QEP Resources Earnings 2020-12-31
| Balance Sheet | Income Statement | Cash Flow |
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
For the fiscal year ended December 31, 2020
For the transition period from ___________ to ___________
| (Commission File No.) | ||||||||
(Exact name of registrant as specified in its charter)
| (State or other jurisdiction of incorporation) | (I.R.S. Employer Identification No.) | |||||||
(Address of principal executive offices)
Registrant's telephone number, including area code: 303 -672-6900
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||||||
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth" in Rule 12b-2 of the Exchange Act.
| Large accelerated filer | ☐ | ☒ | ||||||||||||
| Non-accelerated filer | ☐ | Smaller reporting company | ||||||||||||
| Emerging growth company | ||||||||||||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second fiscal quarter (June 30, 2020): $312,599,033 .
At January 31, 2021, there were 242,565,822 shares of the registrant's $0.01 par value common stock outstanding.
TABLE OF CONTENTS
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ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE | #SectionPage# | ||||||
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Where You Can Find More Information
QEP Resources, Inc. (QEP or the Company) files annual, quarterly, and current reports with the U.S. Securities and Exchange Commission (SEC). The SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC, including QEP.
Investors can also access financial and other information via QEP's website at www.qepres.com. QEP makes available, free of charge through the website, copies of Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to such reports and all reports filed by executive officers and directors under Section 16 of the Securities Exchange Act of 1934 (the Exchange Act) reporting transactions in QEP securities. Access to these reports is provided as soon as reasonably practical after such reports are electronically filed with the SEC. Information contained on or connected to QEP's website which is not directly incorporated by reference into this Annual Report on Form 10-K should not be considered part of this report or any other filing made with the SEC.
QEP's website also can be used to access copies of charters for various board committees, including the Audit Committee, and governance documents, including QEP's Corporate Governance Guidelines and QEP's Code of Conduct. While the Company recommends that you view QEP's website, the information available on QEP's website is not part of this report and is not incorporated herein by reference.
You may request a copy of filings other than an exhibit to a filing unless that exhibit is specifically incorporated by reference into that filing, at no cost by writing or calling QEP, 1050 17th Street, Suite 800, Denver, CO 80265 (telephone number: 303-672-6900).
Cautionary Statement Regarding Forward-Looking Statements
This Annual Report on Form 10-K contains or incorporates by reference information that includes or is based upon "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the Securities Act), and Section 21E of the Exchange Act. Forward-looking statements give expectations or forecasts of future events. You can identify these statements by the fact that they do not relate strictly to historical or current facts. We use words such as "anticipate," "estimate," "expect," "project," "intend," "plan," "believe," and other words and terms of similar meaning in connection with a discussion of future operating or financial performance. Forward-looking statements include statements relating to, among other things:
•focus on returns-driven growth and superior execution and strategies to achieve these objectives;
•our strategic objectives;
•effect of the novel Coronavirus disease (COVID-19) pandemic on our business results;
•the belief that the Company will be able to maintain positive cash flow and protect its balance sheet, with the ultimate goal of protecting shareholder returns over the long term;
•completion of the merger is expected to occur late in the first quarter of 2021;
•reductions in general and administrative expense to ensure our cost structure is competitive with industry peers;
•the effect of the strategic initiatives on employees and third parties;
•plans to generate Free Cash Flow and focus on capital efficiency;
•drilling and completion plans and strategies;
•adding additional acreage in our operating areas;
•estimated reserves and development of such reserves;
•adequacy of procedures implemented to protect against credit-related losses;
•expectations and assumptions regarding oil, gas and NGL prices;
•development of proved undeveloped (PUD) reserves within five years;
•reclassification of PUD reserves;
•PUD conversion rates and factors impacting conversion of PUD reserves;
•future development costs and funding sources for same;
•factors affecting our decision to modify our development plans;
