NOTES ACCOMPANYING THE CONSOLIDATED FINANCIAL STATEMENTS
Note 1 – Summary of Significant Accounting Policies
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). In January 2019, the Company sold its Haynesville/Cotton Valley assets in Louisiana and in February 2019, the Company announced the termination of the purchase and sale agreement related to its Williston Basin assets in North Dakota. In 2019, QEP's Board of Directors commenced and completed a comprehensive review of strategic alternatives to maximize shareholder value and determined that the best alternative for QEP's shareholders was to move forward as an independent company. Unless otherwise specified or the context otherwise requires, all references to "QEP" or the "Company" are to QEP Resources, Inc. and its subsidiaries on a consolidated basis. QEP's corporate headquarters are located in Denver, Colorado and shares of QEP's common stock trade on the New York Stock Exchange (NYSE) under the ticker symbol "QEP".
Principles of Consolidation
The Consolidated Financial Statements contain the accounts of QEP and its majority-owned or controlled subsidiaries. The Consolidated Financial Statements were prepared in accordance with GAAP and with the instructions for annual reports on Form 10-K and Regulation S-X. All significant intercompany accounts and transactions have been eliminated in consolidation.
All dollar and share amounts in this Annual Report on Form 10-K are in millions, except per share information and where otherwise noted.
Business Segments
QEP conducted a segment analysis in accordance with Accounting Standards Codification (ASC) Topic 280, Segment Reporting, and determined that QEP has one reportable segment.
Reclassifications
Certain prior period balances on the Consolidated Statements of Cash Flows have been reclassified to conform to the current year presentation. Such reclassifications had no effect on the Company's net income (loss), earnings (loss) per share or retained earnings previously reported.
Use of Estimates
The preparation of the Consolidated Financial Statements and Notes in conformity with GAAP requires that management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent assets and liabilities. A significant item that requires management's estimates and assumptions is the estimate of proved oil and condensate, gas and NGL reserves, which are used in the calculation of depreciation, depletion and amortization rates of its oil and gas properties, impairment of proved properties and asset retirement obligations. Changes in estimated quantities of its reserves could impact the Company's reported financial results as well as disclosures regarding the quantities and value of proved oil and gas reserves. Other items subject to estimates and assumptions include the carrying amount of property, plant and equipment, assigning fair value and allocating purchase price in connection with business combinations, valuation allowances for receivables, income taxes, valuation of derivatives instruments, contingencies, accrued liabilities, accrued revenue and related receivables and obligations related to employee benefits, among others. Although management believes these estimates are reasonable, actual results could differ from these estimates.
Risks and Uncertainties
The Company's revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil, gas and NGL, which are affected by many factors outside of QEP's control, including changes in market supply and demand. Changes in market supply and demand are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials, export capacity, strength of the U.S. dollar and other factors. Field-level prices received for QEP's oil and gas production have historically been volatile and may be subject to significant fluctuations in the future. The Company's derivative contracts serve to mitigate in part the effect of this price volatility on the Company's cash flows, and the Company has derivative contracts in place for a portion of its expected future oil and condensate production. Refer to Note 7 – Derivative Contracts for the Company's open oil commodity derivative contracts.
Revenue Recognition
QEP recognizes revenue from the sale of oil and condensate, gas and NGL in the period that the performance obligations are satisfied. QEP's performance obligations are satisfied when the customer obtains control of product, when QEP has no further obligations to perform related to the sale, when the transaction price has been determined and when collectability is probable. The sale of oil and condensate, gas and NGL are made under contracts with customers, which typically include consideration that is based on pricing tied to local indices and volumes delivered in the current month. Reported revenues include estimates for the two most recent months using published commodity price indices and volumes supplied by field operators. Performance obligations under our contracts with customers are typically satisfied at a point in time through monthly delivery of oil and condensate, gas and/or NGL. Our contracts with customers typically require payment for oil and condensate, gas and NGL sales within 30 days following the calendar month of delivery.
QEP's oil and condensate is typically sold at specific delivery points under contract terms that are common in the industry. QEP's gas and NGL are also sold under contract types that are common in the industry; however, under these contracts, the gas and its components, including NGL, may be sold to a single purchaser or the residue gas and NGL may be sold to separate purchasers. Regardless of the contract type, the terms of these contracts compensate QEP for the value of the residue gas and NGL constituent components at market prices for each product. QEP also purchases and resells oil and gas primarily to mitigate credit risk related to third party purchasers, to fulfill volume commitments when production does not fulfill contractual commitments and to capture additional margin from subsequent sales of third party purchases. QEP recognizes revenue from these resale activities in the period that the performance obligations are satisfied.
Cash, Cash Equivalents and Restricted Cash
Cash equivalents consist principally of highly liquid investments in securities with original maturities of three months or less made through commercial bank accounts that result in available funds the next business day. Restricted cash are funds that are legally or contractually reserved for a specific purpose and therefore not available for immediate or general business use.
The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheets to the amounts shown in the Consolidated Statements of Cash Flows:
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December 31,
|
|
2019
|
|
2018
|
|
(in millions)
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Cash and cash equivalents
|
$
|
166.3
|
|
|
$
|
—
|
|
Restricted cash(1)
|
30.1
|
|
|
28.1
|
|
Total cash, cash equivalents and restricted cash shown in the Consolidated Statements of Cash Flows
|
$
|
196.4
|
|
|
$
|
28.1
|
|
_______________________
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|
(1)
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As of December 31, 2019 and 2018, the restricted cash balance related to cash deposited into an escrow account for a title dispute between outside parties in the Williston Basin, and the restricted cash balance is recorded within "Other noncurrent assets" on the Consolidated Balance Sheets.
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Supplemental cash flow information is shown in the table below:
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Year Ended December 31,
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2019
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|
2018
|
|
2017
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Supplemental Disclosures:
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(in millions)
|
Cash paid for interest, net of capitalized interest
|
$
|
126.9
|
|
|
$
|
136.9
|
|
|
$
|
134.9
|
|
Cash paid (refund received) for income taxes, net
|
$
|
(66.7
|
)
|
|
$
|
0.8
|
|
|
$
|
(0.3
|
)
|
Cash paid for amounts included in the measurement of lease liabilities
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$
|
25.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Non-cash Operating Activities:
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|
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Right-of-use assets obtained in exchange for operating lease obligations
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16.6
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|
|
—
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|
|
—
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|
Non-cash Investing Activities:
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|
|
|
|
|
Change in capital expenditure accrual balance
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$
|
8.8
|
|
|
$
|
(57.4
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)
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|
$
|
60.2
|
|
Accounts Receivable
Accounts receivable consists mainly of receivables from oil and gas purchasers and joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Generally, the Company's oil and gas receivables are collected and bad debts are minimal. However, if commodity prices remain low for an extended period of time, the Company could incur increased levels of bad debt expense. Bad debt expense associated with accounts receivable for the year ended December 31, 2019 and 2018 was $0.3 million and $0.6 million, respectively. Recovery of bad debt associated with accounts receivable for the year ended December 31, 2017 was $1.0 million. Bad debt expense or recovery is included in "General and administrative" expense on the Consolidated Statements of Operations. The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability. The allowance for bad debt expenses was $1.6 million at December 31, 2019, and $1.3 million at December 31, 2018.
Property, Plant and Equipment
Property, plant and equipment balances are stated at historical cost. Material and supplies inventories are valued at the lower of cost or net realizable value. Maintenance and repair costs are expensed as incurred. Significant accounting policies for our property, plant and equipment are as follows:
Successful Efforts Accounting for Oil and Gas Operations
The Company follows the successful efforts method of accounting for oil and gas property acquisitions, exploration, development and production activities. Under this method, the acquisition costs of proved and unproved properties, successful exploratory wells and development wells are capitalized. Other exploration costs, including geological and geophysical costs, delay rentals and administrative costs associated with unproved property and unsuccessful exploratory well costs are expensed. Costs to operate and maintain wells and field equipment are expensed as incurred. A gain or loss is generally recognized only when an entire field is sold or abandoned, or if the unit-of-production depreciation, depletion and amortization rate would be significantly affected. Capitalized costs of unproved properties are reclassified to proved property when related proved reserves are determined or charged against the impairment allowance when abandoned.
Depreciation, Depletion and Amortization (DD&A)
Capitalized proved leasehold costs are depleted on a field-by-field basis using the unit-of-production method and the estimated total proved oil and gas reserves. Capitalized costs of exploratory wells that have found proved oil and gas reserves and capitalized development costs are depreciated using the unit-of-production method based on estimated proved developed reserves for a successful effort field. The Company capitalizes an estimate of the fair value of future abandonment costs.
DD&A for the Company's remaining properties is generally based upon rates that will systematically charge the costs of assets against income over the estimated useful lives of those assets using the straight-line method. The estimated useful lives of those assets depreciated under the straight-line basis generally range as follows:
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Buildings
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10 to 30 years
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Leasehold improvements
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3 to 10 years
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Service, transportation and field service equipment
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3 to 7 years
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Furniture and office equipment
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3 to 7 years
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Impairment of Long-Lived Assets
Proved oil and gas properties are evaluated on a field-by-field basis for potential impairment. Other properties are evaluated on a specific asset basis or in groups of similar assets, as applicable. Impairment is indicated when a triggering event occurs and/or the sum of the estimated undiscounted future net cash flows of an evaluated asset is less than the asset's carrying value. Triggering events could include, but are not limited to, a reduction of oil and condensate, gas and NGL reserves caused by mechanical problems, faster-than-expected decline of production, lease ownership issues, potential disposition of assets and declines in oil, gas and NGL prices. If impairment is indicated, fair value is estimated using a discounted cash flow approach. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including estimates of future production, future commodity prices, future operating costs and future development costs. The signing of a purchase and sale agreement could also cause the Company to recognize an impairment of proved properties. For assets subject to a purchase and sale agreement, the terms of the purchase and sale agreement are used as an indicator of fair value. If a range is estimated for the amount of possible future cash flows, the fair value of property is measured utilizing a probability-weighted approach in which the likelihood of possible outcomes is taken into consideration. Cash flow estimates relating to future cash flows from probable and possible reserves are reduced by additional risk-weighting factors.
Unproved properties are evaluated on a specific asset basis or in groups of similar assets, as applicable. The Company performs periodic assessments of unproved oil and gas properties for impairment and recognizes a loss at the time of impairment. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current development and exploration drilling plans, favorable or unfavorable exploration activity on adjacent leaseholds, in-house geologists' evaluation of the lease, future reserve cash flows and the remaining lease term.
During the year ended December 31, 2019, QEP recorded impairment charges of $5.0 million related to an office building lease.
During the year ended December 31, 2018, QEP recorded impairment charges of $1,560.9 million, of which $1,559.3 million related to proved and unproved properties impairment as a result of signing purchase and sale agreements for the divestitures of the Williston Basin and Uinta Basin assets. The Williston Basin assets were impaired in the fourth quarter utilizing a probability-weighted assets held and use model, and the Uinta Basin assets were impaired in the second quarter utilizing an assets held for sale model.
During the year ended December 31, 2017, QEP recorded impairment charges of $78.9 million, of which $38.1 million, primarily in the Other Northern area, was related to proved properties due to lower future gas prices, $29.0 million was primarily related to unproved leasehold acreage in the Central Basin Platform (refer to Note 4 – Capitalized Exploratory Well Costs for more information), $6.5 million was related to the impairment of an underground gas storage facility and $5.3 million was related to the impairment of goodwill.
Asset Retirement Obligations (ARO)
QEP is obligated to fund the costs of disposing of long-lived assets upon their abandonment. The Company's ARO liability applies primarily to abandonment costs associated with oil and gas wells and certain other properties. ARO associated with the retirement of tangible long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the tangible asset, including the asset retirement costs, is depreciated over the useful life of the asset. The ARO liability is recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company's credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of ARO change, an adjustment is recorded to both the ARO liability and the long-lived asset. Revisions to estimated ARO can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment. Refer to Note 5 – Asset Retirement Obligations for more information.
Goodwill
Goodwill represents the excess of the amount paid over the fair value of assets acquired in a business combination and is not subject to amortization. QEP performs an annual goodwill impairment test by comparing the fair value of a reporting unit with its carry amount, with an impairment charge being recognized for the amount by which the carrying amount exceeds the reporting unit's fair value. QEP determines the fair value of its reporting units in which goodwill is allocated using the income approach in which the fair value is estimated based on the value of expected future cash flows. Key assumptions used in the cash flow model include estimated quantities of oil and condensate, gas and NGL reserves, including both proved reserves and risk-adjusted unproved reserves, and including probable and possible reserves; estimates of market prices considering forward commodity price curves as of the measurement date; estimates of revenue and operating costs over a multi-year period; and estimates of capital costs.
During the year ended December 31, 2017 QEP recorded $5.3 million of goodwill. In addition, during the year ended December 31, 2017, QEP tested goodwill for impairment, which resulted in a full write-down of the $5.3 million.
Litigation and Other Contingencies
The Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. In each reporting period, the Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its Consolidated Financial Statements. The amount of ultimate loss may differ from these estimates. In accordance with ASC 450, Contingencies, an accrual is recorded for a material loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. Refer to Note 11 – Commitments and Contingencies for more information.
QEP accrues material losses associated with environmental obligations when such losses are probable and can be reasonably estimated. Accruals for estimated environmental losses are recognized no later than at the time the remediation feasibility study, or the evaluation of response options, is complete. These accruals are adjusted as more information becomes available or as circumstances change. Future environmental expenditures are not discounted to their present value. Recoveries of environmental costs from other parties are recorded separately as assets at their undiscounted value when receipt of such recoveries is probable.
Derivative Contracts
QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. QEP uses commodity derivative instruments, typically fixed-price swaps, basis swaps and costless collars to realize a known price or price range for a specific volume of production delivered into a regional sales point. QEP's commodity derivative instruments do not require the physical delivery of oil or gas between the parties at settlement. All transactions are settled in cash with one party paying the other for the net difference in prices, multiplied by the contract volume, for the settlement period. QEP does not engage in speculative hedging transactions, nor does it buy and sell energy contracts with the objective of generating profits on short-term differences in price. Additionally, QEP does not currently have any commodity derivative transactions that have margin requirements or collateral provisions that would require payments prior to the scheduled settlement dates.
These derivative contracts are recorded in "Realized and unrealized gains (losses) on derivative contracts" on the Consolidated Statements of Operations in the month of settlement and are also marked-to-market monthly. Refer to Note 7 – Derivative Contracts for more information.
Credit Risk
Management believes that its credit review procedures, loss reserves, cash deposits and investments, and collection procedures have adequately provided for usual and customary credit-related losses. Exposure to credit risk may be affected by extended periods of low commodity prices, as well as the concentration of customers in certain regions due to changes in economic or other conditions. Customers include commercial and industrial enterprises and financial institutions that may react differently to changing conditions.
The Company utilizes various processes to monitor and evaluate its credit risk exposure, which include closely monitoring current market conditions and counterparty credit fundamentals, including public credit ratings, where available. Credit exposure is controlled through credit approvals and limits based on counterparty credit fundamentals. Credit exposure is aggregated across all lines of business, including derivatives, physical exposure and short-term cash investments. To further manage the level of credit risk, the Company requests credit support and, in some cases, requests parental guarantees, letters of credit or prepayment from companies with perceived higher credit risk. Loss reserves are periodically reviewed for adequacy and, if needed, are established on a specific case basis. The Company also has master-netting agreements with some counterparties that allow the offsetting of receivables and payables in a default situation.
The Company enters into International Swap Dealers Association Master Agreements (ISDA Agreements) with each of its derivative counterparties prior to executing derivative contracts. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set-off upon the occurrence of defined acts of default by either the Company or counterparty to a derivative contract. The Company routinely monitors and manages its exposure to counterparty risk related to derivative contracts by requiring specific minimum credit standards for all counterparties, actively monitoring counterparties public credit ratings, and avoiding concentration of credit exposure by transacting with multiple counterparties. The Company's commodity derivative contract counterparties are typically financial institutions and energy trading firms with investment-grade credit ratings.
The Company's five largest customers accounted for 66%, 49%, and 59% of QEP's revenues for the years ended December 31, 2019, 2018 and 2017, respectively. The following table presents the percentages by customer that accounted for 10% or more of QEP's total revenues.
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|
|
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
|
%
|
|
|
|
Year Ended December 31, 2017
|
|
|
Shell Trading Company
|
|
14
|
%
|
Occidental Energy Marketing
|
|
13
|
%
|
Andeavor Logistics LP
|
|
13
|
%
|
BP Energy Company
|
|
10
|
%
|
Plains Marketing LP
|
|
10
|
%
|
Income Taxes
The amount of income taxes recorded by QEP requires interpretations of complex rules and regulations of various tax jurisdictions throughout the United States. QEP has recognized deferred tax assets and liabilities for temporary differences, operating losses and tax credit carryforwards. Deferred income taxes are provided for the temporary differences arising between the book and tax carrying amounts of assets and liabilities. These differences create taxable or tax-deductible amounts for future periods.
