;
•the Company's stock price; and
•other factors the board of directors deems relevant.
The Company can provide no assurance that it will pay dividends in the future.
Regulatory Risks
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. This 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, other damages, or injunctions that could limit the scope of QEP's planned operations.
Moreover, uncertainty about the future course of regulation exists because of the recent change in the U.S. presidential administration. In January 2021, the current administration issued an executive order directing all federal agencies to review and take action to address any federal regulations, orders, guidance documents, policies and any similar agency actions
promulgated during the prior administration that may be inconsistent with the administration’s policies. As a result, it is unclear the degree to which certain recent regulatory developments may be modified or rescinded. The executive order also established an Interagency Working Group on the Social Cost of Greenhouse Gases (Working Group), which is called on to, among other things, develop methodologies for calculating the “social cost of carbon,” “social cost of nitrous oxide” and “social cost of methane.” Recommendations from the Working Group are due beginning June 1, 2021, and final recommendations no later than January 2022. Further regulation of air emissions, as well as uncertainty regarding the future course of regulation, could eventually reduce the demand for oil and natural gas. Also in January 2021, the current administration issued the 2021 Climate Change Executive Order. Among other things, the 2021 Climate Change Executive Order directed the Secretary of the Interior to pause new oil and natural gas leasing on public lands or in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices, consider whether to adjust royalties associated with coal, oil, and gas resources extracted from public lands and offshore waters, or take other appropriate action, to account for corresponding climate costs. The 2021 Climate Change Executive Order also directs the federal government to identify "fossil fuel subsidies" to take steps to ensure that, to the extent consistent with applicable law, federal funding is not directly subsidizing fossil fuels. Legal challenges to the suspension have already been filed and are currently pending.
QEP complies with numerous environmental regulations. Refer to Items 1 & 2 of Part I Government Regulations of this Annual Report on Form 10-K for additional detail on these regulations.
Regulatory requirements to reduce gas flaring and to further restrict emissions could have an adverse effect on our operations. Wells in the Williston Basin of North Dakota and the Permian Basin of Texas, where QEP has significant operations, produce natural gas as well as crude oil. Constraints in third party gas gathering and processing systems in certain areas have resulted in some of that natural gas being flared instead of gathered, processed and sold. In 2014, the NDI Commission, North Dakota's chief energy regulator, adopted a policy to reduce the volume of natural gas flared from oil wells in the Williston Basin. The NDI Commission requires operators to develop gas capture plans that describe how much natural gas is expected to be produced, how it will be delivered to a processor and where it will be processed. Production caps or penalties may be imposed on certain wells that cannot meet the capture goals. It is possible that other states in which QEP operates, including Texas, will require gas capture plans or otherwise institute new regulatory requirements in the future to reduce flaring.
In July and October 2020, after several years of litigation, federal courts struck down both the BLM’s 2016 Waste Prevention Rule and its 2018 Revised Waste Prevention Rule. The effect of these orders combined is to essentially reinstate the previous rule, Notice to Lessees and Operators of Onshore Federal and Indian Oil and Gas Leases: Royalty or Compensation for Oil and Gas Lost (NTL-4A). However, future gas capture requirements and other regulatory requirements, in North Dakota or our other locations, could increase our operational costs and restrict our production, which could materially and adversely affect our financial condition, results of operations and cash flows. If our interpretation of the applicable regulations is incorrect, or if we receive a non-appealable order to pay royalty on past and future flared volumes in North Dakota, such royalty payments could materially and adversely affect our financial condition and cash flows.
The 2021 Climate Change Executive Order directs the Secretary of Interior to impose a moratorium on new oil and natural gas leases on public lands, or offshore waters to the extent possible, and launch a rigorous review of all existing leasing and permitting practices related to fossil fuel development on public lands. This moratorium may include restrictions of approving right-of-ways that could help build out midstream infrastructure needed to help reduce flaring. Any restrictions to building out pipelines or necessary infrastructure by federal, state and tribal governments could make flaring worse.
