NOTES ACCOMPANYING THE CONSOLIDATED FINANCIAL STATEMENTS
Note 1 – Summary of Significant Accounting Policies
Nature of Business
QEP Resources, Inc. is an independent crude oil and natural gas exploration and production company with operations in two regions of the United States: the Northern Region (primarily in North Dakota and Utah) and the Southern Region (primarily in Texas and Louisiana). Unless otherwise specified or the context otherwise requires, all references to "QEP" or the "Company" are to QEP Resources, Inc. and its subsidiaries on a consolidated basis. QEP's corporate headquarters are located in Denver, Colorado and shares of QEP's common stock trade on the New York Stock Exchange (NYSE) under the ticker symbol "QEP".
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 Regulations 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.
Termination of Marketing Agreements
Effective January 1, 2016, QEP terminated its contracts for resale and marketing transactions between its wholly owned subsidiaries, QEP Marketing Company (QEP Marketing) and QEP Energy Company (QEP Energy). In addition, substantially all of QEP Marketing's third-party purchase and sale agreements and gathering, processing and transportation contracts were assigned to QEP Energy, except those contracts related to natural gas storage activities and Haynesville Gathering. As a result, QEP Energy directly markets its own oil, gas and NGL production. While QEP continues to act as an agent for the sale of oil, gas and NGL production for other working interest owners, for whom QEP serves as the operator, QEP is no longer the first purchaser of this production. QEP has substantially reduced its marketing activities, and subsequently, is reporting lower resale revenue and expenses than it had prior to 2016.
In conjunction with the changes described above, QEP conducted a segment analysis in accordance with Accounting Standards Codification (ASC) Topic 280,
Segment Reporting,
and determined that QEP had one reportable segment effective January 1, 2016. The Company has recast its financial statements for historical periods to reflect the impact of the termination of marketing agreements to show its financial results without segments.
Reclassifications
Certain prior period amounts on the Consolidated Statements of Operations, Consolidated Balance Sheets and 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, cash flows, current assets 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, 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, 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 gas production. Refer to
Note 6 – Derivative Contracts
for the Company's open oil and gas commodity derivative contracts.
Revenue Recognition
QEP recognizes revenue from oil and gas producing activities in the period that services are provided or products are delivered. Revenues associated with the sale of oil, gas and NGL are accounted for using the sales method, whereby revenue is recognized when these commodities are sold to purchasers. Revenues include estimates for the two most recent months using published commodity price indexes and volumes supplied by field operators. An imbalance liability is recorded to the extent that QEP has sold volumes in excess of its share of remaining reserves in an underlying property.
QEP also purchases and resells oil and gas primarily to mitigate losses on unutilized capacity related to firm transportation commitments and storage activities. QEP recognizes revenue from these resale activities when title transfers to the customer.
Cash and 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.
As of
December 31, 2017
, QEP had no unrestricted cash and restricted cash of
$23.4 million
. As of
December 31, 2016
, QEP had unrestricted cash of
$443.8 million
and restricted cash of
$21.6 million
. QEP's restricted cash is primarily cash deposited into an escrow account related to a title dispute between third parties in the Williston Basin and is included in "Other noncurrent assets" on the Consolidated Balance Sheets.
Supplemental cash flow information is shown in the table below:
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Year Ended December 31,
|
|
2017
|
|
2016
|
|
2015
|
Supplemental Disclosures
|
(in millions)
|
Cash paid for interest, net of capitalized interest
|
$
|
134.9
|
|
|
$
|
139.1
|
|
|
$
|
139.4
|
|
Cash paid (refund received) for income taxes, net
|
$
|
(0.3
|
)
|
|
$
|
(123.5
|
)
|
|
$
|
487.8
|
|
Non-cash investing activities
|
|
|
|
|
|
Change in capital expenditure accrual balance
|
$
|
60.2
|
|
|
$
|
(32.8
|
)
|
|
$
|
(129.2
|
)
|
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. Recovery of bad debt associated with accounts receivable for the year ended
December 31, 2017
was
$1.0 million
. Bad debt expense associated with accounts receivable for the years ended
December 31, 2016
and
2015
, was
$1.8 million
, and
$0.5 million
, respectively. Bad debt recovery or expense 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, 2017
, and
$4.8 million
at
December 31, 2016
.
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.
Capitalized Exploratory Well Costs
The Company capitalizes exploratory well costs until it determines whether an exploratory well is commercial or noncommercial. If the Company deems the well commercial, capitalized costs are depreciated on a field basis using the unit-of-production method and the estimated proved developed oil and gas reserves. If the Company concludes that the well is noncommercial, well costs are immediately charged to exploration expense. Exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling are expensed unless the Company remains engaged in substantial activities to assess whether the project is commercial.