ASC 740, Income Taxes, specifies the accounting for uncertainty in income taxes by prescribing a minimum recognition threshold for a tax position to be reflected in the financial statements. If recognized, the tax benefit is measured as the largest amount of tax benefit that is more-likely-than-not to be realized upon ultimate settlement. Management has considered the amounts and the probabilities of the outcomes that could be realized upon ultimate settlement and believes that it is more-likely-than-not that the Company's recorded income tax benefits will be fully realized, or recognizes a valuation allowance against deferred tax assets in cases where we do not forecast sufficient future income to recognize the deferred tax asset. All federal income tax returns prior to 2019 have been examined by the Internal Revenue Service and are closed or have been pre-reviewed before filing. Income tax returns for 2019 have not yet been filed. Most state tax returns for 2016 and subsequent years remain subject to examination. Should the Company utilize any of its state loss carryforwards, their carryforward losses would be subject to examination.
The benefits of uncertain tax positions taken or expected to be taken on income tax returns is recognized in the consolidated financial statements at the largest amount that is more-likely-than-not to be sustained upon examination by the relevant taxing authorities.
In December 2017, the Tax Cuts and Jobs Act (H.R.1) (Tax Legislation) was signed into law, which resulted in significant changes to U.S. federal income tax law. QEP expects that these changes will positively impact QEP's future after-tax earnings in the U.S., primarily due to the lower federal statutory tax rate of 21% compared to 35%. The impact of the Tax Legislation may differ from the statements above due to, among other things, changes in interpretations and assumptions the Company has made and actions the Company may take as a result of the Tax Legislation. Additionally, guidance issued by the relevant regulatory authorities regarding the Tax Legislation may materially impact QEP's financial statements. As additional guidance to the Tax Legislation is published in the form of Treasury Regulations and other IRS communications, the Company will monitor, assess, and determine the impact of these communications on the Company's consolidated financial statements and operations.
Treasury Stock
We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders' equity in the Consolidated Balance Sheets. QEP acquires treasury stock from stock forfeitures and withholdings and uses the acquired treasury stock for stock option exercises and certain stock grants to employees. Refer to Note 12 – Share-Based Compensation for more information.
Earnings (Loss) Per Share
Basic earnings (loss) per share (EPS) are computed by dividing net income (loss) by the weighted-average number of common shares outstanding during the reporting period. Diluted EPS includes the potential increase in the number of outstanding shares that could result from the exercise of in-the-money stock options. QEP's unvested restricted share awards are included in weighted-average basic common shares outstanding because, once the shares are granted, the restricted share awards are considered issued and outstanding, the historical forfeiture rate is minimal and the restricted share awards are eligible to receive dividends.
Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings (loss) per share pursuant to the two-class method. The Company's unvested restricted share awards contain non-forfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company's unvested restricted share awards do not have a contractual obligation to share in losses of the Company. The Company's unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings (loss) per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings (loss) per common share. For the years ended December 31, 2019, 2018 and 2017, there were no anti-dilutive shares.
The following is a reconciliation of the components of basic and diluted shares used in the EPS calculation:
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|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2019
|
|
2018
|
|
2017
|
|
(in millions)
|
Weighted-average basic common shares outstanding
|
237.7
|
|
|
237.9
|
|
|
240.6
|
|
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan
|
—
|
|
|
—
|
|
|
—
|
|
Average diluted common shares outstanding
|
237.7
|
|
|
237.9
|
|
|
240.6
|
|
Share-Based Compensation
QEP issues restricted share awards and restricted share units to certain officers, employees and non-employee directors under its 2018 Long-Term Incentive Plan (LTIP). QEP historically issued stock options. QEP used the Black-Scholes-Merton mathematical model to estimate the fair value of stock options for accounting purposes. The grant date fair value for restricted share awards is determined based on the closing bid price of the Company's common stock on the grant date. Share-based compensation cost for restricted share units is equal to its fair value as of the end of the period and is classified as a liability. QEP uses an accelerated method in recognizing share-based compensation costs for stock options and restricted share awards with graded-vesting periods. Stock options held by employees generally vest in three equal, annual installments and primarily have a term of seven years. Restricted share awards and restricted share units vest in equal installments over a specified number of years after the grant date with the majority vesting in three years. Non-vested restricted share awards have voting and dividend rights; however, sale or transfer is restricted. Employees may elect to defer their grants of restricted share awards and these deferred awards are designated as restricted share units. Restricted share units vest over a three-year period and are deferred into the Company's nonqualified, unfunded deferred compensation plan at the time of vesting. The Company also awards performance share units under its Cash Incentive Plan (CIP) that are generally paid out in cash depending upon the Company's total shareholder return compared to a group of its peers over a three-year period. Share-based compensation cost for the performance share units is equal to its fair value as of the end of the period and is classified as a liability. Refer to Note 12 – Share-Based Compensation for more information.
Pension and Other Postretirement Benefits
QEP maintains closed, defined-benefit pension and other postretirement benefit plans, including both a qualified and a supplemental plan. QEP also provides certain health care and life insurance benefits for certain retired QEP employees. Determination of the benefit obligations for QEP's defined-benefit pension and other postretirement benefit plans impacts the recorded amounts for such obligations on the Consolidated Balance Sheets and the amount of benefit expense recorded to the Consolidated Statements of Operations.
QEP measures pension plan assets at fair value. Defined-benefit plan obligations and costs are actuarially determined, incorporating the use of various assumptions. Critical assumptions for pension and other postretirement benefit plans include the discount rate, the expected rate of return on plan assets (for funded pension plans) and the rate of future compensation increases. Other assumptions involve demographic factors such as retirement, mortality and turnover. QEP evaluates and updates its actuarial assumptions at least annually. QEP recognizes a pension curtailment immediately when there is a significant reduction in, or an elimination of, defined-benefit accruals for present employees' future services. Refer to Note 13 – Employee Benefits for more information.
Comprehensive Income (Loss)
Comprehensive income (loss) is the sum of net income (loss) as reported in the Consolidated Statements of Operations and changes in the components of other comprehensive income (loss). Other comprehensive income (loss) includes certain items that are recorded directly to equity and classified as accumulated other comprehensive income (AOCI), which includes changes in the underfunded portion of the Company's defined-benefit pension and other postretirement benefits plans and changes in deferred income taxes on such amounts. These transactions do not represent the culmination of the earnings process but result from periodically adjusting historical balances to fair value.
Recent Accounting Developments
In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2016-02, Leases (Topic 842), which requires lessees to recognize the lease assets and lease liabilities classified as operating leases on the balance sheet and disclose key quantitative and qualitative information about leasing arrangements. The FASB subsequently issued various ASUs which provided additional implementation guidance. The Company adopted ASU 2016-02 on January 1, 2019 using the modified retrospective approach and elected to not adjust periods prior to January 1, 2019. The Company elected the package of practical expedients permitted under the transition guidance within the new standard, which, among other things, allowed the carry forward of the historical lease classification, including accounting treatment for land easements. This standard does not apply to QEP's leases that provide the right to explore for minerals, oil or natural gas resources. The adoption of this guidance resulted in the recognition of net operating lease right-of-use assets and operating lease liabilities on QEP's Consolidated Balance Sheets. These leases primarily relate to office buildings, compressors and generators. This guidance did not have a significant impact on the Consolidated Statements of Operations or the Consolidated Statements of Cash Flows. Refer to Note 8 – Leases for more information.
In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes, which simplifies the accounting for income taxes. The amendment will be effective for reporting periods beginning after December 15, 2020, and early adoption is permitted. The Company is currently assessing the impact of the ASU on the Company's Consolidated Financial Statements.
Note 2 – Revenue
Revenue Recognition
QEP recognizes revenue from the sale of oil and condensate, gas and NGL in the period that the performance obligations are satisfied. QEP's performance obligations are satisfied when the customer obtains control of product, when QEP has no further obligations to perform related to the sale, when the transaction price has been determined and when collectability is probable. The sale of oil and condensate, gas and NGL are made under contracts with customers, which typically include consideration that is based on pricing tied to local indices and volumes delivered in the current month. Reported revenues include estimates for the two most recent months using published commodity price indices and volumes supplied by field operators. Performance obligations under our contracts with customers are typically satisfied at a point in time through monthly delivery of oil and condensate, gas and/or NGL. Our contracts with customers typically require payment for oil and condensate, gas and NGL sales within 30 days following the calendar month of delivery.
QEP's oil and condensate is typically sold at specific delivery points under contract terms that are common in the industry. QEP's gas and NGL are also sold under contract types that are common in the industry; however, under these contracts, the gas and its components, including NGL, may be sold to a single purchaser or the residue gas and NGL may be sold to separate purchasers. Regardless of the contract type, the terms of these contracts compensate QEP for the value of the residue gas and NGL constituent components at market prices for each product. QEP also purchases and resells oil and gas primarily to mitigate credit risk related to third party purchasers, to fulfill volume commitments when production does not fulfill contractual commitments and to capture additional margin from subsequent sales of third party purchases. QEP recognizes revenue from these resale activities in the period that the performance obligations are satisfied.
The following tables present QEP's revenues that are disaggregated by revenue source and by geographic area. Transportation and processing costs in the following tables are not all of the transportation and processing costs that the Company incurs, only the expenses that are netted against revenues pursuant to ASC Topic 606.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate sales
|
|
Gas sales
|
|
NGL sales
|
|
Transportation and processing costs included in revenue
|
|
Oil and condensate, gas and NGL sales, as reported
|
|
(in millions)
|
|
Year Ended December 31, 2019
|
Northern Region
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
$
|
420.8
|
|
|
$
|
33.1
|
|
|
$
|
19.4
|
|
|
$
|
(34.4
|
)
|
|
$
|
438.9
|
|
Other Northern
|
1.1
|
|
|
0.4
|
|
|
0.1
|
|
|
—
|
|
|
1.6
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
710.6
|
|
|
12.8
|
|
|
37.8
|
|
|
(20.5
|
)
|
|
740.7
|
|
Other Southern(1)
|
0.1
|
|
|
6.1
|
|
|
—
|
|
|
—
|
|
|
6.2
|
|
Total oil and condensate, gas and NGL sales
|
$
|
1,132.6
|
|
|
$
|
52.4
|
|
|
$
|
57.3
|
|
|
$
|
(54.9
|
)
|
|
$
|
1,187.4
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2018
|
Northern Region
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
$
|
707.0
|
|
|
$
|
45.3
|
|
|
$
|
56.5
|
|
|
$
|
(43.1
|
)
|
|
$
|
765.7
|
|
Uinta Basin
|
25.3
|
|
|
25.0
|
|
|
4.8
|
|
|
—
|
|
|
55.1
|
|
Other Northern
|
4.9
|
|
|
2.0
|
|
|
—
|
|
|
—
|
|
|
6.9
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
684.4
|
|
|
17.3
|
|
|
49.5
|
|
|
(11.9
|
)
|
|
739.3
|
|
Haynesville/Cotton Valley
|
1.0
|
|
|
303.1
|
|
|
—
|
|
|
—
|
|
|
304.1
|
|
Other Southern
|
(0.2
|
)
|
|
0.4
|
|
|
—
|
|
|
—
|
|
|
0.2
|
|
Total oil and condensate, gas and NGL sales
|
$
|
1,422.4
|
|
|
$
|
393.1
|
|
|
$
|
110.8
|
|
|
$
|
(55.0
|
)
|
|
$
|
1,871.3
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2017(2)
|
Northern Region
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
$
|
586.5
|
|
|
$
|
42.3
|
|
|
$
|
51.5
|
|
|
$
|
—
|
|
|
$
|
680.3
|
|
Pinedale
|
18.0
|
|
|
154.8
|
|
|
31.8
|
|
|
—
|
|
|
204.6
|
|
Uinta Basin
|
29.6
|
|
|
50.0
|
|
|
5.9
|
|
|
—
|
|
|
85.5
|
|
Other Northern
|
4.9
|
|
|
16.6
|
|
|
0.3
|
|
|
—
|
|
|
21.8
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
298.8
|
|
|
15.5
|
|
|
22.0
|
|
|
—
|
|
|
336.3
|
|
Haynesville/Cotton Valley
|
1.2
|
|
|
214.4
|
|
|
0.4
|
|
|
—
|
|
|
216.0
|
|
Other Southern
|
0.4
|
|
|
0.4
|
|
|
—
|
|
|
—
|
|
|
0.8
|
|
Total oil and condensate, gas and NGL sales
|
$
|
939.4
|
|
|
$
|
494.0
|
|
|
$
|
111.9
|
|
|
$
|
—
|
|
|
$
|
1,545.3
|
|
_______________________
|
|
(1)
|
For the year ended December 31, 2019, $5.9 million of revenues associated with Haynesville/Cotton Valley have been included in Other Southern.
|
|
|
(2)
|
Prior period amounts have not been adjusted under the modified retrospective method under ASC Topic 606.
|
Note 3 – Acquisitions and Divestitures
Acquisitions
2017 Permian Basin Acquisition
In the fourth quarter of 2017, QEP acquired additional oil and gas properties in the Permian Basin for an aggregate purchase price of $721.0 million (2017 Permian Basin Acquisition). The 2017 Permian Basin Acquisition consisted of approximately 15,100 acres, mainly in Martin County, Texas, which were held by production from existing vertical wells at the time of the acquisition. QEP structured the transaction as a like-kind exchange under Section 1031 of the Internal Revenue Service Code and funded the purchase price with the proceeds from the Pinedale Divestiture (defined below). The 2017 Permian Basin Acquisition meets the definition of an asset acquisition because substantially all of the total fair value acquired relates to undeveloped leaseholds which do not have outputs. During the year ended December 31, 2018, QEP closed $49.1 million of acquisitions from various entities that owned additional oil and gas interests in certain properties included in the 2017 Permian Basin Acquisition on substantially the same terms and conditions as the 2017 Permian Basin Acquisition.
Other Acquisitions
During the years ended December 31, 2019 and 2018, QEP acquired various oil and gas properties, which primarily included proved leasehold acreage in the Permian Basin for an aggregate purchase price of $3.5 million and $16.5 million, respectively, subject to post-closing purchase price adjustments.
In addition to the 2017 Permian Basin Acquisition, QEP acquired various oil and gas properties in 2017, which primarily included undeveloped leasehold acreage, producing wells and additional surface acreage in the Permian Basin, for an aggregate purchase price of $94.5 million. In conjunction with the acquisitions, the Company recorded $5.3 million of goodwill, which was subsequently impaired.
Divestitures
In February 2018, QEP's Board of Directors (Board) unanimously approved certain strategic and financial initiatives including plans to market its assets in the Williston Basin, the Uinta Basin and Haynesville/Cotton Valley and focus its activities in the Permian Basin. The Company subsequently sold its Uinta Basin assets in September 2018 and sold its Haynesville/Cotton Valley assets in January 2019. In addition, the Company entered into a purchase and sale agreement for its Williston Basin assets in November 2018. However, in February 2019, the Company agreed with the buyer to terminate the purchase and sale agreement (Terminated Williston Basin Divestiture).
Haynesville/Cotton Valley Divestiture
In November 2018, the Company's wholly owned subsidiaries, QEP Energy Company, QEP Marketing Company, and QEP Oil & Gas Company, entered into a definitive agreement to sell their assets in Haynesville/Cotton Valley for a purchase price of $735.0 million, subject to purchase price adjustments, including adjustments for certain title and environmental defects asserted prior to the closing (Haynesville Divestiture). In addition, $32.2 million was placed in escrow due to title defects asserted prior to closing, to be resolved pursuant to the purchase and sale agreement's title dispute resolution procedures. In January 2019, QEP closed the Haynesville Divestiture and during the year ended December 31, 2019 reached final settlement on asserted title defects and received net cash proceeds of $633.9 million. During the years ended December 31, 2019 and 2018, QEP recorded a pre-tax loss, including restructuring costs, of $1.0 million and $3.0 million, respectively, which were recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Consolidated Statements of Operations.
During the year ended December 31, 2019, QEP accounted for revenues and expenses related to Haynesville/Cotton Valley, including the pre-tax loss on sale of $1.0 million as income from continuing operations on the Consolidated Statements of Operations because the Haynesville Divestiture did not cause a strategic shift for the Company and therefore did not qualify as discontinued operations under ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. During the year ended December 31, 2019, QEP recorded net income before income taxes related to the divested Haynesville/Cotton Valley assets, prior to divestiture, of $3.2 million which includes the pre-tax loss on sale of $1.0 million. During the year ended December 31, 2018, QEP recorded net income before income taxes related to the divested Haynesville/Cotton Valley assets of $76.0 million.
Since the transaction was substantially finalized as of December 31, 2018, the assets and liabilities associated with the Haynesville Divestiture were classified as noncurrent assets and liabilities held for sale on the Consolidated Balance Sheets and the notes accompanying the Consolidated Financial Statements. In addition, QEP recorded $1.4 million and $3.0 million of restructuring costs related to this divestiture during the years ended December 31, 2019 and 2018, respectively, included in "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Consolidated Statements of Operations. Refer to Note 9 – Restructuring for more information.