Rules regarding crude oil shipments by rail may pose unique hazards that may have an adverse effect on our operations. The NDI Commission requires that crude oil produced in the Bakken Petroleum System be conditioned to remove lighter, volatile hydrocarbons and improve the marketability and safe transportation of the crude oil by rail. The U.S. Department of Transportation rule regarding the safe transportation of flammable liquids by rail imposes certain requirements on "offerors" of crude oil, including sampling, testing, and certification requirements. These conditioning requirements, and any similar future obligations imposed at the state or federal level, may increase our operational costs or restrict our production, which could materially and adversely affect our financial condition, results of operations and cash flows.
Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in areas where we operate. Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various species and wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect threatened and endangered species could prohibit drilling in certain areas or require the
implementation of expensive mitigation measures. The designation of previously unprotected species as threatened or endangered in areas where we operate could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have a material adverse effect on our ability to develop and produce our reserves.
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 federal Clean Air Act, Clean Water Act, 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 ENGOs to oppose drilling on some of QEP's federal and state leases. These organizations sometimes sue federal and state regulatory agencies and/or the Company under these laws alleging 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. 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. In addition, the BIA implemented final regulations in March 2016, which significantly altered the procedure for obtaining rights-of-way on tribal lands. These new regulations may increase the time and cost required to obtain necessary rights-of-way for QEP's operations on tribal lands, and rights-of-way issued under these new regulations expressly make QEP subject to a tribe's regulatory and judicial jurisdiction.
In April 2020, the U.S. District Court for the District of Montana vacated the Corps’ 2017 issuance of NWP 12 (the general permit issued by the Corps for pipelines and utility projects). In May 2020, the court narrowed its ruling, vacating and enjoining the use of NWP 12 only as it relates to construction of new oil and gas pipelines. The Corps appealed the decision to the U.S. Court of Appeals for the Ninth Circuit and the litigation is ongoing. In July 2020, the U.S. Supreme Court granted in part and denied in part the Corps’ application for stay of the order issued by the district court. The U.S. Supreme Court stayed the lower court order except as it applies to the Keystone XL pipeline. The stay is to remain in place pending disposition of the appeal currently pending before the Ninth Circuit. In January 2021, the Corps released the final version of a rule renewing twelve of its NWPs, including NWP 12. The new rule splits NWP 12 into three parts; NWP 12 will continue to be available for oil and gas pipelines, while new NWP 57 will be available for electric utility line and telecommunications activities, and a new NWP 58 will be available for utility line activities for water and other substances. The new rule also eliminates preconstruction notice requirements for NWP 12 for several conditions that used to require such notice, but also now requires new oil and gas pipeline projects that exceed 250 miles in length to give preconstruction notice and obtain approval before proceeding. We cannot predict at this time how the new rule will be implemented, because permits are issued by the local Corps district offices, or whether it will remain in place following the review required by the Biden executive orders. However, if new oil and gas pipeline projects are unable to utilize NWP 12 or identify an alternate means of Clean Water Act compliance, such projects could be significantly delayed, which could have an adverse impact on our operations.
Our operations on the Fort Berthold Indian Reservation of the Three Affiliated Tribes in North Dakota are subject to various federal, state, local and tribal regulations and laws, any of which may increase our costs and have an adverse impact on our ability to effectively conduct our operations. Various federal agencies within the U.S. Department of the Interior, particularly the BIA and the Office of Natural Resource Revenue, along with the Three Affiliated Tribes of the Fort Berthold Indian Reservation (TAT), promulgate and enforce regulations pertaining to operations on the Fort Berthold Indian Reservation. In addition, the TAT is a sovereign nation having the right to enforce laws and regulations independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees, approvals and other conditions that apply to lessees, operators and contractors conducting operations on the Fort Berthold Indian Reservation. Lessees and operators conducting operations on tribal lands may be subject to the TAT's court system. One or more of these factors may increase our costs of doing business on the Fort Berthold Indian Reservation and may have an adverse impact on our ability to effectively transport products within the Fort Berthold Indian Reservation or to conduct our operations on such lands.