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 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
|
10 to 30 years
|
Leasehold improvements
|
3 to 10 years
|
Service, transportation and field service equipment
|
3 to 7 years
|
Furniture and office equipment
|
3 to 7 years
|
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, gas and NGL reserves caused by mechanical problems, faster-than-expected decline of production, lease ownership issues, 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 commodity prices, operating costs and estimates of proved, probable and possible reserves. Cash flow estimates relating to future cash flows from probable and possible reserves are reduced by additional risk-weighting factors.
Unproved properties are evaluated on a specific asset basis or in groups of similar assets, as applicable. The Company performs periodic assessments of unproved oil and gas properties for impairment and recognizes a loss at the time of impairment. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current development and exploration drilling plans, favorable or unfavorable exploration activity on adjacent leaseholds, in-house geologists' evaluation of the lease, future reserve cash flows and the remaining lease term.
During the year ended
December 31, 2017
, QEP recorded impairment charges of
$78.9 million
, of which
$38.1 million
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 3 – Capitalized Exploratory Well Costs
for additional information),
$6.5 million
was related to impairment of an underground gas storage facility and
$5.3 million
was related to the impairment of goodwill. Of the
$38.1 million
impairment of proved properties,
$37.1 million
related to the Other Northern area and
$1.0 million
related to Louisiana properties.
During the year ended
December 31, 2016
, QEP recorded impairment charges of
$1,194.3 million
, of which
$1,172.7 million
was related to proved properties due to lower future oil and gas prices,
$17.9 million
was related to expiring leaseholds on unproved properties and
$3.7 million
was related to the impairment of goodwill. Of the
$1,172.7 million
impairment of proved properties,
$1,164.0 million
related to Pinedale properties,
$4.7 million
related to Uinta Basin properties,
$3.4 million
related to the Other Northern area and
$0.6 million
related to QEP's remaining Other Southern properties.
During the year ended
December 31, 2015
, QEP recorded impairment charges of
$55.6 million
, of which
$39.3 million
was related to proved properties due to lower future oil and gas prices,
$2.0 million
was related to expiring leaseholds on unproved properties and
$14.3 million
was related to the impairment of goodwill. Of the
$39.3 million
impairment on proved properties,
$20.2 million
related to QEP's remaining Other Southern properties,
$18.4 million
related Other Northern properties, and
$0.7 million
related to Permian Basin properties.
Asset Retirement Obligations
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. ARO are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company's credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of ARO change, an adjustment is recorded to both the 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 4 – Asset Retirement Obligations
for additional 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. During the year ended
December 31, 2017
, QEP early adopted ASU 2017-04,
Intangibles – Goodwill and Other (Topic 350): Simplifying the test for goodwill impairment
. Under the new guidance 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, 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, which related to an acquisition in the first quarter of 2017. During the fourth quarter of 2017, QEP performed an annual impairment test over goodwill as described above, which resulted in a full write down of goodwill of
$5.3 million
.
During the years ended
December 31, 2016
and
2015
, QEP recorded
$3.7 million
and
$14.3 million
, respectively, of goodwill. Annual impairment tests over goodwill at year end
December 31, 2016
and
2015
resulted in a full write down of
$3.7 million
and
$14.3 million
, respectively.
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 9 – Commitments and Contingencies
for additional 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 additional information becomes available or as circumstances change. Future environmental expenditures are not discounted to their present value. Recoveries of environmental costs from other parties are recorded separately as assets at their undiscounted value when receipt of such recoveries is probable.
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 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 6 – Derivative Contracts
for additional 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, and 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 may be 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
59%
,
48%
, and
30%
of QEP's revenues for the years ended
December 31, 2017
,
2016
and
2015
, respectively. During the year ended
December 31, 2017
,
Shell Trading Company
,
Occidental Energy Marketing
,
Andeavor Logistics LP
,
BP Energy Company
and
Plains Marketing LP
accounted for
14%
,
13%
,
13%
,
10%
and
10%
, respectively, of QEP's total revenues. During the year ended
December 31, 2016
,
Shell Trading Company
,
BP Energy Company
and
Valero Marketing & Supply Company
accounted for
14%
,
10%
and
10%
, respectively, of QEP's total revenues. During the year ended
December 31, 2015
, no customer accounted for
10%
or more of QEP's total revenues. Management believes that the loss of any of these customers, or any other customer, would not have a material effect on the financial position or results of operations of QEP, since there are numerous potential purchasers of its production.