The following table presents the carrying amounts of the major classes of assets and liabilities classified as noncurrent assets and liabilities held for sale on the Consolidated Balance Sheets:
|
|
|
|
|
|
December 31, 2018 (1)
|
|
(in millions)
|
Assets
|
|
Current assets, total
|
$
|
1.2
|
|
Property, Plant and Equipment
|
683.7
|
|
Other noncurrent assets
|
7.8
|
|
Noncurrent assets held for sale
|
$
|
692.7
|
|
Liabilities
|
|
Current liabilities, total
|
$
|
3.4
|
|
Asset retirement obligations, current
|
0.7
|
|
Asset retirement obligations, long-term
|
56.9
|
|
Fair value of derivative contracts, long-term
|
—
|
|
Other long-term liabilities
|
0.3
|
|
Other long-term liabilities held for sale
|
$
|
61.3
|
|
____________________________
|
|
(1)
|
The Haynesville Divestiture closed in January 2019, therefore there are no assets and liabilities held for sale as of December 31, 2019.
|
Terminated Williston Basin Divestiture
In November 2018, the Company's wholly owned subsidiary, QEP Energy Company, entered into a purchase and sale agreement for its assets in the Williston Basin for a purchase price of $1,725.0 million, subject to purchase price adjustments. The purchase price was comprised of $1,650.0 million in cash and contractual rights to receive $75.0 million of the buyer's common stock if certain conditions were met. The transaction was subject to certain conditions, including, but not limited to, approval of buyer's shareholders and regulatory approvals. In February 2019, the Company agreed with the buyer to terminate the purchase and sale agreement. As of December 31, 2018, the Williston Basin assets were classified as held and used in the Company's Consolidated Financial Statements as the assets did not meet the held for sale criteria. As a part of our strategic initiatives, QEP has incurred costs associated with contractual termination benefits, including severance, accelerated vesting of share-based compensation and other expenses. Refer to Note 9 – Restructuring and Note 17 – Subsequent Events for more information.
Uinta Basin Divestiture
In September 2018, QEP sold its natural gas and oil producing properties, undeveloped acreage and related assets located in the Uinta Basin for net cash proceeds of $153.0 million, (Uinta Basin Divestiture). During the year ended December 31, 2018, QEP recorded a pre-tax loss of $12.6 million related to the Uinta Basin Divestiture, which included $5.4 million related to estimated restructuring costs recorded on the Consolidated Statements of Operations within "Net gain (loss) from asset sales, inclusive of restructuring costs". In conjunction with the Uinta Basin Divestiture, QEP recorded $402.8 million of proved and unproved properties impairment during the year ended December 31, 2018. For the year ended December 31, 2019, QEP recorded a pre-tax loss of $0.2 million, due to post-closing purchase price adjustments, which were recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs". Refer to Note 1 – Summary of Significant Accounting Policies and Note 9 – Restructuring for more information.
Pinedale Divestiture
In September 2017, QEP sold its Pinedale assets (Pinedale Divestiture), for net cash proceeds (after purchase price adjustments) of $718.2 million. During the year ended December 31, 2017 QEP recorded a pre-tax gain on sale of $180.4 million, which was recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Consolidated Statements of Operations. For the year ended December 31, 2018, QEP recorded a pre-tax gain on sale of $1.2 million, due to additional post-closing purchase price adjustments.
As part of the purchase and sale agreement, QEP agreed to reimburse the buyer for certain deficiency charges that totaled $9.3 million as of December 31, 2018 and is reported on the Consolidated Balance Sheets within "Accounts payable and accrued expenses". As of December 31, 2019, QEP has no remaining liability related to this commitment.
For the year ended December 31, 2017, QEP recorded net income before income taxes related to Pinedale, prior to the divestiture of $251.0 million, which includes the pre-tax gain on sale of $180.4 million.
Other Divestitures
In addition to the Haynesville and Uinta Basin divestitures, during the year ended December 31, 2019, QEP received net cash proceeds of $45.1 million and recorded a net pre-tax gain on sale of $5.1 million related to the divestiture of properties outside our main operating areas.
In addition to the Uinta Basin Divestiture, during the year ended December 31, 2018, QEP received net cash proceeds of $90.6 million and recorded a net pre-tax gain on sale of $38.5 million related to the divestiture of properties outside our main operating areas.
In addition to the Pinedale Divestiture, during the year ended December 31, 2017, QEP also sold its Central Basin Platform assets (Central Basin Platform Divestiture) and received net cash proceeds of $3.5 million. Refer to Note 4 – Capitalized Exploratory Well Costs for more information. In addition, QEP received net cash proceeds of $85.1 million and recorded a pre-tax gain on sale of $33.1 million, primarily related to the sale of properties in the Other Northern area.
These gains and losses are reported on the Consolidated Statements of Operations within "Net gain (loss) from asset sales, inclusive of restructuring costs".
Note 4 – Capitalized Exploratory Well Costs
Net changes in capitalized exploratory well costs are presented in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalized Exploratory Well Costs
|
|
2019
|
|
2018
|
|
2017
|
|
(in millions)
|
Balance at January 1,
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
14.2
|
|
Additions to capitalized exploratory well costs
|
—
|
|
|
—
|
|
|
10.7
|
|
Reclassifications to proved properties
|
—
|
|
|
—
|
|
|
(3.6
|
)
|
Capitalized exploratory well costs charged to expense
|
—
|
|
|
—
|
|
|
(21.3
|
)
|
Balance at December 31,
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
During the year ended December 31, 2017, QEP's exploratory well activity was related to the Central Basin Platform exploration project in the Permian Basin targeting the Woodford Formation. QEP completed a second exploratory well related to this project in the first half of 2017. During the year ended December 31, 2017, based on the performance of the two exploratory wells that were drilled and the analysis of the ultimate economic feasibility of this exploration project, QEP determined it would no longer pursue the development of the Central Basin Platform exploration project and would seek to monetize the assets. QEP charged $21.3 million of exploratory well costs to exploration expense. In conjunction with the expensing of the exploratory well costs, QEP charged $28.3 million of the associated unproved leasehold acreage in the Central Basin Platform to impairment expense during the year ended December 31, 2017. QEP wrote down the Central Basin Platform assets to their fair market value of $3.6 million and reclassified the assets to proved properties. During the fourth quarter of 2017, QEP closed the Central Basin Platform Divestiture for net cash proceeds of $3.5 million.
Note 5 – Asset Retirement Obligations
QEP records ARO associated with the retirement of tangible, long-lived assets. The Company's ARO liability applies primarily to abandonment costs associated with oil and gas wells and certain other properties. The fair values of such costs are estimated by Company personnel based on abandonment costs of similar assets and depreciated over the life of the related assets. Revisions to the ARO estimates result from changes in expected cash flows or material changes in estimated asset retirement costs. The ARO liability is adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate.
The Consolidated Balance Sheet line items of QEP's ARO liability are presented in the table below:
|
|
|
|
|
|
|
|
|
|
Asset Retirement Obligations
|
|
December 31,
|
|
2019
|
|
2018
|
Balance Sheet line item
|
(in millions)
|
Current:
|
|
|
|
Asset retirement obligations, current liability
|
$
|
6.0
|
|
|
$
|
5.1
|
|
Long-term:
|
|
|
|
Asset retirement obligations
|
94.9
|
|
|
96.9
|
|
Other long-term liabilities held for sale
|
—
|
|
|
57.6
|
|
Total ARO Liability
|
$
|
100.9
|
|
|
$
|
159.6
|
|
The following is a reconciliation of the changes in the Company's ARO for the periods specified below:
|
|
|
|
|
|
|
|
|
|
Asset Retirement Obligations
|
|
2019
|
|
2018
|
|
(in millions)
|
ARO liability at January 1,
|
$
|
159.6
|
|
|
$
|
214.1
|
|
Accretion
|
5.2
|
|
|
6.4
|
|
Additions
|
1.1
|
|
|
4.1
|
|
Revisions
|
(2.2
|
)
|
|
(4.9
|
)
|
Liabilities related to assets sold(1)
|
(60.7
|
)
|
|
(56.8
|
)
|
Liabilities settled
|
(2.1
|
)
|
|
(3.3
|
)
|
ARO liability at December 31,
|
$
|
100.9
|
|
|
$
|
159.6
|
|
___________________________
|
|
(1)
|
Liabilities related to assets sold for the year ended December 31, 2019, includes $57.6 million related to the Haynesville Divestiture. Liabilities related to assets sold for the year ended December 31, 2018, includes $51.0 million related to the Uinta Basin Divestiture. Refer to Note 3 – Acquisitions and Divestitures for more information.
|
Note 6 – Fair Value Measurements
QEP measures and discloses fair values in accordance with the provisions of ASC 820, Fair Value Measurements and Disclosures. This guidance defines fair value in applying GAAP, establishes a framework for measuring fair value and expands disclosures about fair value measurements. ASC 820 also establishes a fair value hierarchy. Level 1 inputs are quoted prices (unadjusted) for identical assets or liabilities in active markets that the Company has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability.
QEP has determined that its commodity derivative instruments are Level 2. The Level 2 fair value of commodity derivative contracts (refer to Note 7 – Derivative Contracts for more information) is based on market prices posted on the respective commodity exchange on the last trading day of the reporting period and industry standard discounted cash flow models. QEP primarily applies the market approach for recurring fair value measurements and maximizes its use of observable inputs and minimizes its use of unobservable inputs. QEP considers bid and ask prices for valuing the majority of its assets and liabilities measured and reported at fair value. In addition to using market data, QEP makes assumptions in valuing its assets and liabilities, including assumptions about risk and the risks inherent in the inputs to the valuation technique. The Company's policy is to recognize significant transfers between levels at the end of the reporting period.
Certain of the Company's commodity derivative instruments are valued using industry standard models that consider various inputs, including quoted forward prices for commodities, time value, volatility, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable prices at which transactions are executed in the marketplace. The determination of fair value for derivative assets and liabilities also incorporates nonperformance risk for counterparties and for QEP. Derivative contract fair values are reported on a net basis to the extent a legal right of offset with the counterparty exists.
The fair value of financial assets and liabilities at December 31, 2019 and 2018, is shown in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements
|
|
Gross Amounts of Assets and Liabilities
|
|
Netting Adjustments(1)
|
|
Net Amounts Presented on the Consolidated Balance Sheets
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
|
(in millions)
|
|
December 31, 2019
|
Financial Assets
|
|
|
|
|
|
|
|
|
|
Fair value of derivative contracts – short-term
|
$
|
—
|
|
|
$
|
1.5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1.5
|
|
Fair value of derivative contracts – long-term
|
—
|
|
|
0.2
|
|
|
—
|
|
|
—
|
|
|
0.2
|
|
Total financial assets
|
$
|
—
|
|
|
$
|
1.7
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1.7
|
|
|
|
|
|
|
|
|
|
|
|
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
Fair value of derivative contracts – short-term
|
$
|
—
|
|
|
$
|
18.7
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
18.7
|
|
Fair value of derivative contracts – long-term
|
—
|
|
|
0.5
|
|
|
—
|
|
|
—
|
|
|
0.5
|
|
Total financial liabilities
|
$
|
—
|
|
|
$
|
19.2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
19.2
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2018
|
Financial Assets
|
|
|
|
|
|
|
|
|
|
Fair value of derivative contracts – short-term(2)
|
$
|
—
|
|
|
$
|
88.2
|
|
|
$
|
—
|
|
|
$
|
(0.4
|
)
|
|
$
|
87.8
|
|
Fair value of derivative contracts – long-term
|
—
|
|
|
35.4
|
|
|
—
|
|
|
—
|
|
|
35.4
|
|
Total financial assets
|
$
|
—
|
|
|
$
|
123.6
|
|
|
$
|
—
|
|
|
$
|
(0.4
|
)
|
|
$
|
123.2
|
|
|
|
|
|
|
|
|
|
|
|
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
Fair value of derivative contracts – short-term
|
$
|
—
|
|
|
$
|
0.4
|
|
|
$
|
—
|
|
|
$
|
(0.4
|
)
|
|
$
|
—
|
|
Fair value of derivative contracts – long-term
|
—
|
|
|
0.7
|
|
|
—
|
|
|
—
|
|
|
0.7
|
|
Total financial liabilities
|
$
|
—
|
|
|
$
|
1.1
|
|
|
$
|
—
|
|
|
$
|
(0.4
|
)
|
|
$
|
0.7
|
|
____________________________
|
|
(1)
|
The Company nets its derivative contract assets and liabilities outstanding with the same counterparty on the Consolidated Balance Sheets for the contracts that contain netting provisions. Refer to Note 7 – Derivative Contracts for more information regarding the Company's derivative contracts.
|
|
|
(2)
|
Includes fair value of derivative contracts classified as "Noncurrent assets held for sale" of $0.3 million as of December 31, 2018 on the Consolidated Balance Sheets related to the Haynesville Divestiture.
|
The following table discloses the fair value and related carrying amount of certain financial instruments not disclosed in other Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Carrying Amount
|
|
Level 1 Fair Value
|
|
Carrying Amount
|
|
Level 1 Fair Value
|
|
December 31, 2019
|
|
December 31, 2018
|
Financial Assets
|
(in millions)
|
Cash and cash equivalents
|
$
|
166.3
|
|
|
$
|
166.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Financial Liabilities
|
|
|
|
|
|
|
|
Checks outstanding in excess of cash balances
|
$
|
18.3
|
|
|
$
|
18.3
|
|
|
$
|
14.6
|
|
|
$
|
14.6
|
|
Long-term debt
|
$
|
2,015.6
|
|
|
$
|
2,029.4
|
|
|
$
|
2,507.1
|
|
|
$
|
2,350.5
|
|
The carrying amounts of cash and cash equivalents and checks outstanding in excess of cash balances approximate fair value. The fair value of fixed-rate long-term debt is based on the trading levels and dollar prices for the Company's debt at the end of the year. The carrying amount of variable-rate long-term debt approximates fair value because the floating interest rate paid on such debt was set for periods of one month.
The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the calculation of ARO include plugging costs and reserve lives. A reconciliation of the Company's ARO is presented in Note 5 – Asset Retirement Obligations.
Nonrecurring Fair Value Measurements
The provisions of the fair value measurement standard are also applied to the Company's nonrecurring measurements. The Company utilizes fair value on a periodic basis, at least annually, to review its proved oil and gas properties and operating lease right-of-use assets for potential impairment when events and changes in circumstances indicate that the carrying amount of such property may not be recoverable. The fair value of property is measured utilizing the income approach, and utilizing inputs that are primarily based upon internally developed cash flow models discounted at an appropriate weighted average cost of capital. In addition, the signing of a purchase and sale agreement could also trigger an impairment of proved properties. For assets subject to a purchase and sale agreement, the terms of the purchase and sale agreement are used as an indicator of fair value. If a range is estimated for the amount of possible future cash flows, the fair value of property is measured utilizing a probability-weighted approach whereas the likelihood of possible outcomes is taken into consideration. Specific to the Planned Williston Basin Divestiture, the Company obtained a Black-Scholes-Merton estimate of the value of the contractual rights to receive up to 5.8 million shares of the buyer's common stock at December 31, 2018. The estimated fair value of these contractual rights at December 31, 2018 was determined using a five-year contractual period, a 5% risk-free interest rate and a 49.3% weighted-average expected price volatility. Given the unobservable nature of the inputs, fair value calculations associated with proved oil and gas property impairments are considered Level 3 within the fair value hierarchy. During the year ended December 31, 2019, the Company recorded impairments of $5.0 million related to an office building lease. During the years ended December 31, 2018 and 2017, the Company recorded impairments on certain proved oil and gas properties of $1,524.6 million and $38.1 million, respectively, resulting in a reduction of the associated carrying value to fair value. Refer to Note 1 – Summary of Significant Accounting Policies for more information on impairment of oil and gas properties.
Note 7 – Derivative Contracts
QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. In the normal course of business, QEP uses commodity price derivative instruments to reduce the impact of potential downward movements in commodity prices on cash flow, returns on capital investment, and other financial results. However, these instruments typically limit gains from favorable price movements. The volume of production subject to commodity derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. QEP may enter into commodity derivative contracts for up to 100% of forecasted production, but generally, QEP enters into commodity derivative contracts for approximately 50% to 75% of its forecasted annual production by the end of the first quarter of each fiscal year. QEP typically enters into commodity derivative transactions covering a substantial, but varying, portion of its anticipated oil and gas production for the next 12 to 24 months. In addition, QEP has historically entered into commodity derivative contracts on a portion of its storage transactions. QEP does not enter into commodity derivative contracts for speculative purposes.
QEP uses commodity derivative instruments known as fixed-price swaps or costless collars to realize a known price or price range for a specific volume of production delivered into a regional sales point. QEP's commodity derivative instruments do not require the physical delivery of oil or gas between the parties at settlement. All transactions are settled in cash with one party paying the other for the net difference in prices, multiplied by the contract volume, for the settlement period. Oil price derivative instruments are typically structured as NYMEX fixed-price swaps based at Cushing, Oklahoma. Gas price derivative instruments are typically structured as fixed-price swaps or costless collars at NYMEX HH or regional price indices. QEP also enters into oil and gas basis swaps to achieve a fixed-price swap for a portion of its oil and gas sales at prices that reference specific regional index prices.
QEP does not currently have any commodity derivative transactions that have margin requirements or collateral provisions that would require payments prior to the scheduled settlement dates. QEP's commodity derivative contract counterparties are typically financial institutions and energy trading firms with investment-grade credit ratings. QEP routinely monitors and manages its exposure to counterparty risk by requiring specific minimum credit standards for all counterparties, actively monitoring counterparties' public credit ratings and avoiding the concentration of credit exposure by transacting with multiple counterparties. The Company has master-netting agreements with some counterparties that allow the offsetting of receivables and payables in a default situation.