•our ability to meet delivery and sales commitments;
•the effect of lost customers on the financial position or results of operations;
•FERC regulation of oil and gas pipelines;
•impact of tax legislation on our tax position and after-tax earnings or financial statements;
•adequacy of insurance;
•volatility of oil, gas and NGL prices and factors impacting such prices;
•the effects of oil, gas and NGL prices on our business;
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•beliefs about the reduction of global spending on new oil and gas projects and a corresponding reduction in the global oil supply;
•expectations regarding the impact of the agreement among Organization of Petroleum Exporting Countries (OPEC) and other oil producing countries on oil prices;
•impact of shutting in wells;
•factors impacting our ability to transport oil and condensate and gas;
•credit agreement limitations that could prevent QEP from incurring certain indebtedness, which could limit QEP's ability to engage in acquisitions;
•credit agreement limitations on divestitures;
•impact of potential activist shareholders to our operations, personnel retention, strategies and costs;
•incurring penalties related to air emission noncompliance and capital expenditures to maintain or obtain operating permits and approvals;
•the underfunded status of our pension plan;
•the adjustments made to GAAP Measures to arrive at non-GAAP measures and the usefulness of non-GAAP financial measures;
•our inventory of drilling locations and the ability of that inventory to provide a solid base for generating Free Cash Flow and capital efficiency;
•evaluation of potential acquisitions, divestitures and joint venture opportunities;
•our balance sheet and sufficient liquidity providing for the ability to meet future financial obligations, ensure financial flexibility, withstand commodity price volatility, fund its development projects, operations and capital expenditures and return capital to shareholders;
•our ability to fund maturities of senior notes;
•future availability under our revolving credit facility or continued compliance with restrictive financial covenants;
•adjustments to our capital investment program based on a variety of factors, including an evaluation of drilling and completion activities and drilling results;
•focus on operating costs and per well drilling costs;
•amount and allocation of forecasted capital expenditures (excluding property acquisitions) and, plans and sources for funding operations and capital investments;
•impact of lower or higher commodity prices and interest rates;
•potential for asset impairments and factors impacting impairment amounts;
•fair value estimates and related assumptions and assessment of the sensitivity of changes in assumptions, and critical accounting estimates, including estimated asset retirement obligations;
•impact of global geopolitical and macroeconomic events and the monitoring of such events;
•plans regarding derivative contracts, including the volumes utilized, and the anticipated benefits derived there from;
•outcome and impact of various claims;
•expected cost savings and other efficiencies from multi-well pad drilling, including "tank-style" development;
•delays in completion of wells, well shut-ins and volatility to operating results caused by multi-well pad drilling;
•predictability and success of our drilling operations;
•plans and ability to pursue acquisition opportunities;
•value of pension plan assets and our plans regarding additional contributions to our pension plan;
•our plans regarding contributions to the nonqualified retirement plan (SERP), medical plan and 401(k) plan;
•the estimated actuarial loss and services cost and discount rate assumptions related to our pension plan, the SERP and medical plan, as applicable;
•estimates of the amount of additional indebtedness we may incur under our revolving credit facility;
•off-balance sheet arrangements;
•impact of inflation and price changes on our ability to raise capital, borrow money and retain personnel;
•leasehold development and financial capability to continue planned development;
•estimates of environmental remediation costs and factors impacting such estimates;
•adequacy of tax accruals and potential changes to such accruals;
•potential retirement of debt through various options, including exchanges, open market purchases, tender offers and privately negotiated transactions;
•factors impacting our ability to borrow and the interest rates offered;
•factors impacting bad debt expense;
•assumptions regarding share-based compensation;
•settlement of performance share units and restricted share units in cash;
•plans to use proceeds from any additional sales of assets to fund on-going operations, reduce debt and for general corporate purposes;
•use of net operating losses;
•alternative minimum tax credit refund amounts and timing; and
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•the belief that 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.