Federal and state hydraulic fracturing legislation or regulatory initiatives could increase QEP's costs and restrict its access to oil and gas reserves. Currently, well construction activities, including hydraulic fracture stimulation, are regulated by state agencies that review and approve oil and gas well design and operation. The EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the SDWA and issued guidance related to this asserted regulatory authority. The EPA may consider seeking to further regulate hydraulic fracturing fluids and/or the components of those fluids. At the state and local level, some states and local governments have adopted, and other states and local governments have considered adopting regulations and moratoria that could restrict or prohibit hydraulic fracturing in certain circumstances. If new or more stringent federal, state, tribal 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.
In December 2016, the EPA released its final report on the potential for impacts to drinking water resources from hydraulic fracturing. The study concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances. Many other recent studies and reports have examined the potential impacts of hydraulic fracturing on the public and the environment. These and future studies could form a basis for additional regulations, which could lead to operational burdens similar to those described above.
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. Water is an essential component of QEP’s drilling and hydraulic fracture stimulation processes. 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. In some cases, QEP may need to obtain water from new sources and transport it to drilling sites, resulting in increased costs. In recent years, West Texas has experienced a severe drought. Accordingly, QEP may experience difficulty in securing the necessary volumes of water for its operations. QEP's inability to timely secure sufficient amounts of water, or to dispose of or recycle the water used in its operations, could adversely impact its operations. Moreover, the imposition of new environmental 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 oil and 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 or may cause QEP to delay, curtail or discontinue its exploration and development plans, which could have a material adverse effect on its business, financial condition, results of operations and cash flows.
Legislation or regulatory initiatives intended to address induced seismicity could restrict QEP's drilling and production activities as well as QEP's ability to dispose of produced water gathered from such activities, which could have a material adverse effect on QEP's business. State and federal regulatory agencies have focused on a possible connection between the disposal of wastewater in underground injection wells, or to a lesser extent the hydraulic fracturing of oil and gas wells, and the increased occurrence of seismic activity in certain areas, and regulatory agencies at all levels are continuing to study the possible linkage between oil and natural gas activity and induced seismicity. For example, in 2015, the United States Geological Survey identified eight states, including Texas, with areas of increased rates of seismic activity that may be attributable to fluid injection or oil and natural gas extraction activities. In addition, a number of lawsuits have been filed, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, in 2014, the TRRC published a new rule governing permitting or re-permitting of disposal wells that requires, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or applicant fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific data indicate the well is likely or determined to be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the permit application or existing operating permit for that well.
QEP operates injection wells and utilizes injection wells owned by third parties to dispose of large volumes of waste water associated with its drilling, completion and production operations. QEP disposes of these volumes of produced water pursuant to permits issued to QEP by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements or prohibitions on operating certain facilities, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations or the issuance of any orders or imposition of any requirements that restrict QEP's ability to use hydraulic fracturing or dispose of produced water gathered from its drilling and production activities by limiting volumes, injection pressures or rates, or restricting producing or disposal well locations, or requiring QEP to shut down disposal wells, could have a material adverse effect on QEP's business, financial condition and results of operations.