Derivative Contracts – Production
The following table presents QEP's volumes and average prices for its commodity derivative swap contracts as of December 31, 2019:
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
Index
|
|
Total Volumes
|
|
Average Swap Price per Unit
|
|
|
|
|
(in millions)
|
|
|
Oil sales
|
|
|
|
(bbls)
|
|
|
($/bbl)
|
|
2020
|
|
NYMEX WTI
|
|
14.1
|
|
|
$
|
57.83
|
|
2020
|
|
Argus WTI Houston
|
|
1.0
|
|
|
$
|
60.06
|
|
2020
|
|
Argus WTI Midland
|
|
1.5
|
|
|
$
|
57.30
|
|
2021
|
|
NYMEX WTI
|
|
0.9
|
|
|
$
|
55.06
|
|
QEP uses oil basis swaps, combined with NYMEX WTI fixed price swaps, to achieve fixed price swaps for the location at which it sells its physical production. The following table presents details of QEP's oil basis swaps as of December 31, 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
Index
|
|
Basis
|
|
Total Volumes
|
|
Weighted-Average Differential
|
|
|
|
|
|
|
(in millions)
|
|
|
Oil sales
|
|
|
|
|
|
(bbls)
|
|
|
($/bbl)
|
|
2020
|
|
NYMEX WTI
|
|
Argus WTI Midland
|
|
6.8
|
|
|
$
|
0.18
|
|
2020
|
|
NYMEX WTI
|
|
Argus WTI Houston
|
|
0.4
|
|
|
$
|
3.75
|
|
2021
|
|
NYMEX WTI
|
|
Argus WTI Midland
|
|
3.7
|
|
|
$
|
0.98
|
|
QEP Derivative Financial Statement Presentation
The following table identifies the Consolidated Balance Sheets location of QEP's outstanding derivative contracts on a gross contract basis as opposed to the net contract basis presentation on the Consolidated Balance Sheets and the related fair values at the balance sheet dates:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross asset derivative
instruments fair value
|
|
Gross liability derivative
instruments fair value
|
|
|
|
December 31,
|
|
Balance Sheet line item
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Current:
|
|
|
(in millions)
|
Commodity
|
Fair value of derivative contracts
|
|
$
|
1.5
|
|
|
$
|
88.2
|
|
|
$
|
18.7
|
|
|
$
|
0.4
|
|
Long-term:
|
|
|
|
|
|
|
|
|
|
|
Commodity
|
Fair value of derivative contracts
|
|
0.2
|
|
|
35.4
|
|
|
0.5
|
|
|
0.7
|
|
Total derivative instruments(1)
|
|
$
|
1.7
|
|
|
$
|
123.6
|
|
|
$
|
19.2
|
|
|
$
|
1.1
|
|
_______________________
|
|
(1)
|
Includes fair value of derivative contracts classified as "Noncurrent assets held for sale" of $0.3 million as of December 31, 2018 on the Consolidated Balance Sheets related to the Haynesville Divestiture.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative contracts
|
Year Ended December 31,
|
2019
|
|
2018
|
|
2017
|
Realized gains (losses) on commodity derivative contracts
|
(in millions)
|
Production
|
|
|
|
|
|
Oil derivative contracts
|
$
|
(32.2
|
)
|
|
$
|
(153.4
|
)
|
|
$
|
6.8
|
|
Gas derivative contracts
|
(2.9
|
)
|
|
(5.0
|
)
|
|
(22.3
|
)
|
Gas Storage
|
|
|
|
|
|
Gas derivative contracts
|
—
|
|
|
0.3
|
|
|
—
|
|
Realized gains (losses) on commodity derivative contracts
|
(35.1
|
)
|
|
(158.1
|
)
|
|
(15.5
|
)
|
Unrealized gains (losses) on commodity derivative contracts
|
|
|
|
|
|
Production
|
|
|
|
|
|
Oil derivative contracts
|
(139.8
|
)
|
|
277.0
|
|
|
(66.2
|
)
|
Gas derivative contracts
|
(0.3
|
)
|
|
(22.3
|
)
|
|
133.6
|
|
Gas Storage
|
|
|
|
|
|
Gas derivative contracts
|
—
|
|
|
(0.3
|
)
|
|
2.5
|
|
Unrealized gains (losses) on commodity derivative contracts
|
(140.1
|
)
|
|
254.4
|
|
|
69.9
|
|
Total realized and unrealized gains (losses) on commodity derivative contracts related to production and storage contracts
|
$
|
(175.2
|
)
|
|
$
|
96.3
|
|
|
$
|
54.4
|
|
|
|
|
|
|
|
Derivatives associated with divestitures
|
|
|
|
|
|
Unrealized gains (losses) on commodity derivative contracts
|
|
|
|
|
|
Production
|
|
|
|
|
|
Oil derivative contracts
|
$
|
—
|
|
|
$
|
(2.7
|
)
|
|
$
|
(1.3
|
)
|
Gas derivative contracts
|
1.8
|
|
|
—
|
|
|
(23.5
|
)
|
NGL derivative contracts
|
—
|
|
|
(3.2
|
)
|
|
(5.1
|
)
|
Unrealized gains (losses) on commodity derivative contracts related to divestitures(1)(2)(3)
|
$
|
1.8
|
|
|
$
|
(5.9
|
)
|
|
$
|
(29.9
|
)
|
|
|
|
|
|
|
Total realized and unrealized gains (losses) on commodity derivative contracts
|
$
|
(173.4
|
)
|
|
$
|
90.4
|
|
|
$
|
24.5
|
|
_______________________
|
|
(1)
|
During the year ended December 31, 2019 , the unrealized gains (losses) on commodity derivative contracts related to the Haynesville Divestiture are comprised of derivatives included as part of the Haynesville/Cotton Valley purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in January 2019. Refer to Note 3 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Haynesville Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Consolidated Statements of Operations.
|
|
|
(2)
|
During the year ended December 31, 2018, the unrealized gains (losses) on commodity derivative contracts related to the Uinta Basin Divestiture are comprised of derivatives entered into in conjunction with the execution of the Uinta Basin purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in September 2018. Refer to Note 3 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Uinta Basin Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Consolidated Statements of Operations.
|
|
|
(3)
|
During the year ended December 31, 2017, the unrealized gains (losses) on commodity derivative contracts related to the Pinedale Divestiture are comprised of derivatives entered into in conjunction with the execution of the Pinedale purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in September 2017. Refer to Note 3 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Pinedale Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Consolidated Statements of Operations.
|
Note 8 – Leases
Adoption of ASC Topic 842, Leases
On January 1, 2019, QEP adopted ASC Topic 842, Leases, using the modified retrospective approach, which was applied to historical leases that were still effective as of January 1, 2019. Results for reporting periods beginning January 1, 2019, are presented in accordance with ASC Topic 842, while prior period amounts are reported in accordance with historical accounting treatment under ASC Topic 840, Leases.
In accordance with the adoption of ASC Topic 842, QEP now records a net operating lease right-of-use (ROU) asset and operating lease liability on the Consolidated Balance Sheets for all operating leases with a contract term in excess of 12 months. Prior to the adoption of ASC Topic 842, these same leases were treated as operating leases under ASC Topic 840 and therefore were not recorded on the December 31, 2018 Consolidated Balance Sheet. There was no impact to retained earnings and no significant impact on the Consolidated Statements of Operations or the Consolidated Statements of Cash Flows as a result of adopting ASC Topic 842.
Lease Recognition
QEP enters into contractual lease arrangements to rent office space, compressors, generators, drilling rigs and other equipment from third-party lessors. ROU assets represent QEP’s right to use an underlying asset for the lease term and lease liabilities represent QEP’s obligation to make future lease payments arising from the lease. Operating lease ROU assets and liabilities are recorded at commencement date based on the present value of lease payments over the lease term. Leases with an initial term of 12 months or less are not recorded on the Consolidated Balance Sheets. The Company recognizes lease expense for these short-term leases on a straight-line basis over the lease term. With the exception of generators, QEP does not account for lease components separately from the non-lease components. The contractual consideration provided under QEP's leased generators is allocated between lease components, such as equipment, and non-lease components, such as maintenance service fees, based on estimated costs from the vendor. QEP uses the implicit interest rate when readily determinable. However, most of QEP's lease agreements do not provide an implicit interest rate. As such, QEP uses its incremental borrowing rate based on the information available at commencement date of the contract in determining the present value of future lease payments. The incremental borrowing rate is calculated using a risk-free interest rate adjusted for QEP's risk. The operating lease ROU asset also includes any lease incentives received in the recognition of the present value of future lease payments. Certain of QEP's leases may also include escalation clauses or options to extend or terminate the lease. These options are included in the present value recorded for the leases when it is reasonably certain that QEP will exercise that option. Lease expense for lease payments is recognized on a straight-line basis over the lease term.
QEP determines if an arrangement is a lease at inception of the contract and records the resulting operating lease asset on the Consolidated Balance Sheets as “Operating lease right-of-use assets, net” with offsetting liabilities recorded as “Current operating lease liabilities” and “Operating lease liabilities.” QEP recognizes a lease in the financial statements when the arrangement either explicitly or implicitly involves property, plant, or equipment (PP&E), the contract terms are dependent on the use of the PP&E, and QEP has the ability or right to operate the PP&E or to direct others to operate the PP&E and receive the majority of the economic benefits of the assets. As of December 31, 2019, QEP does not have any financing leases.
Lease costs represent the straight-line lease expense of ROU assets and short-term leases. The components of lease cost are classified as follows:
|
|
|
|
|
|
As of December 31,
|
|
2019 (1)
|
|
(in millions)
|
Lease Cost included in the Consolidated Balance Sheets
|
|
Property, Plant and Equipment acquisitions (2)
|
$
|
13.8
|
|
|
|
|
Year Ended December 31,
|
|
2019 (1)
|
|
(in millions)
|
Lease Cost included in the Consolidated Statement of Operations
|
|
Lease operating expense
|
$
|
11.9
|
|
Gathering and other expense
|
7.7
|
|
General and administrative
|
5.7
|
|
|
|
Total lease cost
|
$
|
25.3
|
|
____________________________
|
|
(1)
|
Prior periods are not presented as prior period amounts have not been adjusted under the modified retrospective method for the new lease recognition rule, ASC Topic 842. Refer to Note 1 – Basis of Presentation for additional information.
|
|
|
(2)
|
Represents short-term lease capital expenditures related to drilling rigs for the twelve months ended December 31, 2019. These costs are capitalized as a part of "Proved properties" on the Consolidated Balance Sheets.
|
Lease term and discount rate related to the Company's leases are as follows:
|
|
|
|
|
December 31, 2019 (1)
|
Weighted-average remaining lease term (years)
|
5.4
|
|
Weighted-average discount rate
|
8.0
|
%
|
____________________________
|
|
(1)
|
Prior periods are not presented as prior period amounts have not been adjusted under the modified retrospective method for the new lease recognition rule, ASC Topic 842. Refer to Note 1 – Basis of Presentation for additional information.
|
Note 9 – Restructuring
In February 2018, QEP's Board approved certain strategic and financial initiatives. In February 2019, QEP's Board commenced a comprehensive review of strategic alternatives to maximize shareholder value. In connection with these activities, QEP has incurred or expects to incur various restructuring costs associated with contractual termination benefits including severance, accelerated vesting of share-based compensation and other expenses. The termination benefits have been accounted for under ASC 712, Compensation – Nonretirement Postemployment Benefits and ASC 718, Compensation – Stock Compensation.
Restructuring costs recognized are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2019
|
|
Total recognized
|
|
Recognized in "General and administrative"
|
|
Recognized in "Net (gain) loss from asset sales, inclusive of restructuring costs"
|
|
Recognized in "Interest and other (income) expense"
|
|
(in millions)
|
Termination benefits
|
$
|
12.3
|
|
|
$
|
12.2
|
|
|
$
|
0.1
|
|
|
—
|
|
Office lease termination costs
|
0.6
|
|
|
0.6
|
|
|
—
|
|
|
—
|
|
Accelerated share-based compensation(1)
|
12.6
|
|
|
11.1
|
|
|
1.5
|
|
|
—
|
|
Retention expense (including share-based compensation)
|
19.5
|
|
|
19.5
|
|
|
—
|
|
|
—
|
|
Pension and Medical Plan curtailment
|
1.2
|
|
|
—
|
|
|
(0.2
|
)
|
|
1.4
|
|
Total restructuring costs
|
$
|
46.2
|
|
|
$
|
43.4
|
|
|
$
|
1.4
|
|
|
$
|
1.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2018
|
|
Total recognized
|
|
Recognized in "General and administrative"
|
|
Recognized in "Net (gain) loss from asset sales, inclusive of restructuring costs"
|
|
Recognized in "Interest and other (income) expense"
|
|
(in millions)
|
Termination benefits
|
$
|
32.3
|
|
|
$
|
25.7
|
|
|
$
|
6.6
|
|
|
$
|
—
|
|
Office lease termination costs
|
1.0
|
|
|
1.0
|
|
|
—
|
|
|
—
|
|
Accelerated share-based compensation(1)
|
11.0
|
|
|
8.8
|
|
|
2.2
|
|
|
—
|
|
Retention expense (including share-based compensation)
|
18.8
|
|
|
18.8
|
|
|
—
|
|
|
—
|
|
Pension and Medical Plan curtailment
|
0.1
|
|
|
—
|
|
|
(0.2
|
)
|
|
0.3
|
|
Total restructuring costs
|
$
|
63.2
|
|
|
$
|
54.3
|
|
|
$
|
8.6
|
|
|
$
|
0.3
|
|
____________________________
|
|
(1)
|
Accelerated share-based compensation represents the additional expense or loss recognized in the Consolidated Statements of Operations for the year ended December 31, 2019 and 2018. Total accelerated share-based compensation was $29.1 million and was determined based on the contractual vesting date, with $12.6 million and $11.0 million recognized in 2019 and 2018, respectively, as shown above, and the remaining amount recognized in prior periods.
|
|
|
|
|
|
|
|
|
|
|
|
Costs recognized from inception through December 31, 2019 (1)
|
|
Total remaining costs expected to be incurred(2)
|
|
|
(in millions)
|
Termination benefits
|
$
|
44.6
|
|
|
$
|
—
|
|
(2)
|
Office lease termination costs
|
1.6
|
|
|
—
|
|
(2)
|
Accelerated share-based compensation
|
23.6
|
|
|
—
|
|
(2)
|
Retention expense (including share-based compensation)
|
38.3
|
|
|
0.5
|
|
|
Pension and Medical Plan curtailment
|
1.3
|
|
|
—
|
|
(2)
|
Total restructuring costs
|
$
|
109.4
|
|
|
$
|
0.5
|
|
|
____________________________
|
|
(1)
|
Represents costs incurred since February 2018 when QEP's Board approved certain strategic and financial initiatives.
|
|
|
(2)
|
Due to the nature of the strategic initiatives, as of December 31, 2019, the Company is not able to reasonably estimate the total cost to be incurred in connection with these restructurings.
|
The following table is a reconciliation of QEP's restructuring liability, which is included within "Accounts payable and accrued expenses" on the Consolidated Balance Sheets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restructuring liability
|
|
Termination benefits
|
|
Office lease termination costs
|
|
Accelerated share-based compensation
|
|
Retention expense
|
|
Pension curtailment
|
|
Total
|
|
(in millions)
|
Balance at December 31, 2018
|
$
|
19.5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
10.8
|
|
|
$
|
—
|
|
|
$
|
30.3
|
|
Costs incurred and charged to expense
|
12.3
|
|
|
0.6
|
|
|
12.6
|
|
|
19.5
|
|
|
1.2
|
|
|
46.2
|
|
Costs paid or otherwise settled
|
(30.6
|
)
|
|
(0.6
|
)
|
|
(12.6
|
)
|
|
(23.8
|
)
|
|
(1.2
|
)
|
|
(68.8
|
)
|
Balance at December 31, 2019
|
$
|
1.2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
6.5
|
|
|
$
|
—
|
|
|
$
|
7.7
|
|
Note 10 – Debt
As of the indicated dates, the principal amount of QEP's debt consisted of the following:
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2019
|
|
2018
|
|
(in millions)
|
Revolving Credit Facility due 2022
|
$
|
—
|
|
|
$
|
430.0
|
|
6.80% Senior Notes due 2020
|
—
|
|
|
51.7
|
|
6.875% Senior Notes due 2021
|
382.4
|
|
|
397.6
|
|
5.375% Senior Notes due 2022
|
500.0
|
|
|
500.0
|
|
5.25% Senior Notes due 2023
|
650.0
|
|
|
650.0
|
|
5.625% Senior Notes due 2026
|
500.0
|
|
|
500.0
|
|
Less: unamortized discount and unamortized debt issuance costs
|
(16.8
|
)
|
|
(22.2
|
)
|
Total long-term debt outstanding
|
$
|
2,015.6
|
|
|
$
|
2,507.1
|
|
Of the total debt outstanding on December 31, 2019, the 6.875% Senior Notes due March 1, 2021, the 5.375% Senior Notes due October 1, 2022 and the 5.25% Senior Notes due May 1, 2023, will mature within the next five years. In addition, the revolving credit facility matures on September 1, 2022.