Any or all forward-looking statements may turn out to be incorrect. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. These statements are based on current expectations and the current economic environment. They involve a number of risks and uncertainties that are difficult to predict. These statements are not guarantees of future performance. Actual results could differ materially from those expressed or implied in the forward-looking statements. Factors that could cause actual results to differ materially include, but are not limited to the following:
•the risk factors in Part I, Item 1A of this Annual Report on Form 10-K;
•any potential impact from the announcement that the Company has entered into a merger agreement with Diamondback Energy, Inc. and Bohemia Merger Sub, Inc.;
•changes in oil, gas and NGL prices;
•global geopolitical and macroeconomic factors;
•general economic conditions, including the performance of financial markets and interest rates;
•the length and severity of a pandemic or health crisis, such as the outbreak of COVID-19 and the measures that international, federal, state and local governments, agencies, law enforcement and/or health authorities implement to address it, which may (as with COVID-19) precipitate or exacerbate one or more of the factors herein, reduce the demand for oil, gas and NGLs and significantly disrupt or prevent us from operating our business in the ordinary course for an extended period;
•the risks and liabilities associated with acquired assets;
•asset impairments;
•liquidity constraints, including those resulting from the cost and availability of debt and equity financing;
•drilling and completion strategies, methods and results;
•assumptions around well density/spacing and recoverable reserves per well prove to be inaccurate;
•changes in estimated reserve quantities;
•changes in management's assessments as to where QEP's capital can be most profitably deployed;
•shortages and costs of oilfield equipment, services and personnel;
•changes in development plans;
•lack of available pipeline, processing and refining capacity;
•processing volumes and pipeline throughput;
•risks associated with hydraulic fracturing;
•the outcome of contingencies such as legal proceedings;
•delays in obtaining permits and governmental approvals;
•operating risks such as unexpected drilling conditions and risks inherent in the production of oil and gas;
•weather conditions;
•changes in, adoption of and compliance with laws and regulations, including decisions and policies concerning: the environment, climate change, greenhouse gas or other emissions, renewable energy mandates, natural resources, fish and wildlife, hydraulic fracturing, water use and drilling and completion techniques, as well as the risk of legal proceedings arising from such matters, whether involving public or private claimants or regulatory investigative or enforcement measures;
•derivative activities;
•potential losses or earnings reductions from our commodity price risk management programs;
•volatility in the commodity-futures market;
•failure of internal controls and procedures;
•failure of our information technology infrastructure or applications to prevent a cyberattack;
•the increased exposure to cyber and other operational risks that may result due to many of our employees working remotely for an indefinite time period due to safety concerns related to the COVID-19 pandemic;
•elimination of federal income tax deductions for oil and gas exploration and development costs;
•production, severance and property taxation rates;
•discount rates;
•regulatory approvals and compliance with contractual obligations;
•actions of, or inaction by federal, state, local or tribal governments, foreign countries and the Organization of Petroleum Exporting Countries;
•lack of, or disruptions in, adequate and reliable transportation for our production;
•competitive conditions;
•production and sales volumes;
•actions of operators on properties in which we own an interest but do not operate;
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•estimates of oil and gas reserve quantities;
•reservoir performance;
•operating costs;
•inflation;
•capital costs;
•creditworthiness and performance of the Company's counterparties, including financial institutions, operating partners and other parties;
•volatility in the securities, capital and credit markets;
•actions by credit rating agencies and their impact on the Company;
•changes in guidance issued related to tax reform legislation and the Coronavirus Aid, Relief, and Economic Security Act (CARES Act) or application of that guidance;
•changes in tax laws pertaining to independent exploration and production producers;
•actions of activist shareholders;
•any impact of the ongoing COVID-19 pandemic or any government restrictions or other responses thereto on the pending merger, including the QEP special meeting of stockholders to be held virtually on the QEP special meeting website;
•the risk that the merger agreement may be terminated in accordance with its terms and that the merger may not be completed;
•the risk that the parties may not be able to satisfy the conditions to the completion of the merger in a timely manner or at all, including the possibility that QEP stockholders do not approve the merger proposal;
•the possibility that QEP will incur significant transaction and other costs in connection with the merger, which may be in excess of those anticipated by QEP;
•the risk of any litigation relating to the merger;
•the risk related to disruption of management time from ongoing business operations due to the merger; and
•other factors, most of which are beyond the Company's control.