Income Taxes
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, except as noted below. As of
December 31, 2017
, the Company had a valuation allowance of
$56.8 million
against the state net operating loss deferred tax asset because management does not forecast future income in Oklahoma and Louisiana to offset net operating losses before they expire. All federal income tax returns prior to
2017
have been examined by the Internal Revenue Service and are closed. Income tax returns for
2017
have not yet been filed. Most state tax returns for 2014 and subsequent years remain 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. Our policy is to recognize any interest earned on income tax refunds in "Interest and other income (expense)" on the Consolidated Statements of Operations, any interest expense related to uncertain tax positions in "Interest expense" on the Consolidated Statements of Operations and to recognize any penalties related to uncertain tax positions in "General and administrative" expense on the Consolidated Statements of Operations. As of
December 31, 2017
and
2016
, QEP had
$19.0 million
and
$15.6 million
of unrecognized tax benefits related to uncertain tax positions for asset sales that occurred in 2014, which was included within "Other long-term liabilities" on the Consolidated Balance Sheets. During the year ended
December 31, 2017
, the Company incurred
$0.7 million
of estimated interest expense related to uncertain tax positions. During the year ended
December 31, 2016
, the Company incurred
$0.7 million
of estimated interest expense and
$0.6 million
of estimated penalties related to uncertain tax positions. During the year ended
December 31, 2015
, the Company incurred
$0.5 million
of estimated interest expense and
$2.2 million
of estimated penalties related to uncertain tax positions.
On December 22, 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 Tax Legislation also repeals the corporate alternative minimum tax (AMT). Several provisions of the new tax law such as limitations on the deductibility of interest expense and certain executive compensation and the inability to use Section 1031 like-kind exchanges for assets such as machinery and equipment could apply to QEP; however, we do not believe that they will materially impact QEP's financial statements. 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. The Company will continue to analyze the Tax Legislation to determine the full impact of the new law, 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 10 – Share-Based Compensation
for additional 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, 2017
and
2015
, there were no anti-dilutive shares. For the year ended
December 31, 2016
, there were
0.1 million
shares not included in diluted common shares outstanding as they were anti-dilutive due to QEP's net loss from continuing operations.
The following is a reconciliation of the components of basic and diluted shares used in the EPS calculation:
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|
December 31,
|
|
2017
|
|
2016
|
|
2015
|
|
(in millions)
|
Weighted-average basic common shares outstanding
|
240.6
|
|
|
221.7
|
|
|
176.6
|
|
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
|
240.6
|
|
|
221.7
|
|
|
176.6
|
|
Share-Based Compensation
QEP issues stock options, restricted share awards and restricted share units to certain officers, employees and non-employee directors under its Long-Term Stock Incentive Plan (LTSIP). QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock options for accounting purposes. The 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 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. For additional information, refer to
Note 10 – Share-Based Compensation
for additional 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 11 – Employee Benefits
for additional 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. 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 May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09,
Revenue from Contracts with Customers (Topic 606)
, which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries and across capital markets. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. In addition, new and enhanced disclosures will be required. The amendment is effective prospectively for reporting periods beginning on or after December 15, 2017, and early adoption is permitted for periods beginning on or after December 15, 2016. The two permitted transition methods under the new standard are the full retrospective method, in which case the standard would be applied to each prior reporting period presented, or the modified retrospective method, in which case the cumulative effect of applying the standard would be recognized at the date of initial application. The Company does not expect net income (loss) or cash flows to be materially impacted by the new standard; however, the Company expects that a portion of its transportation and processing costs will be netted within revenue under the new standard. In addition, the Company will have expanded disclosure requirements, as a result of the adoption of the ASU. The Company has selected the modified retrospective method and will adopt this guidance on the effective date of January 1, 2018.
In February 2016, the FASB issued 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 amendment will be effective for reporting periods beginning after December 15, 2018, and early adoption is permitted. The Company is currently assessing the impact of the ASU on the Company's Consolidated Financial Statements.
In March 2016, the FASB issued ASU No. 2016-06,
Derivatives and hedging (Topic 815): Contingent put and call options in debt instruments
, which clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. The amendment was effective prospectively for reporting periods beginning on or after December 15, 2016, and early adoption was permitted. The Company adopted this standard in the first quarter of 2017 and the adoption of this new standard did not have a material impact on the Company's Consolidated Financial Statements.