Credit Facility
QEP's revolving credit facility, which matures in September 2022, provides for loan commitments of $1.25 billion. The credit facility provides for borrowings at short-term interest rates and contains customary covenants and restrictions. The credit agreement contains financial covenants (that are defined in the credit agreement) that limit the amount of debt the Company can incur and may limit the amount available to be drawn under the credit facility including: (i) a net funded debt to capitalization ratio that may not exceed 60%, (ii) a leverage ratio under which net funded debt may not exceed 3.75 times consolidated EBITDA (as defined in the credit agreement), beginning January 1, 2019, and (iii) a present value coverage ratio under which the present value of the Company's proved reserves must exceed net funded debt by 1.40 times through December 31, 2019, and must exceed net funded debt by 1.50 times at any time on or after January 1, 2020. As of December 31, 2019 and 2018, QEP was in compliance with the covenants under the credit agreement.
During the years ended December 31, 2019 and 2018, QEP's weighted-average interest rates on borrowings from its credit facility were 4.73% and 4.43%, respectively. As of December 31, 2019, QEP had no borrowings outstanding and $2.9 million in letters of credit outstanding under the credit facility. As of December 31, 2018, QEP had $430.0 million of borrowings outstanding and $0.3 million in letters of credit outstanding under the credit facility.
Senior Notes
At December 31, 2019, the Company had $2,032.4 million principal amount of senior notes outstanding with maturities ranging from March 1, 2021 to March 1, 2026 and coupons ranging from 5.25% to 6.875%. The senior notes pay interest semi-annually, are unsecured senior obligations and rank equally with all of our other existing and future unsecured and senior obligations. QEP may redeem some or all of its senior notes at any time before their maturity at a redemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption. The indentures governing QEP's senior notes contain customary events of default and covenants that may limit QEP's ability to, among other things, place liens on its property or assets. During the year ended December 31, 2019, QEP redeemed all $51.7 million of its outstanding 6.80% Senior Notes due March 2020 and repurchased $15.2 million of its 6.875% Senior Notes due March 2021. During the year ended December 31, 2019, the Company recorded $1.0 million in "Loss from early extinguishment of debt" in the Consolidated Statements of Operations for costs associated with the redemption and repurchase of Senior Notes.
The Company expects to fund the maturity of its 6.875% Senior Notes due March 1, 2021 with cash on hand, cash flow from its operating activities, the expected alternative minimum tax (AMT) credit refunds, proceeds from potential asset sales and borrowings under its revolving credit facility. The credit facility has various financial covenants that limit the amount of debt the Company can incur, including the present value of the Company’s reserves. An updated present value calculation is required to be delivered to the bank group by April 1 of each year and is calculated using the prior year end reserve report and an average commodity price deck provided by a subset of the bank group. Based on the Company’s December 31, 2019 reserves, and current commodity pricing, the Company believes there will be sufficient availability under its revolving credit facility to continue to fund ongoing operations, including funding of a portion of the 6.875% Senior Notes repayment. The Company can make no assurance regarding future availability under its revolving credit facility or continued compliance with restrictive financial covenants if its current projections or material underlying assumptions prove to be incorrect. Further, if the Company fails to comply with the covenants, the Company may not be able to borrow under the credit facility.
Note 11 – Commitments and Contingencies
The Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. In each reporting period, the Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its Consolidated Financial Statements. In accordance with ASC 450, Contingencies, an accrual is recorded for a material loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes.
Legal proceedings are inherently unpredictable and unfavorable resolutions can occur. Assessing contingencies is highly subjective and requires judgment about uncertain future events. When evaluating contingencies related to legal proceedings, the Company may be unable to estimate losses due to a number of factors, including potential defenses, the procedural status of the matter in question, the presence of complex legal and/or factual issues, the ongoing discovery and/or development of information important to the matter.
Mabee Ranch Royalty Partnership Litigation – In October, 2017, the owners of certain surface and mineral interests in Martin and Andrews County, Texas, filed suit against QEP, alleging QEP improperly used the surface of the properties and failed to correctly pay royalties, and seeking money damages and a declaratory judgment that portions of the oil and gas leases covering the properties are no longer in effect.
Mandan, Hidatsa and Arikara Nation ("MHA Nation") Title Dispute – In June 2018, the MHA Nation notified QEP of its position that QEP has no valid lease covering certain minerals underlying the Missouri and Little Missouri Riverbeds on the Fort Berthold Reservation in North Dakota. The MHA Nation also passed a resolution purporting to rescind those portions of QEP's IMDA lease covering the disputed minerals underlying the Missouri River.
Overriding Royalty Interest Litigation – In July 2019, owners of small overriding royalty interests in certain wells in the South Antelope oil and gas field in North Dakota filed suit against QEP, alleging QEP has improperly taken deductions for post-production expenses.
The Company is unable to make an estimate of the range of reasonably possible loss related to its contingencies.
Commitments
QEP has contracted for gathering, processing and firm transportation services with various third parties. Market conditions, drilling activity and competition may prevent full utilization of the contractual capacity. In addition, QEP has contracts with third parties who provide drilling services. Annual payments and the corresponding years for gathering, processing, transportation, drilling and fractionation contracts are as follows:
|
|
|
|
|
Year
|
Amount
|
|
(in millions)
|
2020
|
$
|
25.2
|
|
2021
|
$
|
23.8
|
|
2022
|
$
|
19.4
|
|
2023
|
$
|
9.5
|
|
2024
|
$
|
5.6
|
|
After 2024
|
$
|
7.2
|
|
QEP has entered into contractual lease arrangements to rent office space, compressors, generators, and other equipment from third-party lessors. On January 1, 2019, QEP adopted ASC Topic 842, Leases, using the modified retrospective approach. Refer to Note 8 – Leases for additional information. Expense from operating leases were $25.3 million, $30.3 million and $24.9 million during the years ended December 31, 2019, 2018 and 2017, respectively. Amounts for 2018 and 2017 are reported in accordance with historical accounting treatment under ASC Topic 840, Leases.
As of December 31, 2019, the maturity analysis for long-term operating leases under the scope of ASC 842 are as follows:
|
|
|
|
|
Year
|
Amount
|
|
(in millions)
|
2020
|
$
|
22.3
|
|
2021
|
$
|
20.4
|
|
2022
|
$
|
15.9
|
|
2023
|
$
|
10.6
|
|
2024
|
$
|
1.4
|
|
After 2024
|
$
|
2.4
|
|
Less: Interest(1)
|
$
|
(10.2
|
)
|
Present Value of Lease Liabilities(2)
|
$
|
62.8
|
|
____________________________
|
|
(1)
|
Calculated using the estimated or stated interest rate for each lease.
|
|
|
(2)
|
Of the total present value of lease liabilities, $18.0 million was recorded in "Current operating lease liabilities" and $44.8 million was recorded in "Operating lease liabilities" on the Consolidated Balance Sheets.
|
As of December 31, 2018, minimum future contractual payments for long-term operating leases under the scope of ASC 840 are as follows:
|
|
|
|
|
Year
|
Amount
|
|
(in millions)
|
2019
|
$
|
17.4
|
|
2020
|
$
|
13.8
|
|
2021
|
$
|
9.1
|
|
2022
|
$
|
7.4
|
|
2023
|
$
|
4.5
|
|
After 2023
|
$
|
—
|
|
Note 12 – Share-Based Compensation
In 2018, QEP's Board and QEP's shareholders approved the QEP Resources, Inc. 2018 Long-Term Incentive Plan (LTIP), which replaces the 2010 Long-Term Stock Incentive Plan (LTSIP) and provides for the issuance of up to 10.0 million shares such that the Board of Directors may grant long-term incentive compensation. QEP issues restricted share awards and restricted share units under its LTSIP or LTIP and awards performance share units under its CIP to certain officers, employees, and non-employee directors. QEP historically issued stock options. Grants issued prior to May 15, 2018 are under the LTSIP and the grants issued on or after May 15, 2018 are under the LTIP. QEP recognizes the expense over the vesting periods for the stock options, restricted share awards, restricted share units and performance share units. There were 8.3 million shares available for future grants under the LTIP at December 31, 2019.
Share-based compensation expense is generally recognized within "General and administrative" expense on the Consolidated Statements of Operations and is summarized in the table below. During the year ended December 31, 2019 and 2018, the Company recorded an additional $12.6 million and $11.0 million, respectively, of share-based compensation expense related to the acceleration of vesting that occurred as part of the restructuring program. Of this, $1.5 million and $2.2 million for the year ended December 31, 2019 and 2018, respectively, was recorded in "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Consolidated Statements of Operations and the remaining $11.1 million and $8.8 million, respectively, is included in share-based compensation expense below. Refer to Note 9 – Restructuring for additional information.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2019
|
|
2018
|
|
2017
|
|
(in millions)
|
Stock options
|
$
|
0.4
|
|
|
$
|
1.2
|
|
|
$
|
2.3
|
|
Restricted share awards
|
20.4
|
|
|
27.5
|
|
|
24.6
|
|
Performance share units
|
4.3
|
|
|
8.1
|
|
|
(4.5
|
)
|
Restricted share units
|
0.3
|
|
|
0.1
|
|
|
—
|
|
Total share-based compensation expense
|
$
|
25.4
|
|
|
$
|
36.9
|
|
|
$
|
22.4
|
|
Stock Options
QEP used the Black-Scholes-Merton mathematical model to estimate the fair value of stock option awards at the date of grant. Fair value calculations rely upon subjective assumptions used in the mathematical model and may not be representative of future results. The Black-Scholes-Merton model is intended for calculating the value of options not traded on an exchange. The Company utilized the "simplified" method to estimate the expected term of the stock options granted as there was limited historical exercise data available in estimating the expected term of the stock options. QEP used a historical volatility method to estimate the fair value of stock options awards and the risk-free interest rate was based on the yield on U.S. Treasury strips with maturities similar to those of the expected term of the stock options. The stock options typically vest in equal installments over three years from the grant date and are exercisable immediately upon vesting through the seventh anniversary of the grant date. To fulfill options exercised, QEP either reissues treasury stock or issues new shares. The Company recognizes forfeitures of stock options as they occur. During the years ended December 31, 2019 and 2018, QEP did not issue stock options.
The calculated fair value of options granted and major assumptions used in the model at the date of grant are listed below:
|
|
|
|
|
|
Stock Option Assumptions
|
|
Year Ended December 31,
|
|
2017
|
Weighted-average grant date fair value of awards granted during the period
|
$
|
6.44
|
|
Risk-free interest rate range
|
1.66% - 1.81%
|
|
Weighted-average risk-free interest rate
|
1.8
|
%
|
Expected price volatility range
|
43.82% - 46.70%
|
|
Weighted-average expected price volatility
|
43.9
|
%
|
Expected dividend yield
|
—
|
%
|
Expected term in years at the date of grant
|
4.5
|
|
Stock option transactions under the terms of the LTSIP are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding
|
|
Weighted-Average Exercise Price
|
|
Weighted-Average Remaining Contractual Term
|
|
Aggregate Intrinsic Value
|
|
|
|
(per share)
|
|
(in years)
|
|
(in millions)
|
Outstanding at December 31, 2018
|
2,098,933
|
|
|
$
|
22.27
|
|
|
|
|
|
Exercised
|
—
|
|
|
—
|
|
|
|
|
|
Cancelled
|
(296,546
|
)
|
|
30.81
|
|
|
|
|
|
Outstanding at December 31, 2019
|
1,802,387
|
|
|
$
|
20.87
|
|
|
2.31
|
|
$
|
—
|
|
Options Exercisable at December 31, 2019
|
1,780,124
|
|
|
$
|
20.93
|
|
|
2.30
|
|
$
|
—
|
|
Unvested Options at December 31, 2019
|
22,263
|
|
|
$
|
15.68
|
|
|
4.20
|
|
$
|
—
|
|
During the years ended December 31, 2019 and December 31, 2017, there were no exercises of stock options. The total intrinsic value (the difference between the market price at the exercise date and the exercise price) of stock options exercised was $0.1 million during the year ended December 31, 2018. There was $2.3 million income tax impact for the year ended December 31, 2019, and no income tax impact for the years ended December 31, 2018 and 2017. As of December 31, 2019, there was no unrecognized compensation cost related to stock options granted under the LTSIP. Refer to Note 9 – Restructuring for more information.
Restricted Share Awards
Restricted share award grants typically vest in equal installments over three years from the grant date. The grant date fair value is determined based on the closing bid price of the Company's common stock on the grant date. The Company recognizes restricted share forfeitures as they occur. The total fair value of restricted share awards that vested during the years ended December 31, 2019, 2018 and 2017, was $32.5 million, $21.5 million and $18.4 million, respectively. There was $5.4 million income tax impact for the year ended December 31, 2019, and no tax impact for the years ended December 31, 2018 and 2017. The weighted-average grant date fair value of restricted share awards granted was $7.72 per share, $9.56 per share and $13.90 per share for the years ended December 31, 2019, 2018 and 2017, respectively. As of December 31, 2019, $9.2 million of unrecognized compensation cost related to restricted share awards granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 1.95 years. The weighted-average vesting period may be reduced due to accelerated vesting of awards under the restructuring program. Refer to Note 9 – Restructuring for more information.
Transactions involving restricted share awards under the terms of the LTSIP and LTIP are summarized below:
|
|
|
|
|
|
|
|
|
Restricted Share Awards Outstanding
|
|
Weighted-Average Grant Date Fair Value
|
|
|
|
(per share)
|
Unvested balance at December 31, 2018
|
3,822,133
|
|
|
$
|
10.76
|
|
Granted
|
2,365,262
|
|
|
7.72
|
|
Vested
|
(3,093,883
|
)
|
|
10.49
|
|
Forfeited
|
(248,479
|
)
|
|
9.14
|
|
Unvested balance at December 31, 2019
|
2,845,033
|
|
|
$
|
8.67
|
|
Performance Share Units
The payouts for performance share units are dependent upon the Company's total shareholder return compared to a group of its peers over three years. The awards are denominated in share units and have historically been paid in cash. The Company has the option to settle earned awards in cash or shares of common stock under the Company's LTIP; however, as of December 31, 2019, the Company expects to settle all awards in cash under the CIP. These awards are classified as liabilities and are included within "Other long-term liabilities" on the Consolidated Balance Sheets. As these awards are dependent upon the Company's total shareholder return and stock price, they are measured at fair value at the end of each reporting period. The Company paid $13.0 million, $2.8 million and $5.3 million for vested performance share units during the years ended December 31, 2019, 2018 and 2017, respectively. The weighted-average grant date fair value of the performance share units granted during the years ended December 31, 2019, 2018 and 2017, was $7.93, $9.55, and $16.90 per share, respectively. As of December 31, 2019, $1.0 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of performance shares granted, is expected to be recognized over a weighted-average vesting period of 2.05 years. The weighted-average vesting period may be reduced due to accelerated vesting under the restructuring program. Refer to Note 9 – Restructuring for more information.
Transactions involving performance share units under the terms of the CIP are summarized below:
|
|
|
|
|
|
|
|
|
Performance Share Units Outstanding
|
|
Weighted-Average Grant Date Fair Value
|
|
|
|
(per share)
|
Unvested balance at December 31, 2018
|
1,559,312
|
|
|
$
|
11.47
|
|
Granted
|
759,506
|
|
|
7.93
|
|
Vested
|
(1,692,896
|
)
|
|
10.70
|
|
Unvested balance at December 31, 2019
|
625,922
|
|
|
$
|
9.04
|
|
Restricted Share Units
Employees may elect to defer their grants of restricted share awards and these deferred awards are designated as restricted share units. Restricted share units vest over three years and are deferred into the Company's nonqualified, unfunded deferred compensation plan at the time of vesting. These awards are ultimately paid in cash, are classified as liabilities in "Other long-term liabilities" on the Consolidated Balance Sheets and are measured at fair value at the end of each reporting period. The weighted-average grant date fair value of the restricted share units was $7.87, $9.55 and $16.98 per share for the years ended December 31, 2019, 2018 and 2017, respectively. There was $2.1 million income tax impact for the year ended December 31, 2019, and no tax impact for the years ended December 31, 2018 and 2017.As of December 31, 2019, $0.1 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of restricted share units granted, is expected to be recognized over a weighted-average vesting period of 0.97 years. The weighted-average vesting period may be reduced due to accelerated vesting of awards under the restructuring program. Refer to Note 9 – Restructuring for more information.
Transactions involving restricted share units under the terms of the LTSIP are summarized below:
|
|
|
|
|
|
|
|
|
Restricted Share Units Outstanding
|
|
Weighted-Average Grant Date Fair Value
|
|
|
|
(per share)
|
Unvested balance at December 31, 2018
|
42,675
|
|
|
$
|
10.47
|
|
Granted
|
37,779
|
|
|
7.87
|
|
Vested and paid
|
(46,061
|
)
|
|
10.06
|
|
Unvested balance at December 31, 2019
|
34,393
|
|
|
$
|
8.16
|
|
Note 13 – Employee Benefits
Pension and Other Postretirement Benefits
The Company provides pension and other postretirement benefits to certain employees through three benefit plans: the QEP Resources, Inc. Retirement Plan (Pension Plan), the Supplemental Executive Retirement Plan (SERP), and a postretirement medical plan (Medical Plan).