QEP undertakes no obligation to publicly correct or update the forward-looking statements in this Annual Report on Form
10-K, in other documents, or on the Company's website to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.
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Glossary of Terms
Adjusted EBITDA A non-GAAP financial measure which management defines as earnings before interest, income taxes, depreciation, depletion and amortization (EBITDA), adjusted to exclude changes in fair value of derivative contracts, exploration expenses, gains and losses from asset sales, impairment, gains or losses from early extinguishment of debt and certain other items.
Adjusted transportation and processing costs A non-GAAP financial measure which management defines as transportation and processing costs presented on the Consolidated Statements of Operations and transportation and processing costs that are included as part of "Oil and condensate, gas and NGL sales" on the Consolidated Statements of Operations. These costs are added together to reflect the total transportation and processing costs associated with QEP's production.
Argus WTI Midland An index price reflecting the weighted average price of WTI at the pipeline and storage hub at Midland, Texas.
B Billion.
bbl Barrel, which is equal to 42 U.S. gallons liquid volume and is a common measure of volume of crude oil and other liquid hydrocarbons.
basis The difference between a reference or benchmark commodity price and the corresponding sales price at various regional sales points.
basis swap A financial derivative that fixes the price difference between two sales points for a specified commodity volume over a specified time period.
Boe Barrel of oil equivalent.
Btu One British thermal unit – a measure of the amount of energy required to raise the temperature of a one-pound mass of water one degree Fahrenheit at sea level.
cf Cubic foot or cubic feet is a common unit of gas measurement. One standard cubic foot equals the volume of gas in one cubic foot measured at standard conditions – a temperature of 60 degrees Fahrenheit and a pressure of 30 inches of mercury (approximately 14.7 pounds per square inch).
development well A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
dry hole An exploratory, development or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
exploratory well A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.
FERC The Federal Energy Regulatory Commission.
Free Cash Flow A non-GAAP financial measure which management defines as Adjusted EBITDA plus certain non-cash items that are included in Net Cash Provided by (Used in) Operating activities but excluded from Adjusted EBITDA less interest expense, excluding amortization of debt issuance costs and discounts, and accrued property, plant and equipment capital expenditures.
GAAP Accounting principles generally accepted in the United States of America.
gas All references to "gas" in this report refer to natural gas.
gross "Gross" oil and gas wells or "gross" acres are the total number of wells or acres in which the Company has an ownership interest.
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IF Waha Index pricing reported in Platts' Inside FERCs' Gas Market Report, reflects the weighted average price of Natural Gas transactions at the Waha Hub in west Texas on the first day of the month.
M Thousand.
MM Million.
mineral interest The economic interest or ownership of minerals, giving the owner the right to a share of the minerals produced or proceeds from the sale of the minerals.
midstream Gas gathering, compression, treating, processing, and transmission assets and activities that are non-jurisdictional. Also includes certain crude oil, water distribution and produced water gathering and disposal systems and related commercial activities.
natural gas liquids (NGL) Liquid hydrocarbons that are extracted from the natural gas stream. NGL products include ethane, propane, butane, natural gasoline and heavier hydrocarbons.
net "Net" oil and gas wells or "net" acres are the sum of the fractional working interest the Company owns in the gross wells or acres. "Net" revenues are QEP's share of revenues from wells after deductions of royalties, overrides, net profits and other lease burdens.
NYMEX The New York Mercantile Exchange.
NYMEX CMA The New York Mercantile Exchange current month average (CMA) price of crude oil.
NYMEX HH The New York Mercantile Exchange price of natural gas at the Henry Hub.