Climate change and climate change legislation and regulatory initiatives, including renewable energy mandates could result in increased operating costs and decreased demand for the oil and natural gas that we produce. Climate change, the costs that may be associated with its effects, the required use of renewable energy, and the regulation of GHG emissions have the potential to affect our business in many ways, including increasing the costs to provide our products, reducing the demand for and consumption of our products (due to changes in both costs and weather patterns) and negatively impacting the economic health of the regions in which we operate, all of which can create financial risks. In addition, if restrictions on GHG emissions and mandates for use of renewable energy significantly increase our costs to produce oil and gas, or significantly decrease demand for our products, the value of our oil and gas reserves may decrease. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. In addition, legislative and regulatory responses related to GHG emissions, climate change and renewable energy use may result in increased operating costs, delays in obtaining air emissions and other necessary permits for new or modified facilities and reduced demand for the oil, gas and NGL that QEP produces. Federal and state courts and administrative agencies are considering the scope and scale of potential climate-change-related regulation under various existing laws pertaining to the environment, energy use and energy resource development. Federal, state and local governments may also pass laws specifically aimed at GHG regulation, and mandating the use of renewable energy sources, such as wind power and solar energy, or restricting or banning the use of gasoline or diesel powered vehicles, which may reduce demand for oil and natural gas. Although Congress previously considered but did not adopt proposed legislation aimed at reducing GHG emissions, recent Congressional resolutions and the new Democratic majority in both the Senate and House of Representatives make it likely Congress will soon consider new legislation requiring decarbonization or use of renewable energy in much higher proportions. Recently, several states and local jurisdictions have pledged to remove internal combustion engines from their roads as early as 2035. Further, state and local governments may pursue additional litigation against oil and gas producers for damages allegedly resulting from climate change. QEP's ability to access and develop new oil and gas reserves may also be restricted by climate change regulations, including GHG reporting and regulation.
The EPA has adopted final regulations under the Clean Air Act for the measurement and reporting of GHG emitted from certain large facilities and, as discussed above, has adopted additional regulations, intended to include additional requirements to reduce methane and volatile organic compound emissions from oil and natural gas facilities. The status of those regulations is uncertain given the ongoing litigation, administrative reconsideration, final revisions to those rules announced in August 2020, and the prospects for legal challenges to such revisions. In addition, in January 2021, the administration issued an executive order calling on the EPA to, among other things, consider a proposed rule suspending, revising or rescinding the deregulatory amendments by September 2021. Additionally, in 2014, the United States Supreme Court upheld a portion of EPA's GHG stationary source permitting program in Utility Air Regulatory Group v. EPA, but also invalidated a portion of it. The Court's holding does not prevent states from considering and adopting state-only major source permitting requirements based solely on GHG emission levels. Federal and state regulatory agencies can impose administrative, civil and/or criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations to which QEP's operations are subject, including certain existing GHG permitting requirements.
In 2015, over 190 countries, including the U.S., met in Paris (COP 21) and agreed to reduce global emissions of GHG by entering into the Paris Climate Agreement. The Paris Climate Agreement provides for the cutting of carbon emissions every five years, beginning in 2023, and sets a goal of keeping global warming to a maximum limit of two degrees Celsius and a target limit of 1.5 degrees Celsius greater than pre-industrial levels. However, in November 2019, President Trump initiated the formal process to withdraw the United States from the Paris Climate Agreement with an effective withdrawal date of November 2020. The 2021 Climate Change Executive Order commenced the process for the U.S. reentering the Paris Climate Agreement, although the emissions pledges in connection with that effort have not yet been updated. State and local climate regulatory efforts are expected to increase. In several of the states in which QEP operates the regulatory authorities are considering various GHG registration and reduction programs, including methane leak detection monitoring and repair requirements specific to oil and gas facilities. In addition, the failure of the federal government to address climate change concerns, including, for example, a protracted delay by President Trump's administration in determining its own carbon-cost estimate (i.e., the estimate of how much carbon pollution costs society via climate damages) after rejecting the $40 per ton of carbon dioxide equivalent estimate of the Obama administration, could afford ENGOs additional opportunities to pursue further legal challenges to oil and gas drilling and pipeline projects.
Moreover, some experts believe climate change poses potential physical risks, including an increase in sea level and changes in weather conditions, such as an increase in precipitation and extreme weather events. In addition, warmer winters in some regions as a result of climate change could also decrease demand for natural gas. To the extent that such unfavorable weather conditions are realized due to climate change or otherwise, our operations may be adversely affected to a greater degree than we have previously experienced, including increased delays and costs. However, the uncertain nature of changes in extreme weather events (such as increased frequency, duration, and severity) and the long period of time over which any changes would take place make any estimations of future financial risk to our operations caused by these potential physical risks of climate change unreliable. In January 2021, President Biden issued the 2021 Climate Change Executive Order. It sets goals of a carbon pollution free power sector by 2035 and a net zero economy by 2050.