The Pension Plan is a closed, qualified, defined-benefit pension plan that is funded and provides pension benefits to certain QEP employees, which, as of December 31, 2019, covers four active and suspended participants, or 2%, of QEP's active employees, and 210 participants that are retired or were terminated and vested. Pension Plan benefits are based on the employee's age at retirement, years of service as of the earlier of the participant's termination of employment or December 31, 2015, and highest earnings in a consecutive 72 semi-monthly pay period during the 10 years preceding termination of employment or, if earlier, December 31, 2015. During the year ended December 31, 2019, the Company made contributions of $5.0 million to the Pension Plan and expects to contribute approximately $4.0 million to the Pension Plan in 2020. Contributions to the Pension Plan increase plan assets.
The SERP is a nonqualified retirement plan that is unfunded and provides pension benefits to certain QEP employees. SERP benefits are based on the employee's age at retirement, years of service and highest earnings in a consecutive 72 semi-monthly pay period during the 10 years preceding the participant's termination of employment. During the year ended December 31, 2019, the Company made contributions of $0.5 million to its SERP and expects to contribute approximately $8.6 million in 2020. Contributions to the SERP are used to fund current benefit payments. The SERP was amended and restated in June 2015 and is closed to new participants effective January 1, 2016.
During the year ended December 31, 2017, the Company recognized a $0.7 million loss on curtailment related to the SERP in connection with the Pinedale Divestiture, which was recorded on the Consolidated Statements of Operations within "Net gain (loss) from asset sales, inclusive of restructuring costs."
The Medical Plan is a self-insured plan. It is unfunded and provides other postretirement benefits including certain health care and life insurance benefits for certain retired QEP employees. The Medical Plan was originally provided only to employees hired by Questar Corporation before January 1, 1997. Of the four active, pension eligible employees, one is also eligible for the Medical Plan when they retire. As of December 31, 2019, 33 retirees are enrolled in the Medical Plan. The Company has capped its exposure to increasing medical costs by paying a fixed dollar monthly contribution toward these retiree benefits. The Company's contribution is prorated based on an employee's years of service at retirement; only those employees with 25 or more years of service receive the maximum company contribution. During the year ended December 31, 2019, the Company made contributions of $0.9 million and expects to contribute approximately $0.2 million of benefits in 2020. At December 31, 2019 and 2018, QEP's accumulated benefit obligation exceeded the fair value of its qualified retirement plan assets.
In February 2017, the Company changed the eligibility requirements for active employees eligible for the Medical Plan, as well as retirees currently enrolled. Effective July 1, 2017, the Company no longer offers the Medical Plan to a retiree and spouse that are both Medicare eligible. In addition, the Company no longer offers life insurance to individuals retiring on or after July 1, 2017.
The Company's execution of its 2018 and 2019 strategic initiatives, including divestitures and corporate restructurings, triggered curtailments related to the Pension Plan, SERP and/or Medical Plan at the closing of the various transactions. Refer to Note 9 – Restructuring for more information. Curtailments were included in "Interest and other income (expense)" and "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Consolidated Statements of Operations depending on the associated participants triggering the curtailment and are summarized in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
Statements of Operations Line
|
|
2019
|
|
2018
|
Interest and other income (expense)
|
|
$
|
(1.4
|
)
|
|
$
|
(0.3
|
)
|
Net gain (loss) from asset sales, inclusive of restructuring costs
|
|
0.2
|
|
|
0.2
|
|
Total curtailment gain (loss)
|
|
$
|
(1.2
|
)
|
|
$
|
(0.1
|
)
|
In accordance with the early adoption of ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the presentation of net periodic pension cost and net periodic postretirement benefit cost, the Company recognizes service costs related to SERP and Medical Plan benefits within "General and administrative" expense on the Consolidated Statements of
Operations. All other expenses related to the Pension Plan, SERP and Medical Plan are recognized within "Interest and other income (expense)" on the Consolidated Statements of Operations.
The accumulated benefit obligation for all defined-benefit pension plans was $135.2 million and $122.1 million at December 31, 2019 and 2018, respectively.
The following table sets forth changes in the benefit obligations and fair value of plan assets for the Company's Pension Plan, SERP and Medical Plan for the years ended December 31, 2019 and 2018, as well as the funded status of the plans and amounts recognized in the financial statements at December 31, 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Plan and SERP benefits
|
|
Medical Plan benefits
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Change in benefit obligation
|
(in millions)
|
Benefit obligation at January 1,
|
$
|
122.1
|
|
|
$
|
130.0
|
|
|
$
|
2.5
|
|
|
$
|
2.9
|
|
Service cost
|
0.3
|
|
|
0.8
|
|
|
—
|
|
|
—
|
|
Interest cost
|
4.8
|
|
|
4.6
|
|
|
0.1
|
|
|
0.1
|
|
Curtailments
|
1.2
|
|
|
0.1
|
|
|
—
|
|
|
—
|
|
Benefit payments
|
(6.2
|
)
|
|
(5.8
|
)
|
|
(0.9
|
)
|
|
(0.4
|
)
|
Plan amendments
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Actuarial loss (gain)
|
13.0
|
|
|
(7.6
|
)
|
|
0.9
|
|
|
(0.1
|
)
|
Benefit obligation at December 31,
|
$
|
135.2
|
|
|
$
|
122.1
|
|
|
$
|
2.6
|
|
|
$
|
2.5
|
|
Change in plan assets
|
|
|
|
|
|
|
|
Fair value of plan assets at January 1,
|
$
|
93.3
|
|
|
$
|
100.5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Actual return on plan assets
|
21.3
|
|
|
(7.1
|
)
|
|
—
|
|
|
—
|
|
Company contributions to the plan
|
5.5
|
|
|
5.7
|
|
|
0.9
|
|
|
0.4
|
|
Benefit payments
|
(6.2
|
)
|
|
(5.8
|
)
|
|
(0.9
|
)
|
|
(0.4
|
)
|
Fair value of plan assets at December 31,
|
113.9
|
|
|
93.3
|
|
|
—
|
|
|
—
|
|
Underfunded status (current and long-term)
|
$
|
(21.3
|
)
|
|
$
|
(28.8
|
)
|
|
$
|
(2.6
|
)
|
|
$
|
(2.5
|
)
|
Amounts recognized in balance sheets
|
|
|
|
|
|
|
|
Accounts payable and accrued expenses
|
$
|
(9.2
|
)
|
|
$
|
(1.1
|
)
|
|
$
|
(0.2
|
)
|
|
$
|
(0.2
|
)
|
Other long-term liabilities
|
(12.1
|
)
|
|
(27.7
|
)
|
|
(2.4
|
)
|
|
(2.3
|
)
|
Total amount recognized in balance sheet
|
$
|
(21.3
|
)
|
|
$
|
(28.8
|
)
|
|
$
|
(2.6
|
)
|
|
$
|
(2.5
|
)
|
Amounts recognized in AOCI
|
|
|
|
|
|
|
|
Net actuarial loss (gain)
|
$
|
15.7
|
|
|
$
|
19.4
|
|
|
$
|
0.4
|
|
|
$
|
(0.5
|
)
|
Prior service cost
|
—
|
|
|
0.4
|
|
|
—
|
|
|
(0.8
|
)
|
Total amount recognized in AOCI
|
$
|
15.7
|
|
|
$
|
19.8
|
|
|
$
|
0.4
|
|
|
$
|
(1.3
|
)
|
The following table sets forth the Company's Pension Plan, SERP and Medical Plan cost and amounts recognized in other comprehensive income (before tax) for the respective years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Plan and SERP benefits
|
|
Medical Plan benefits
|
|
2019
|
|
2018
|
|
2017
|
|
2019
|
|
2018
|
|
2017
|
Components of net periodic benefit cost
|
(in millions)
|
Service cost
|
$
|
0.3
|
|
|
$
|
0.8
|
|
|
$
|
0.8
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Interest cost
|
4.8
|
|
|
4.6
|
|
|
4.7
|
|
|
0.1
|
|
|
0.1
|
|
|
0.1
|
|
Expected return on plan assets
|
(5.9
|
)
|
|
(5.8
|
)
|
|
(5.4
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
Curtailment (gain) loss
|
2.0
|
|
|
0.3
|
|
|
0.7
|
|
|
(0.8
|
)
|
|
(0.2
|
)
|
|
—
|
|
Settlements
|
—
|
|
|
—
|
|
|
0.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Amortization of prior service costs
|
0.4
|
|
|
0.8
|
|
|
1.0
|
|
|
—
|
|
|
(0.3
|
)
|
|
(0.3
|
)
|
Amortization of actuarial loss
|
0.5
|
|
|
0.8
|
|
|
0.5
|
|
|
—
|
|
|
—
|
|
|
(0.1
|
)
|
Periodic expense
|
$
|
2.1
|
|
|
$
|
1.5
|
|
|
$
|
2.5
|
|
|
$
|
(0.7
|
)
|
|
$
|
(0.4
|
)
|
|
$
|
(0.3
|
)
|
Components recognized in accumulated other comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
Current period prior service cost
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(0.7
|
)
|
|
$
|
—
|
|
|
$
|
0.2
|
|
|
$
|
(2.5
|
)
|
Current period actuarial (gain) loss
|
(2.4
|
)
|
|
5.6
|
|
|
(7.5
|
)
|
|
0.9
|
|
|
(0.1
|
)
|
|
(0.1
|
)
|
Amortization of prior service cost
|
(0.4
|
)
|
|
(0.8
|
)
|
|
(1.0
|
)
|
|
0.8
|
|
|
0.3
|
|
|
0.3
|
|
Amortization of actuarial gain (loss)
|
(0.5
|
)
|
|
(0.8
|
)
|
|
(0.5
|
)
|
|
—
|
|
|
—
|
|
|
0.1
|
|
Loss on curtailment in current period
|
(0.8
|
)
|
|
(0.1
|
)
|
|
(0.3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
Settlements
|
—
|
|
|
—
|
|
|
(0.2
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
Total amount recognized in accumulated other comprehensive income
|
$
|
(4.1
|
)
|
|
$
|
3.9
|
|
|
$
|
(10.2
|
)
|
|
$
|
1.7
|
|
|
$
|
0.4
|
|
|
$
|
(2.2
|
)
|
The Company recognizes service costs related to SERP and Medical Plan benefits on the Consolidated Statements of Operations within "General and administrative" expense. All other expenses related to the Pension Plan, SERP and Medical Plan are recognized on the Consolidated Statements of Operations within "Interest and other income (expense)".
The estimated portion of net actuarial loss and net prior service cost for the Pension Plan and SERP that will be amortized from AOCI into net periodic benefit cost in 2020 is $0.8 million, which represents amortization of prior service cost recognized and actuarial losses. The estimated portion of net actuarial loss and net prior service cost for the Medical Plan that will be amortized from AOCI into net periodic benefit cost in 2020 is less than $0.1 million, which represents amortization of prior service cost recognized and actuarial losses. Amortization of prior service costs and actuarial gains or losses out of AOCI are recognized in the Consolidated Statements of Operations in "Interest and other income (expense)".
Following are the weighted-average assumptions (weighted by the plan level benefit obligation for pension benefits) used by the Company to calculate the Pension Plan, SERP and Medical Plan obligations at December 31, 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Plan and SERP benefits
|
|
Medical Plan benefits
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Discount rate
|
3.13
|
%
|
|
4.19
|
%
|
|
3.40
|
%
|
|
4.30
|
%
|
Rate of increase in compensation(1)
|
n/a
|
|
|
3.00
|
%
|
|
n/a
|
|
|
n/a
|
|
_______________________
|
|
(1)
|
The Pension Plan was frozen effective January 1, 2016, and as a result, the rate of increase in compensation for participants is no longer considered an assumption used by the Company to calculate the value of the Pension Plan. As such, for the year ended December 31, 2018, the rate of increase in compensation is only used for the SERP. For the year ended December 31, 2019, there are no longer any eligible participants in the SERP. As such, the rate of increase in compensation is no longer considered an assumption used to calculate the value of the SERP.
|
The discount rate assumptions used by the Company represents an estimate of the interest rate at which the Pension Plan, SERP and Medical Plan obligations could effectively be settled on the measurement date.
Following are the weighted-average assumptions (weighted by the net period benefit cost for pension benefits) used by the Company in determining the net periodic Pension Plan, SERP and Medical Plan cost for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Plan and SERP benefits
|
|
Medical Plan benefits
|
|
2019
|
|
2018
|
|
2017
|
|
2019
|
|
2018
|
|
2017
|
Discount rate
|
4.19
|
%
|
|
3.50
|
%
|
|
4.00
|
%
|
|
4.30
|
%
|
|
3.60
|
%
|
|
4.10
|
%
|
Expected long-term return on plan assets
|
5.70
|
%
|
|
6.00
|
%
|
|
6.00
|
%
|
|
n/a
|
|
|
n/a
|
|
|
n/a
|
|
Rate of increase in compensation(1)
|
3.00
|
%
|
|
3.50
|
%
|
|
3.50
|
%
|
|
n/a
|
|
|
n/a
|
|
|
3.50
|
%
|
_______________________
|
|
(1)
|
The Pension Plan was frozen effective January 1, 2016, and as a result, the rate of increase in compensation for participants is no longer considered an assumption used by the Company to calculate the net period benefit cost of the Pension Plan. As such, for the years ended December 31, 2019 and 2018, the rate of increase in compensation is only used for the SERP.
|
In selecting the assumption for expected long-term rate of return on assets, the Company considers the average rate of return expected on the funds to be invested to provide benefits. This includes considering the plan's asset allocation, historical returns on these types of assets, the current economic environment and the expected returns likely to be earned over the life of the plan. No plan assets are expected to be returned to the Company in 2020. Historical health care cost trend rates are not applicable to the Company, because the Company's medical costs are capped at a fixed amount. As the Company's medical costs are capped at a fixed amount, the sensitivity to increases and decreases in the health-care inflation rate is not applicable.
Plan Assets
The Company's Employee Benefits Committee (EBC) oversees investment of qualified pension plan assets. The EBC uses a third-party asset manager to assist in setting targeted-policy ranges for the allocation of assets among various investment categories. The EBC allocates pension plan assets among broad asset categories and reviews the asset allocation at least annually. Asset allocation decisions consider risk and return, future-benefit requirements, participant growth and other expected cash flows. These characteristics affect the level, risk and expected growth of postretirement-benefit assets. The EBC uses asset-mix guidelines that include targets for each asset category, return objectives for each asset group and the desired level of diversification and liquidity. These guidelines may change from time to time based on the EBC's ongoing evaluation of each plan's risk tolerance. The EBC estimates an expected overall long-term rate of return on assets by weighting expected returns of each asset class by its targeted asset allocation percentage. Expected return estimates are developed from analysis of past performance and forecasts of long-term return expectations by third-parties. Responsibility for individual security selection rests with each investment manager, who is subject to guidelines specified by the EBC. The EBC sets performance objectives for each investment manager that are expected to be met over a three-year period or a complete market cycle, whichever is shorter. Performance and risk levels are regularly monitored to confirm policy compliance and that results are within expectations. Performance for each investment is measured relative to the appropriate index benchmark for its category. QEP securities may be considered for purchase at an investment manager's discretion, but within limitations prescribed by the Employee Retirement Income Security Act of 1974 (ERISA) and other laws. There was no direct investment in QEP shares for the periods disclosed. The majority of retirement-benefit assets were invested as follows:
Equity securities: Domestic equity assets were invested in a combination of index funds and actively managed products, with a diversification goal representative of the whole U.S. stock market. International equity securities consisted of developed and emerging market foreign equity assets that were invested in funds that hold a diversified portfolio of common stocks of corporations in developed and emerging foreign countries.
Debt securities: Investment grade intermediate-term debt assets are invested in funds holding a diversified portfolio of debt of governments, corporations and mortgage borrowers with average maturities of five to ten years and investment grade credit ratings. Investment grade long-term debt assets are invested in a diversified portfolio of debt of corporate and non-corporate issuers, with an average maturity of more than ten years and investment grade credit ratings. High yield and bank loan assets are held in funds holding a diversified portfolio of these instruments with an average maturity of five to seven years.
Although the actual allocation to cash and short-term investments is minimal (less than 5%), larger cash allocations may be held from time to time if deemed necessary for operational aspects of the retirement plan. Cash is invested in a high-quality, short-term temporary investment fund that purchases investment-grade quality short-term debt issued by governments and corporations.
The EBC made the decision to invest all of the retirement plan assets in commingled funds as these funds typically have lower expense ratios and are more tax efficient than mutual funds. These investments are public investment vehicles valued using the net asset value (NAV) as a practical expedient. The NAV is based on the underlying assets owned by the fund excluding transaction costs and minus liabilities, which can be traced back to observable asset values. No assets held by the Pension Plan that were valued using the NAV methodology were subject to redemption restrictions on their valuation date. These commingled funds are audited annually by an independent accounting firm.