NYMEX WTI The New York Mercantile Exchange price of West Texas Intermediate crude oil.
oil All references to "oil" in this report refer to crude oil and condensate.
oil equivalent Natural gas is converted to a crude oil equivalent at the ratio of six Mcf of natural gas to one barrel of crude oil equivalent.
possible reserves Those additional reserves that are less certain to be recovered than probable reserves.
probable reserves Those additional reserves that are less certain to be recovered than proved reserves but, together with proved reserves, are as likely as not to be recovered.
proved developed reserves Reserves that are expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.
proved properties Properties with proved reserves.
proved reserves Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
proved undeveloped reserves or PUD reserves Proved undeveloped reserves or PUD reserves are those reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.
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PUD reserves conversion rate The volume of PUD reserves transferred to proved developed over total volume of PUD reserves as of the prior year end.
reserves Estimated remaining quantities of crude oil, natural gas and related substances anticipated to be economically producible as of a given date by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production.
reservoir An underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
resource play Refers to regionally distributed oil and natural gas accumulation as opposed to conventional plays which are more limited in areal extent. Resource plays are characterized by continuous, aerially extensive hydrocarbon accumulations in tight sand, shale and coal reservoirs.
royalty An interest in an oil and gas lease that gives the mineral owner the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling, completing or operating the wells on the leased acreage. Royalties may be either landowner's royalties, which are reserved by the owner of the minerals at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
seismic data An exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of a subsurface rock formation. 2-D seismic provides two-dimensional information and 3-D seismic provides three-dimensional views.
undeveloped reserves Reserves of any category that are expected to be recovered from new wells or from existing wells where a relatively major expenditure is required for recompletion.
working interest An interest in an oil and gas lease that gives the owner the right to drill, produce and conduct operating activities on the leased acreage and receive a share of any production, subject to all royalties, other burdens and to all capital costs and operating expenses.
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FORM 10-K
ANNUAL REPORT 2020
PART I
ITEMS 1 and 2. BUSINESS AND PROPERTIES
Nature of Business
QEP Resources, Inc. (QEP or the Company) is an independent crude oil and natural gas exploration and production company 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.
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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.
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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.
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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:
| December 31, 2020 | December 31, 2019 | ||||||||||||||||||||||||||||||||||||||||||||||
| Oil and condensate | Gas(1) | NGL | Total(1) | Oil and condensate | Gas(1) | NGL | Total(1) | ||||||||||||||||||||||||||||||||||||||||
| (MMbbl) | (Bcf) | (MMbbl) | (MMboe)(2) | (MMbbl) | (Bcf) | (MMbbl) | (MMboe)(2) | ||||||||||||||||||||||||||||||||||||||||
| Proved developed reserves | 101.2 | 185.0 | 32.0 | 164.0 | 117.5 | 217.0 | 36.7 | 190.4 | |||||||||||||||||||||||||||||||||||||||
| Proved undeveloped reserves | 136.7 | 183.3 | 32.1 | 199.4 | 137.4 | 156.3 | 28.5 | 191.9 | |||||||||||||||||||||||||||||||||||||||
| Total proved reserves | 237.9 | 368.3 | 64.1 | 363.4 | 254.9 | 373.3 | 65.2 | 382.3 | |||||||||||||||||||||||||||||||||||||||
____________________________
(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:
| Year Ended December 31, | Year End Reserves (MMboe) | Oil and condensate, Gas and NGL Production(2)(3) (MMboe) | Reserve Life Index(1)(2)(3) (Years) | |||||||||||||||||
| 2018 | 658.2 | 49.6 | 13.3 | |||||||||||||||||
| 2019 | 382.3 | 31.9 | 12.0 | |||||||||||||||||
| 2020 | 363.4 | 30.3 | 12.0 | |||||||||||||||||
____________________________
(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.