A change in the jurisdictional characterization of some of our assets by federal, state, or local regulatory agencies or a change in policy by those agencies could result in increased regulation of our assets, which could cause our revenues to decline and operating expenses to increase. We believe that our gas gathering systems meet the traditional tests FERC has used to determine if a pipeline is a gas gathering pipeline and is, therefore, not subject to FERC jurisdiction. FERC, however, has not made any determinations with respect to the jurisdictional status of any of these gas gathering systems. The distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of ongoing litigation and, over time, FERC policy concerning which activities it regulates and which activities are excluded from its regulation has changed. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation.
In addition, QEP's crude oil pipelines (specifically the rates, terms and conditions for shipments) may also be subject to FERC regulation if QEP's crude oil pipelines provide part of the movement in interstate or foreign commerce for shippers (pursuant to the Interstate Commerce Act, as it existed on October 1, 1977, the Energy Policy Act of 1992 and related rules). QEP does not control the entire transportation path of all crude oil shipped on QEP's pipelines. Therefore, FERC regulation could be triggered by QEP's customers' transportation decisions.
FERC makes jurisdictional determinations for both natural gas gathering and crude oil lines on a case-by-case basis. The classification and regulation of our pipelines are subject to change based on future determinations by FERC, the courts, or Congress. A change in the jurisdictional characterization of some of our assets by federal, state, or local regulatory agencies or a change in policy by those agencies could result in increased regulation of our assets, which could cause our revenues to decline and operating expenses to increase.
The taxation of independent producers is subject to change, and changes in tax law could increase our cost of doing business. We are subject to taxation by various taxing authorities at the federal, tribal, state and local levels where we do business. Legislation has been proposed in the past, and could be proposed and enacted in the future, that could increase the taxes or fees imposed on oil and natural gas extraction and properties, corporate and state tax rates, deductibility of expense items or impact the refundability of U.S. alternative minimum tax credits we currently expect to receive. Any such legislation could also impact our liquidity and result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our oil and natural gas. The 2021 Climate Change Executive Order directs federal agencies to eliminate "fossil fuel subsidies" as consistent with applicable law, which may implicate the treatment of oil and gas assets and production under the Code.
If we were to experience an "ownership change," we could be limited in our ability to use certain tax attributes arising prior to the ownership change to offset future taxable income. If we were to experience an "ownership change," as determined
under section 382 of the Internal Revenue Code of 1986, as amended, our ability to offset taxable income arising after the ownership change by utilizing NOL's arising prior to the ownership change could be limited, possibly substantially. Additionally, the deductibility of disallowed interest expense carryforward, pursuant to the tax legislation enacted in December 2017 (Tax Cuts and Jobs Act), could also be limited post-ownership change. An ownership change would establish an annual limitation on the amount of our pre-ownership change losses, including NOL's, tax credits, and disallowed interest expense carryforward, that we could utilize in any future taxable year to an amount generally equal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate.
The enactment of derivatives legislation, and the promulgation of regulations pursuant thereto, could have an adverse impact on QEP's ability to use derivative instruments to reduce the effect of commodity price volatility and other risks associated with its business. The Dodd-Frank Act, which was signed into law in July 2010, contains significant derivatives regulation, including, among other items, a requirement that certain transactions be cleared on exchanges as well as collateral or "margin" requirements for certain uncleared swaps. The Dodd-Frank Act provides for an exception from these clearing requirements for commercial end-users, such as QEP. 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 creditworthy 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 its regulations is to lower commodity prices. Any of these consequences could affect the pricing of derivatives and make it more difficult for us to enter into derivative transactions, which could have a material and adverse effect on QEP's business, financial condition and results of operations. The rulemaking and implementation process are ongoing and the ultimate effect of the adopted rules and regulations and any future rules and regulations on QEP's business remains uncertain.
General Risks
Events of force majeure may limit our ability to operate our business and could adversely affect our operating results.