The following table summarizes investments for which fair value is measured using the NAV per share practical expedient as of December 31, 2019 and 2018, respectively:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2019
|
|
December 31, 2018
|
|
Total
|
|
Percentage of total
|
|
Total
|
|
Percentage of total
|
|
(in millions, except percentages)
|
Cash and short-term investments
|
$
|
0.6
|
|
|
1
|
%
|
|
$
|
0.7
|
|
|
1
|
%
|
Equity securities:
|
|
|
|
|
|
|
|
Domestic
|
30.6
|
|
|
27
|
%
|
|
20.7
|
|
|
22
|
%
|
International
|
10.5
|
|
|
9
|
%
|
|
10.0
|
|
|
11
|
%
|
Fixed income
|
72.2
|
|
|
63
|
%
|
|
61.9
|
|
|
66
|
%
|
Total investments
|
$
|
113.9
|
|
|
100
|
%
|
|
$
|
93.3
|
|
|
100
|
%
|
Expected Benefit Payments
As of December 31, 2019, the following future benefit payments are expected to be paid:
|
|
|
|
|
|
|
|
|
|
Pension Plan and SERP benefits
|
|
Medical Plan benefits
|
|
(in millions)
|
2020
|
$
|
15.1
|
|
|
$
|
0.2
|
|
2021
|
$
|
8.9
|
|
|
$
|
0.2
|
|
2022
|
$
|
9.0
|
|
|
$
|
0.2
|
|
2023
|
$
|
7.6
|
|
|
$
|
0.2
|
|
2024
|
$
|
7.5
|
|
|
$
|
0.1
|
|
2025 through 2029
|
$
|
31.8
|
|
|
$
|
0.5
|
|
Employee Investment Plan
QEP employees may participate in the QEP Employee Investment Plan, a defined-contribution plan (401(k) Plan). The 401(k) Plan allows eligible employees to make investments, including purchasing shares of QEP common stock, through payroll deduction at the current fair market value on the transaction date. Both employees and QEP make contributions to the 401(k) Plan. The Company may contribute a discretionary portion beyond the Company's matching contribution to employees not in the Pension Plan or SERP. During the years ended December 31, 2019, 2018 and 2017, the Company made contributions of $3.6 million, $5.8 million and $6.0 million to the 401(k) Plan, respectively. The Company recognizes expense equal to its yearly contributions. Due to the Company's strategic initiatives, the amount expected to be contributed to the 401(k) Plan is subject to change. Participants receive 100% employer matching contributions on participant 401(k) plan contributions up to a percentage of qualifying earnings as described below.
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2019
|
|
2018
|
|
2017
|
Employees who do not accrue a benefit in the SERP
|
|
|
|
|
|
Maximum employer matching of qualifying earnings
|
8
|
%
|
|
8
|
%
|
|
8
|
%
|
|
|
|
|
|
|
Employees who accrue a benefit in the SERP
|
|
|
|
|
|
Maximum employer matching of qualifying earnings
|
6
|
%
|
|
6
|
%
|
|
6
|
%
|
As a result of freezing benefits under the Pension Plan, the 401(k) Plan and a nonqualified, unfunded deferred compensation plan (the Wrap Plan), were amended to allow the Company to make discretionary contributions in the form of Company Transition Credits to eligible participants. Eligible participants are certain highly and non-highly compensated employees who were active participants in the Pension Plan on December 31, 2015. During the years ended December 31, 2019, 2018 and 2017, the Company made a discretionary contribution of less than $0.1 million, $0.3 million and $0.4 million, respectively, to active participants of the Pension Plan.
Note 14 – Income Taxes
In December 2017 the Tax Legislation was signed into law, which resulted in significant changes to U.S. federal income tax law. QEP expects that these changes will positively impact QEP's future after-tax earnings in the U.S., primarily due to the lower federal statutory tax rate of 21% compared to 35%. The impact of the Tax Legislation may differ from the statements above due to, among other things, changes in interpretations and assumptions the Company has made and actions the Company may take as a result of the Tax Legislation. Additionally, guidance issued by the relevant regulatory authorities regarding the Tax Legislation may materially impact QEP's financial statements. As additional guidance to the Tax Legislation is published in the form of Treasury Regulations and other IRS communications, the Company will monitor, assess, and determine the impact of these communications on the Company's consolidated financial statements and operations.
Details of income tax provisions and deferred income taxes from continuing operations are provided in the following tables.
The components of income tax provisions and benefits were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2019
|
|
2018
|
|
2017
|
Federal income tax provision (benefit)
|
(in millions)
|
Current
|
$
|
(32.2
|
)
|
|
$
|
(71.3
|
)
|
|
$
|
2.1
|
|
Deferred
|
55.7
|
|
|
(257.8
|
)
|
|
(339.8
|
)
|
State income tax provision (benefit)
|
|
|
|
|
|
Current
|
(15.1
|
)
|
|
1.5
|
|
|
0.5
|
|
Deferred
|
(51.4
|
)
|
|
10.2
|
|
|
25.0
|
|
Total income tax provision (benefit)
|
$
|
(43.0
|
)
|
|
$
|
(317.4
|
)
|
|
$
|
(312.2
|
)
|
The difference between the statutory federal income tax rate and the Company's effective income tax rate is explained as follows:
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2019
|
|
2018
|
|
2017
|
Federal income taxes statutory rate(1)
|
21.0
|
%
|
|
21.0
|
%
|
|
35.0
|
%
|
Increase (decrease) in rate as a result of:
|
|
|
|
|
|
State income taxes, net of federal income tax benefit
|
(2.5
|
)%
|
|
4.1
|
%
|
|
44.3
|
%
|
Federal rate change(1)
|
—
|
%
|
|
—
|
%
|
|
741.3
|
%
|
State rate change(2)
|
20.9
|
%
|
|
(2.9
|
)%
|
|
2.1
|
%
|
Valuation allowance(3)
|
(18.0
|
)%
|
|
(1.9
|
)%
|
|
(84.4
|
)%
|
Permanent adjustments(4)
|
(7.1
|
)%
|
|
(0.1
|
)%
|
|
(0.4
|
)%
|
Return to provision adjustment
|
2.7
|
%
|
|
(0.1
|
)%
|
|
(0.7
|
)%
|
Uncertain tax provision(5)
|
13.6
|
%
|
|
—
|
%
|
|
(7.7
|
)%
|
AMT Credit Reclass due to NOL Carryback(6)
|
—
|
%
|
|
3.8
|
%
|
|
(1.8
|
)%
|
Effective income tax rate
|
30.6
|
%
|
|
23.9
|
%
|
|
727.7
|
%
|
____________________________
|
|
(1)
|
The Tax Legislation changed the federal corporate income tax rate from 35% to 21% starting in 2018. The rate change caused the Company to revalue its deferred tax liabilities and assets as of December 31, 2017 from a 35% to 21% federal corporate income tax rate which caused the majority of the change in rate.
|
|
|
(2)
|
During the year ended December 31, 2019, the state rate change was primarily the result of the re-measurement of QEP's deferred tax assets and liabilities at a lower blended state tax rate due to exiting the state of Louisiana.
|
|
|
(3)
|
During the year ended December 31, 2019, the Company recognized an additional valuation allowance of $25.3 million on its Louisiana state NOL. The Company does not expect that it will have sufficient taxable income to utilize the state NOL it is carrying forward due to the Haynesville Divestiture. During the years ended December 31, 2018 and 2017, the Company also increased its valuation allowance by $25.5 million and $36.2 million, respectively, against its Louisiana net operating loss as the Company did not forecast sufficient taxable income to utilize the entire net operating loss in Louisiana at December 31, 2018 and 2017.
|
|
|
(4)
|
During the year ended December 31, 2019, the permanent items primarily related to disallowed officer compensation under Section 162(m) of the Internal Revenue Code of $6.1 million and share-based compensation shortfalls of $4.0 million.
|
|
|
(5)
|
During the year ended December 31, 2019, the Company recognized a tax benefit of $19.0 million due to the expiration of the statute of limitations related to the Company's uncertain tax position. During the year ended December 31, 2017 the decrease in the tax rate was due to the federal corporate income tax rate change related to the Tax Legislation.
|
|
|
(6)
|
During the year ended December 31, 2018, QEP agreed to an IRS proposed change to the initial treatment of the 2016 carryback of net operating losses (NOL). This change resulted in a reduction of available NOL carryforwards valued at $75.7 million and an increase in AMT credit carryforwards of $126.0 million. The net change in value of $50.3 million was recorded in deferred income taxes.
|
Significant components of the Company's deferred income taxes were as follows:
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2019
|
|
2018
|
Deferred tax liabilities
|
(in millions)
|
Property, plant and equipment
|
$
|
592.9
|
|
|
$
|
665.1
|
|
Commodity price derivatives
|
—
|
|
|
30.1
|
|
Operating lease right-of-use assets
|
12.7
|
|
|
—
|
|
Other
|
0.9
|
|
|
2.6
|
|
Total deferred tax liabilities
|
606.5
|
|
|
697.8
|
|
Deferred tax assets
|
|
|
|
NOL and tax credit carryforwards
|
$
|
337.7
|
|
|
$
|
467.9
|
|
State NOL valuation allowance
|
(98.8
|
)
|
|
(82.3
|
)
|
Employee benefits and compensation costs
|
22.3
|
|
|
33.2
|
|
Interest carryforward(1)
|
45.7
|
|
|
—
|
|
Commodity price derivatives
|
3.9
|
|
|
—
|
|
Operating lease liabilities
|
14.1
|
|
|
—
|
|
Other
|
7.1
|
|
|
9.8
|
|
Total deferred tax assets
|
332.0
|
|
|
428.6
|
|
Net deferred income tax liability
|
$
|
274.5
|
|
|
$
|
269.2
|
|
Balance sheet classification
|
|
|
|
Deferred income tax liability – noncurrent
|
274.5
|
|
|
269.2
|
|
Net deferred income tax liability
|
$
|
274.5
|
|
|
$
|
269.2
|
|
____________________________
|
|
(1)
|
During the year ended December 31, 2019, the amount of interest the Company could deduct was limited under Section 163(j) of the Internal Revenue Code. This interest can be carried forward indefinitely to offset future taxable income within the code limitations.
|
The tax effected amounts and expiration dates of NOL and tax credit carryforwards at December 31, 2019, are as follows:
|
|
|
|
|
|
|
|
Expiration Dates
|
|
Amounts
|
|
|
|
(in millions)
|
State NOL and tax credit carryforwards
|
2020-2038
|
|
$
|
114.7
|
|
U.S. NOL(1)
|
2037-Indefinite
|
|
182.1
|
|
U.S. alternative minimum tax credit
|
Indefinite
|
|
37.1
|
|
General business credits
|
2036-2037
|
|
3.8
|
|
Total NOL and tax credit carryforwards
|
|
|
$
|
337.7
|
|
____________________________
|
|
(1)
|
Federal NOL's created in tax years beginning after December 31, 2017 can be carried forward indefinitely under the Tax Legislation (limited to 80% of taxable income computed without the NOL deduction). Of the Company's U.S. NOL, $54.5 million has an indefinite carryforward period but its use is limited to 80% of taxable income.
|
The Company assesses the available evidence to determine if sufficient future taxable income will be generated to use the existing deferred tax assets. The Company maintains a valuation allowance to offset the uncertain realization of certain of its state NOL's. The Company had a valuation allowance of $98.8 million and $82.3 million for the years ended December 31, 2019 and 2018, respectively, for state NOL's outside of our current core operations and primarily relate to state NOL's in Colorado, Louisiana, Utah and Oklahoma. Due to the various divestitures over the last several years, and focus of our operations, we do not expect to have sufficient taxable income in these states to utilize the NOL's we are carrying forward.
The Tax Legislation eliminated corporate AMT which allowed QEP the ability to offset its regular tax liability or claim refunds for taxable years 2018 through 2021 for AMT credits carried forward from prior years. The Company received $73.9 million of AMT credit refunds in 2019 and anticipates it will realize approximately $74.6 million in AMT credit refunds over the next three years with $37.5 million expected to be realized in 2020 for tax years 2018 and 2019, which is shown in "Income tax receivable" with the remaining $37.1 million included in "Deferred income taxes" on the Consolidated Balance Sheet as of December 31, 2019.
Pursuant to Section 382 and 383 of the Internal Revenue Code, utilization of the Company’s NOL's and credits may be subject to annual limitations in the event of any significant future changes in its ownership structure. These annual limitations may result in the expiration of NOL's and credits prior to utilization.
The Company files income tax returns in the U.S. federal jurisdiction and various state jurisdictions. For federal tax purposes, the Company has been a participant in the IRS Compliance Assurance Process through the 2018 tax year, which provides examination of the tax return prior to filing. Generally, for state tax purposes, the Company’s 2016 through 2018 tax years remain open for examination by the taxing authorities under a three-year statute of limitations. Should the Company utilize any of its state loss carryforwards, their carryforward losses would be subject to examination.
Unrecognized Tax Benefit
The benefits of uncertain tax positions taken or expected to be taken on income tax returns is recognized in the Consolidated Financial Statements at the largest amount that is more likely than not to be sustained upon examination by the relevant taxing authorities. As of December 31, 2018, QEP had $19.0 million of unrecognized tax benefit related to uncertain tax positions for asset sales that occurred in 2014, which were recorded within "Other long-term liabilities" on the Consolidated Balance Sheets.
During the year ended December 31, 2019, the statute of limitations related to the Company's uncertain tax position expired, and upon expiration, the Company recognized a $19.0 million tax benefit as well as recorded a $4.1 million reduction in "Interest expense" and a $2.5 million reduction in "General and administrative" expense on the Consolidated Statements of Operations related to accrued interest and penalties that were recorded in prior periods. During the years ended December 31, 2018 and 2017, the Company incurred $0.7 million of estimated interest expense related to uncertain tax positions.
The following is a reconciliation of our beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
Unrecognized Tax Benefits
|
|
2019
|
|
2018
|
|
(in millions)
|
Balance as of January 1,
|
$
|
19.0
|
|
|
$
|
19.0
|
|
Recognized tax benefits
|
(19.0
|
)
|
|
—
|
|
Balance as of December 31,
|
$
|
—
|
|
|
$
|
19.0
|
|
Note 15 – Quarterly Financial Information (unaudited)
The following table provides a summary of unaudited quarterly financial information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
Second Quarter
|
|
Third Quarter
|
|
Fourth Quarter
|
|
Year
|
2019
|
(in millions, except per share amounts or otherwise specified)
|
Revenues
|
$
|
280.6
|
|
|
$
|
296.2
|
|
|
$
|
307.5
|
|
|
$
|
321.9
|
|
|
$
|
1,206.2
|
|
Operating income (loss)
|
$
|
(15.8
|
)
|
|
$
|
72.3
|
|
|
$
|
52.1
|
|
|
$
|
48.9
|
|
|
$
|
157.5
|
|
Net income (loss)
|
$
|
(116.7
|
)
|
|
$
|
48.8
|
|
|
$
|
81.0
|
|
|
$
|
(110.4
|
)
|
|
$
|
(97.3
|
)
|
Net gain (loss) from asset sales, inclusive of restructuring costs and impairment
|
$
|
(18.2
|
)
|
|
$
|
17.8
|
|
|
$
|
(2.1
|
)
|
|
$
|
1.4
|
|
|
$
|
(1.1
|
)
|
Per share information
|
|
|
|
|
|
|
|
|
|
Basic EPS
|
$
|
(0.49
|
)
|
|
$
|
0.20
|
|
|
$
|
0.34
|
|
|
$
|
(0.46
|
)
|
|
$
|
(0.41
|
)
|
Diluted EPS
|
$
|
(0.49
|
)
|
|
$
|
0.20
|
|
|
$
|
0.34
|
|
|
$
|
(0.46
|
)
|
|
$
|
(0.41
|
)
|
Production information
|
|
|
|
|
|
|
|
|
|
Total equivalent production (Mboe)
|
7,806.3
|
|
|
7,534.7
|
|
|
8,404.0
|
|
|
8,465.3
|
|
|
32,210.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
|
|
|
|
|
|
|
Revenues
|
$
|
428.9
|
|
|
$
|
532.4
|
|
|
$
|
560.8
|
|
|
$
|
410.5
|
|
|
$
|
1,932.6
|
|
Operating income (loss)
|
$
|
21.4
|
|
|
$
|
(321.8
|
)
|
|
$
|
156.8
|
|
|
$
|
(1,116.8
|
)
|
|
$
|
(1,260.4
|
)
|
Net income (loss)
|
$
|
(53.6
|
)
|
|
$
|
(336.0
|
)
|
|
$
|
7.3
|
|
|
$
|
(629.3
|
)
|
|
$
|
(1,011.6
|
)
|
Net gain (loss) from asset sales, inclusive of restructuring costs and impairment
|
$
|
2.8
|
|
|
$
|
(407.6
|
)
|
|
$
|
27.1
|
|
|
$
|
(1,158.2
|
)
|
|
$
|
(1,535.9
|
)
|
Per share information
|
|
|
|
|
|
|
|
|
|
Basic EPS
|
$
|
(0.22
|
)
|
|
$
|
(1.42
|
)
|
|
$
|
0.03
|
|
|
$
|
(2.66
|
)
|
|
$
|
(4.25
|
)
|
Diluted EPS
|
$
|
(0.22
|
)
|
|
$
|
(1.42
|
)
|
|
$
|
0.03
|
|
|
$
|
(2.66
|
)
|
|
$
|
(4.25
|
)
|
Production information
|
|
|
|
|
|
|
|
|
|
Total equivalent production (Mboe)
|
11,724.6
|
|
|
14,106.1
|
|
|
14,400.0
|
|
|
11,627.2
|
|
|
51,857.9
|
|
Note 16 – Supplemental Oil and Gas Information (unaudited)
The Company is making the following supplemental disclosures of oil and gas producing activities, in accordance with ASC 932, Extractive Activities – Oil and Gas, as amended by ASU 2010-03, Oil and Gas Reserve Estimation and Disclosures, and SEC Regulation S-X. The Company uses the successful efforts accounting method for its oil and gas exploration and development activities.