In March 2016, the FASB issued ASU No. 2016-09,
Compensation – Stock Compensation (Topic 718): Improvements to employee share-based payment accounting,
which includes provisions intended to simplify various aspects related to how share-based compensation payments are accounted for and presented in the financial statements. This amendment was effective prospectively for reporting periods beginning after December 15, 2016, and early adoption was permitted. The Company adopted this standard in the first quarter of 2017 and the adoption of this new standard did not have a material impact on the Company's Consolidated Financial Statements.
In August 2016, the FASB issued ASU No. 2016-15,
Statement of Cash Flows (Topic 230): Classification of certain cash receipts and cash payments
, which intends to reduce the diversity in practice in how certain transactions are classified in the statement of cash flows. This amendment will be effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company early adopted this standard in the fourth quarter of 2017 and the adoption of this standard did not have a material impact on the Company's Consolidated Financial Statements.
In January 2017, the FASB issued ASU No. 2017-01,
Business Combinations (Topic 805): Clarifying the definition of a business
, which clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of businesses. The amendment will be effective prospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company early adopted this standard in the fourth quarter of 2017 and the adoption of this standard did not have a material impact on the Company's Consolidated Financial Statements; however, this standard may impact the determination of whether future acquisitions are accounted for as a business combination or an asset acquisition.
In January 2017, the FASB issued ASU No. 2017-04,
Intangibles – Goodwill and Other (Topic 350): Simplifying the test for goodwill impairment
, which eliminates the requirement to calculate implied fair value of goodwill to measure the goodwill impairment charge. The amendment will be effective prospectively for reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company early adopted this standard in the first quarter of 2017 and the adoption of this new standard did not have a material impact on the Company's Consolidated Financial Statements.
In March 2017, the FASB issued ASU No. 2017-07,
Compensation – Retirement Benefits (Topic 715): Improving the presentation of net periodic pension cost and net periodic postretirement benefit cost
, which changes how employers of a defined benefit plan present net periodic benefit cost in the statements of operations. The amendment will be effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company early adopted this standard in the first quarter of 2017 and recast the years ended
December 31, 2016
and
2015
. The adoption of this new standard did not have a material impact on the Company's Consolidated Financial Statements. Refer to
Note 11 – Employee Benefits
for additional information regarding the Company's pension and other postretirement plans.
Note 2 – Acquisitions and Divestitures
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
$720.7 million
, subject to post-closing purchase price adjustments (the 2017 Permian Basin Acquisition). The 2017 Permian Basin Acquisition consists of approximately
15,100
acres, mainly in Martin County, Texas, which are held by production from existing vertical wells. 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. In accordance with the early adoption of ASU No. 2017-01,
Business Combinations (Topic 805): Clarifying the definition of a business
in the fourth quarter of 2017
,
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. In addition, QEP has made offers to various persons who own additional oil and gas interests in certain properties included in the 2017 Permian Basin Acquisition on substantially the same terms and conditions as the original purchase. If all offers are accepted, the aggregate purchase price is not expected to exceed
$50.0 million
.
2016 Permian Basin Acquisition
In October 2016, QEP acquired oil and gas properties in the Permian Basin for an aggregate purchase price of approximately
$591.0 million
(the 2016 Permian Basin Acquisition). The 2016 Permian Basin Acquisition consists of approximately
9,600
net acres in Martin County, Texas, which are primarily held by production from existing vertical wells. The 2016 Permian Basin Acquisition was funded with cash on hand, which included proceeds from an equity offering in June 2016.
The 2016 Permian Basin Acquisition meets the definition of a business combination under ASC 805,
Business Combinations
, as it included significant proved properties. QEP allocated the cost of the 2016 Permian Basin Acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Revenues of
$80.2 million
and a net
income
of
$221.4 million
were generated from the acquired properties for the year ended
December 31, 2017
. Revenues of
$3.8 million
and a net
loss
of
$0.7 million
were generated from the acquired properties from October 19, 2016 to December 31, 2016. The revenue and net income (loss) are included in QEP's Consolidated Statements of Operations. During the year ended
December 31, 2016
, QEP incurred acquisition-related costs of
$2.3 million
, which are included in "General and administrative" expense on the Consolidated Statements of Operations. In conjunction with the 2016 Permian Basin Acquisition, the Company recorded a
$17.8 million
bargain purchase gain. The acquisition resulted in a bargain purchase gain primarily as a result of an increase in future oil prices from the execution of the purchase and sale agreement to the closing date of the acquisition. The bargain purchase gain is reported on the Consolidated Statements of Operations within "Interest and other income (expense)".