The weather, unforeseen events, or other events of force majeure in the areas in which we operate could cause disruptions and, in some cases, suspension of our operations. This suspension could result from a direct impact to our properties or result from an indirect impact by a disruption or suspension of the operations of those upon whom we rely for gathering, processing and transportation. If disruption or suspension were to persist for a long period, our results of operations would be materially impacted.
Changes in LIBOR reporting practices or the method in which LIBOR is determined may adversely affect the market value of QEP’s current or future debt obligations, including QEP’s revolving credit facility. The interest rate in QEP's revolving credit facility is indexed to the London Interbank Offered Rate (LIBOR). On July 27, 2017, the Financial Conduct Authority (the FCA) announced its intention to phase out LIBOR rates by the end of 2021. It is unclear whether LIBOR will cease to exist or if new methods of calculating LIBOR will be established such that it continues to exist after 2021, or whether any alternative reference rate will attain market acceptance as a replacement for LIBOR. It is not possible to predict the further effect of the rules of the FCA, any changes in the methods by which LIBOR is determined or any other reforms to LIBOR that may be enacted in the United Kingdom, the European Union or elsewhere. Any such developments may cause LIBOR to perform differently than in the past, or cease to exist. In addition, any other legal or regulatory changes made by the FCA, the European Commission or any other successor governance or oversight body, or future changes adopted by such body, in the method by which LIBOR is determined or the change from LIBOR to a successor benchmark may result in, among other things, a sudden or prolonged increase or decrease in LIBOR, a delay in the publication of LIBOR, and changes in the rules or methodologies in LIBOR, which may discourage market participants from continuing to administer or to participate in LIBOR’s determination, and, in certain situations, could result in LIBOR no longer being determined and published. If a published U.S. dollar LIBOR rate is unavailable after 2021, the interest rates on our debt which are indexed to LIBOR will be determined using a benchmark replacement as defined in the Eighth Amendment of the credit facility, which may result in interest obligations which are more than or do not otherwise correlate over time with the payments that would have been made on such debt if U.S. dollar LIBOR was available in its current form. Further, the same costs and risks that may lead to the discontinuation or unavailability of U.S. dollar LIBOR may make one or more of the benchmark replacement methods impossible or impracticable to determine. Any of these proposals or consequences could have a material adverse effect on our financing costs. As of February 17, 2021, we had no outstanding borrowings under our revolving credit facility.
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. Violations of any laws or regulations caused by either failure of our internal controls related to regulatory compliance or failure of our employees to comply with our internal policies could result in substantial civil or criminal fines. In addition, legal enforcement may be impacted by significant incentives for whistleblowers.
QEP is exposed 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 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. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. QEP's technologies, systems and networks, and those of its vendors, suppliers and other business partners, may become the target of cyberattacks 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 does not maintain specialized insurance for possible losses resulting from a cyberattack on its assets that may shut down all or part of QEP's business. QEP's systems for protecting against cyber security risks may not be sufficient.
While QEP and its vendors have experienced cyberattacks, QEP is not aware of any material losses relating to cyberattacks; however, there is no assurance that QEP will not suffer such losses in the future. In addition, as cybersecurity threats continue to evolve, QEP may expend additional resources to continue to modify or enhance its protective measures or to investigate or remediate any cybersecurity vulnerabilities.
We may be unable to quickly adapt to changes in market/investor priorities. Historically, one of the key drivers in the unconventional resource industry has been growth in production and reserves. With the continued downturn and volatility in oil and natural gas prices, and the possibility that interest rates will rise in the near term, increasing the cost of borrowing, the market and investor emphasis has elevated capital efficiency and free cash flow from earnings as potentially the key drivers for energy companies, especially those primarily focused in the shale play arena. Shifts in focus such as these sometimes require changes in planning and resource management, which cannot necessarily occur instantaneously. Any delay in responding to such changes in market sentiment or perception can result in the investment community in general having a negative sentiment regarding our business plan, potential profitability and our ability to operate in a manner deemed “efficient,” which can have a negative impact on the price of our common stock.