Capitalized Costs
The aggregate amounts of costs capitalized for oil and gas exploration and development activities and the related amounts of accumulated depreciation, depletion and amortization are shown below and includes capitalized costs classified as “Noncurrent assets held for sale” on the Consolidated Balance Sheets:
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2019
|
|
2018
|
|
(in millions)
|
Proved properties
|
$
|
9,574.9
|
|
|
$
|
12,140.7
|
|
Unproved properties, net
|
599.1
|
|
|
759.1
|
|
Total proved and unproved properties
|
10,174.0
|
|
|
12,899.8
|
|
Accumulated depreciation, depletion and amortization
|
(5,250.5
|
)
|
|
(7,450.5
|
)
|
Net capitalized costs
|
$
|
4,923.5
|
|
|
$
|
5,449.3
|
|
Costs Incurred
The costs incurred in oil and gas acquisition, exploration and development activities are displayed in the table below. Costs associated with the Company's midstream and corporate activities are not included. Development costs are net of the change in accrued capital costs of $12.2 million and ARO additions and revisions of $1.2 million during the year ended December 31, 2019. The costs incurred for the development of reserves that were classified as proved undeveloped were approximately $426.1 million in 2019, $606.5 million in 2018 and $389.3 million in 2017.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2019
|
|
2018
|
|
2017
|
|
(in millions)
|
Proved property acquisitions
|
$
|
1.5
|
|
|
$
|
39.1
|
|
|
$
|
269.6
|
|
Unproved property acquisitions
|
2.0
|
|
|
25.8
|
|
|
532.4
|
|
Other acquisitions
|
—
|
|
|
0.8
|
|
|
13.2
|
|
Exploration costs (capitalized and expensed)
|
0.1
|
|
|
0.3
|
|
|
32.7
|
|
Development costs
|
556.2
|
|
|
1,133.1
|
|
|
1,189.3
|
|
Total costs incurred
|
$
|
559.8
|
|
|
$
|
1,199.1
|
|
|
$
|
2,037.2
|
|
Results of Operations
Following are the results of operations of QEP's oil and gas producing activities, before allocated corporate overhead and interest expenses. Revenues and expenses relating to the Company's midstream and corporate activities are not included.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2019
|
|
2018
|
|
2017
|
|
(in millions)
|
Revenues
|
$
|
1,200.6
|
|
|
$
|
1,920.3
|
|
|
$
|
1,548.1
|
|
Production costs
|
361.9
|
|
|
507.3
|
|
|
675.4
|
|
Exploration expenses
|
0.1
|
|
|
0.3
|
|
|
22.0
|
|
Depreciation, depletion and amortization
|
528.5
|
|
|
836.4
|
|
|
735.1
|
|
Impairment
|
—
|
|
|
1,560.9
|
|
|
72.3
|
|
Total expenses
|
890.5
|
|
|
2,904.9
|
|
|
1,504.8
|
|
Income (loss) before income taxes
|
310.1
|
|
|
(984.6
|
)
|
|
43.3
|
|
Income tax benefit (expense)
|
(69.5
|
)
|
|
243.2
|
|
|
(16.0
|
)
|
Results of operations from producing activities excluding allocated corporate overhead and interest expenses
|
$
|
240.6
|
|
|
$
|
(741.4
|
)
|
|
$
|
27.3
|
|
Estimated Quantities of Proved Oil and Gas Reserves
Estimates of proved oil and gas reserves have been completed in accordance with professional engineering standards and the Company's established internal controls, which include the oversight of a multi-functional Reserves Review Committee reporting to the Company's Audit Committee of the Board of Directors. The Company retained Ryder Scott Company, L.P. (RSC), independent oil and gas reserve evaluation engineering consultants, to prepare the estimates of all of its proved reserves as of December 31, 2019, 2018 and 2017. The estimated proved reserves have been prepared in accordance with the SEC's Regulation S-X and ASC 932 as amended. The individuals performing reserves estimates possess professional qualifications and demonstrate competency in reserves estimation and evaluation. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.
All of QEP's proved undeveloped reserves at December 31, 2019, are scheduled to be developed within five years from the date such locations were initially disclosed as proved undeveloped reserves. The Company plans to continue development of its leaseholds and anticipates that it will have the financial capability to continue development in the manner estimated. While the majority of QEP's PUD reserves are located on leaseholds that are held by production, any PUD locations on expiring leaseholds are scheduled for development during the primary term of the lease.
As of December 31, 2019, all of the Company's oil and gas reserves are attributable to properties within the United Sates. A summary of the Company's changes in quantities of proved oil and condensate, gas and NGL reserves for the years ended December 31, 2017, 2018 and 2019 are as follows:
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Oil and condensate
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Gas
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NGL
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Total(13)
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(MMbbl)
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(Bcf)
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(MMbbl)
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(MMboe)
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Balance at December 31, 2016
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238.6
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|
|
2,553.8
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|
|
67.2
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|
|
731.4
|
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Revisions of previous estimates(1)
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3.7
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|
|
12.5
|
|
|
(3.1
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)
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2.7
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Extensions and discoveries(2)
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59.1
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|
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101.9
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|
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10.4
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86.4
|
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Purchase of reserves in place(3)
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46.6
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|
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125.5
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|
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8.7
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|
|
76.3
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Sale of reserves in place(4)
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(7.9
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)
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(831.2
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)
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(12.6
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)
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(159.0
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)
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Production
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(19.6
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)
|
|
(168.9
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)
|
|
(5.4
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)
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|
(53.1
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)
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Balance at December 31, 2017
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320.5
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|
1,793.6
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|
|
65.2
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|
|
684.7
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Revisions of previous estimates(5)
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2.1
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|
|
314.0
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6.7
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61.0
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Extensions and discoveries(6)
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57.1
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56.5
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9.8
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76.3
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Purchase of reserves in place(7)
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8.2
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7.9
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1.3
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10.9
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Sale of reserves in place(8)
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(24.9
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)
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(544.8
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)
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(7.1
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)
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(122.8
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)
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Production
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(23.9
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)
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(139.6
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)
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(4.7
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)
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(51.9
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)
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Balance at December 31, 2018
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339.1
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|
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1,487.6
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71.2
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658.2
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Revisions of previous estimates(9)
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(94.9
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)
|
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(23.0
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)
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(8.7
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)
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(107.3
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)
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Extensions and discoveries(10)
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33.6
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40.0
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7.4
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47.6
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Purchase of reserves in place(11)
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3.6
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4.0
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0.7
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4.9
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Sale of reserves in place(12)
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(4.9
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)
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(1,102.2
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)
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(0.3
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)
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(188.9
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)
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Production
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(21.6
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)
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(33.1
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)
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(5.1
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)
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(32.2
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)
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Balance at December 31, 2019
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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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Proved developed reserves
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|
|
|
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Balance at December 31, 2016
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103.2
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|
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1,309.8
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|
|
35.7
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|
|
357.2
|
|
Balance at December 31, 2017
|
116.0
|
|
|
655.5
|
|
|
27.9
|
|
|
253.1
|
|
Balance at December 31, 2018
|
133.6
|
|
|
382.3
|
|
|
31.5
|
|
|
228.9
|
|
Balance at December 31, 2019
|
117.5
|
|
|
217.0
|
|
|
36.7
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|
|
190.4
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Proved undeveloped reserves
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Balance at December 31, 2016
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135.4
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|
|
1,244.0
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|
|
31.5
|
|
|
374.2
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Balance at December 31, 2017
|
204.5
|
|
|
1,138.1
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|
|
37.3
|
|
|
431.6
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Balance at December 31, 2018
|
205.5
|
|
|
1,105.3
|
|
|
39.7
|
|
|
429.3
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Balance at December 31, 2019
|
137.4
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|
|
156.3
|
|
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28.5
|
|
|
191.9
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___________________________
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(1)
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Revisions of previous estimates in 2017 include 2.7 MMboe of positive revisions, primarily related to 32.0 MMboe of positive revisions related to pricing, driven by higher oil, gas and NGL prices and 2.2 MMboe of positive performance revisions. These positive revisions were partially offset by 11.0 MMboe of negative revisions related to higher operating costs and 20.5 MMboe of other revisions primarily from changing to a horizontal development plan from a vertical well development plan in the Uinta Basin and increased longer laterals in Haynesville/Cotton Valley. These negative other revisions are partially offset by positive other revisions from successful infill drilling in Haynesville/Cotton Valley and the Williston Basin.
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(2)
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Extensions and discoveries in 2017 primarily related to new well completions and associated new PUD locations in the Permian Basin.
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(3)
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Purchase of reserves in place in 2017 was primarily related to QEP's 2017 Permian Basin Acquisition and various other acquired oil and gas properties as discussed in Note 3 – Acquisitions and Divestitures.
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(4)
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Sale of reserves in place in 2017 was primarily related to QEP's Pinedale Divestiture as discussed in Note 3 – Acquisitions and Divestitures.
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(5)
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Revisions of previous estimates in 2018 totaling 61.0 MMboe of positive revisions include 23.4 MMboe of other revisions, primarily related to changing our development plans in the Haynesville/Cotton Valley; 17.3 MMboe of
|
positive revisions related to pricing, primarily driven by higher oil prices; 11.7 MMboe of positive revisions related to lower operating costs; and 8.7 MMboe of positive performance revisions.
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(6)
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Extensions and discoveries in 2018 primarily related to new well completions and associated new PUD locations in the Permian Basin.
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(7)
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Purchase of reserves in place in 2018 primarily relates to the additional acquisitions in the Permian Basin as discussed in Note 3 – Acquisitions and Divestitures.
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(8)
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Sale of reserves in place in 2018 was primarily related to QEP's Uinta Basin Divestiture as discussed in Note 3 – Acquisitions and Divestitures.
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(9)
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Revisions of previous estimates in 2019 totaling 107.3 MMboe of negative revisions includes 44.5 MMboe of negative PUD revisions as a result of changes to the development sequence in the Permian Basin, to maximize capital efficiency (see offset in extensions and discoveries footnote 10 below); 25.8 MMboe of PUD removals, primarily in the Williston Basin, that will not be developed within five years of the initial date of booking due to the reduction in future capital expenditures; 17.0 MMboe of negative revisions related to pricing, primarily driven by lower oil prices; 13.7 MMboe of negative performance revisions, primarily associated with updated volume projections for high-density wells and certain undrilled locations in the Permian Basin; 10.9 MMboe of other negative revisions, partially offset by 4.6 MMboe of positive revisions related to lower operating costs.
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(10)
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Extensions and discoveries in 2019 primarily related to new PUD locations in the Permian Basin due to changes in the development sequence in the Permian Basin to maximize capital efficiency. See partial offset in revisions to previous estimates in footnote 9 above.
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(11)
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Purchase of reserves in place in 2019 primarily relates to the additional acquisitions in the Permian Basin as discussed in Note 3 – Acquisitions and Divestitures.
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(12)
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Sale of reserves in place in 2019 was primarily related to QEP's Haynesville Divestiture as discussed in Note 3 – Acquisitions and Divestitures.
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(13)
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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.
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Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves
Future net cash flows were calculated at December 31, 2019, 2018 and 2017, by applying prices, which were the simple average of the first-of-the-month commodity prices, adjusted for location and quality differentials, for each of the 12 months during 2019, 2018 and 2017, with consideration of known contractual price changes. The prices used do not include any impact of QEP's commodity derivatives portfolio. The following table provides the average benchmark prices per unit, before location and quality differential adjustments, used to calculate the related reserve category:
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For the year ended December 31,
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2019
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2018
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|
2017
|
Average benchmark price per unit:
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Oil price (per bbl)
|
$
|
55.51
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|
|
$
|
65.56
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|
|
$
|
51.34
|
|
Gas price (per MMBtu)
|
$
|
2.58
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|
|
$
|
3.10
|
|
|
$
|
2.98
|
|
Year ended operating expenses, development costs and appropriate statutory income tax rates, with consideration of future tax rates, were used to compute the future net cash flows. All cash flows were discounted at 10% to reflect the time value of cash flows, without regard to the risk of specific properties. The estimated future costs to develop proved undeveloped reserves are approximately $435.0 million in 2020, $458.6 million in 2021 and $449.5 million in 2022. Estimated future development costs include capital spending on major development projects, some of which will take several years to complete. QEP believes cash flow from its operating activities, cash on hand and borrowings under its revolving credit facility will be sufficient to cover these estimated future development costs.
The assumptions used to derive the standardized measure of discounted future net cash flows are those required by accounting standards and do not necessarily reflect the Company's expectations. The information may be useful for certain comparative purposes but should not be solely relied upon in evaluating QEP or its performance. Furthermore, information contained in the following table may not represent realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Company's reserves. Management believes that the following factors should be considered when reviewing the information below:
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•
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Future commodity prices received for selling the Company's net production will likely differ from those required to be used in these calculations.
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•
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Future operating and capital costs will likely differ from those required to be used in these calculations and do not reflect cost savings of Company owned midstream operations on future operating expenses.
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•
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Future market conditions, government regulations, reservoir conditions and risks inherent in the production of oil and condensate and gas may cause production rates in future years to vary significantly from those rates used in the calculations.
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•
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Future revenues may be subject to different production, severance and property taxation rates.
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•
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The selection of a 10% discount rate is arbitrary and may not be a reasonable factor in adjusting for future economic conditions or in considering the risk that is part of realizing future net cash flows from the reserves.
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The standardized measure of discounted future net cash flows relating to proved reserves is presented in the table below:
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|
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Year Ended December 31,
|
|
2019
|
|
2018
|
|
2017
|
|
(in millions)
|
Future cash inflows
|
$
|
14,447.6
|
|
|
$
|
26,482.6
|
|
|
$
|
22,028.9
|
|
Future production costs
|
(6,070.6
|
)
|
|
(9,539.9
|
)
|
|
(9,074.2
|
)
|
Future development costs(1)
|
(2,275.2
|
)
|
|
(4,441.5
|
)
|
|
(4,726.0
|
)
|
Future income tax expenses(2)
|
(845.8
|
)
|
|
(2,553.6
|
)
|
|
(1,439.1
|
)
|
Future net cash flows
|
5,256.0
|
|
|
9,947.6
|
|
|
6,789.6
|
|
10% annual discount for estimated timing of net cash flows
|
(2,579.7
|
)
|
|
(4,991.9
|
)
|
|
(3,692.3
|
)
|
Standardized measure of discounted future net cash flows
|
$
|
2,676.3
|
|
|
$
|
4,955.7
|
|
|
$
|
3,097.3
|
|
___________________________
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|
(1)
|
Future development costs include future abandonment and salvage costs.
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|
|
(2)
|
The standardized measure of discounted future net cash flows for the year ended December 31, 2019, 2018 and 2017, were estimated assuming a 21% federal tax rate from the Tax Legislation enacted in December 2017.
|
The principal sources of change in the standardized measure of discounted future net cash flows relating to proved reserves is presented in the table below:
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|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2019
|
|
2018
|
|
2017
|
|
(in millions)
|
Balance at January 1,
|
$
|
4,955.7
|
|
|
$
|
3,097.3
|
|
|
$
|
1,928.0
|
|
Sales of oil and condensate, gas and NGL produced, net of production costs
|
(838.7
|
)
|
|
(1,413.0
|
)
|
|
(872.7
|
)
|
Net change in sales prices and in production (lifting) costs related to future production
|
(1,988.6
|
)
|
|
1,632.5
|
|
|
1,457.2
|
|
Net change due to extensions and discoveries
|
220.9
|
|
|
692.6
|
|
|
556.8
|
|
Net change due to revisions of quantity estimates
|
(2,079.2
|
)
|
|
732.0
|
|
|
9.9
|
|
Net change due to purchases of reserves in place
|
34.2
|
|
|
117.0
|
|
|
342.7
|
|
Net change due to sales of reserves in place
|
(617.8
|
)
|
|
(369.6
|
)
|
|
(504.7
|
)
|
Previously estimated development costs incurred during the period
|
460.8
|
|
|
735.6
|
|
|
475.4
|
|
Changes in estimated future development costs
|
1,064.7
|
|
|
(28.3
|
)
|
|
(283.4
|
)
|
Accretion of discount
|
622.8
|
|
|
375.4
|
|
|
235.7
|
|
Net change in income taxes
|
841.5
|
|
|
(615.7
|
)
|
|
(227.4
|
)
|
Other
|
—
|
|
|
(0.1
|
)
|
|
(20.2
|
)
|
Net change
|
(2,279.4
|
)
|
|
1,858.4
|
|
|
1,169.3
|
|
Balance at December 31,
|
$
|
2,676.3
|
|
|
$
|
4,955.7
|
|
|
$
|
3,097.3
|
|