12
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:
| December 31, | |||||||||||||||||||||||
| 2020 | 2019 | ||||||||||||||||||||||
| Northern Region | (MMboe) | (% of total) | (MMboe) | (% of total) | |||||||||||||||||||
| Williston Basin | 80.2 | 22 | % | 116.0 | 30 | % | |||||||||||||||||
| Other Northern | — | — | % | — | — | % | |||||||||||||||||
| Southern Region | |||||||||||||||||||||||
| Permian Basin | 283.2 | 78 | % | 266.3 | 70 | % | |||||||||||||||||
| Other Southern | — | — | % | — | — | % | |||||||||||||||||
| Total proved reserves | 363.4 | 100 | % | 382.3 | 100 | % | |||||||||||||||||
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:
| 2020 | |||||
| (MMboe) | |||||
| Proved undeveloped reserves at January 1, | 191.9 | ||||
| Transferred to proved developed reserves | (30.1) | ||||
| Revisions to previous estimates | 37.6 | ||||
| Proved undeveloped reserves at December 31, | 199.4 | ||||
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.
13
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:
| Planned Transfers to Proved Developed Reserves in 2020 as of December 31, 2019 (PUD conversions) | Actual Transfers to Proved Developed Reserves in 2020 (PUD conversions) | Difference | |||||||||||||||
| (MMboe) | |||||||||||||||||
| Northern Region | |||||||||||||||||
| Williston Basin | 8.5 | 0.6 | (7.9) | ||||||||||||||
| Other Northern | — | — | — | ||||||||||||||
| Southern Region | |||||||||||||||||
| Permian Basin | 29.5 | 29.5 | — | ||||||||||||||
| Other Southern | — | — | — | ||||||||||||||
| Total | 38.0 | 30.1 | (7.9) | ||||||||||||||
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:
| 2020 | |||||
| (MMboe) | |||||
| Revisions due to: | |||||
| Changes in year-end prices (price impact to January 1, 2019 balance) | (2.6) | ||||
| Positive performance | 1.9 | ||||
| Change in development plans | 58.8 | ||||
| Removal due to five year SEC rule | (16.9) | ||||
| Other | (3.6) | ||||
| Total revisions to prior estimates | 37.6 | ||||
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.
14
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.
15
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.
16
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:
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| Production volumes | |||||||||||||||||
| Oil and condensate (Mbbl) | 19,721.6 | 21,558.3 | 23,932.0 | ||||||||||||||
| Gas (Bcf) | 32.5 | 33.1 | 139.6 | ||||||||||||||
| NGL (Mbbl) | 5,185.1 | 5,139.0 | 4,661.4 | ||||||||||||||
| Total equivalent production (Mboe) | 30,324.9 | 32,210.3 | 51,857.9 | ||||||||||||||
Average field-level price (1) | |||||||||||||||||
| Oil (per bbl) | $ | 35.08 | $ | 52.54 | $ | 59.43 | |||||||||||
| Gas (per Mcf) | $ | 1.22 | $ | 1.58 | $ | 2.82 | |||||||||||
| NGL (per bbl) | $ | 8.82 | $ | 11.15 | $ | 23.79 | |||||||||||
| Production costs (per Boe) | |||||||||||||||||
| Lease operating expense | $ | 4.67 | $ | 5.68 | $ | 5.07 | |||||||||||
Adjusted transportation and processing costs(2) | 3.85 | 3.22 | 3.33 | ||||||||||||||
| Production and property taxes | 1.91 | 2.98 | 2.52 | ||||||||||||||
| Total production costs | $ | 10.43 | $ | 11.88 | $ | 10.92 | |||||||||||
____________________________
(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:
| 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) | ||||||||||||||||||||||||
17
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) | ||||||||||||||||||||||||
18
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.
19
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.
20
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 | |||||||||||||||||||||||||||||
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(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 | |||||||||
21
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 | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
22
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 | — | |||||||||||||||||||||||||||||||||||||||||||||||