The following table presents a summary of the Company's purchase accounting entries (in millions) as of
December 31, 2017
:
|
|
|
|
|
|
Consideration:
|
|
|
Total consideration
|
|
$
|
591.0
|
|
|
|
|
Amounts recognized for fair value of assets acquired and liabilities assumed:
|
|
|
Proved properties
|
|
$
|
406.2
|
|
Unproved properties
|
|
214.2
|
|
Asset retirement obligations
|
|
(11.6
|
)
|
Bargain purchase gain
|
|
(17.8
|
)
|
Total fair value
|
|
$
|
591.0
|
|
The following unaudited, pro forma results of operations are provided for the year ended
December 31, 2016
. Pro forma results are not provided for the year ended
December 31, 2017
, because the 2016 Permian Basin Acquisition occurred during the fourth quarter of 2016; and therefore, the results are included in QEP's results of operations for the year ended
December 31, 2017
. The supplemental pro forma results of operations are provided for illustrative purposes only and may not be indicative of the actual results that would have been achieved by the acquired properties for the periods presented, or that may be achieved by such properties in the future. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors. The pro forma information is based on QEP's consolidated results of operations for the year ended
December 31, 2016
, the acquired properties' historical results of operations and estimates of the effect of the transaction on the combined results. The pro forma results of operations have been prepared by adjusting, and quantifying, the historical results of QEP to include the historical results of the acquired properties based on information provided by the seller and the impact of the purchase price allocation. The pro forma results of operations do not include any cost savings or other synergies that may result from the 2016 Permian Basin Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the acquired properties.
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
2016
|
|
|
Actual
|
|
Pro forma
|
|
|
(in millions, except per share amounts)
|
Revenues
|
|
$
|
1,377.1
|
|
|
$
|
1,392.5
|
|
Net income (loss)
|
|
$
|
(1,245.0
|
)
|
|
$
|
(1,246.8
|
)
|
Earnings (loss) per common share
|
|
|
|
|
Basic
|
|
$
|
(5.62
|
)
|
|
$
|
(5.62
|
)
|
Diluted
|
|
$
|
(5.62
|
)
|
|
$
|
(5.62
|
)
|
Other Acquisitions
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
, subject to customary post-closing purchase price adjustments. In conjunction with the acquisitions, the Company recorded
$5.3 million
of goodwill, which was subsequently impaired.
In addition to the 2016 Permian Basin Acquisition, QEP acquired various oil and gas properties in 2016, primarily in the Permian and Williston basins, for an aggregate purchase price of
$54.6 million
, which included acquisitions of additional interests in QEP operated wells and additional undeveloped leasehold acreage. In conjunction with the acquisitions, the Company recorded
$3.7 million
of goodwill, which was subsequently impaired, and a
$4.4 million
bargain purchase gain. The bargain purchase gain is reported on the Consolidated Statements of Operations within "Interest and other income (expense)".
During the year ended
December 31, 2015
, QEP acquired various oil and gas properties, primarily in the Williston and Permian basins, for a total purchase price of
$98.3 million
, which included acquisitions of additional interests in QEP operated wells and additional undeveloped leasehold acreage. In conjunction with the acquisitions, the Company recorded
$14.3 million
of goodwill, which was subsequently impaired.
Pinedale Divestiture
In September 2017, QEP sold its Pinedale assets (the Pinedale Divestiture), for net cash proceeds (after purchase price adjustments) of
$718.2 million
, subject to post-closing purchase price adjustments, and recorded a pre-tax
gain
on sale of
$180.4 million
which was recorded within "Net gain (loss) from asset sales" on the Consolidated Statements of Operations. As part of the purchase and sale agreement, at the request of the buyer, QEP agreed to enter into derivative contracts covering a portion of Pinedale's future production. Those derivative contracts were novated to the buyer at closing. In addition, QEP agreed to reimburse the buyer for certain deficiency charges it incurs related to gas processing and NGL transportation and fractionation contracts, if any, between the effective date of the sale and December 31, 2019, in an aggregate amount not to exceed
$45.0 million
. The fair value of the deficiency charges was measured utilizing an internally developed cash flow model discounted at QEP's weighted average cost of debt. Given the unobservable nature of the inputs, the fair value calculation associated with the deficiency charges is considered Level 3 within the fair value hierarchy
.
As of
December 31, 2017
, the liability associated with estimated future payments for this commitment was
$30.6 million
, of which
$27.4 million
is reported on the Consolidated Balance Sheets within "Accounts payable and accrued expenses" and
$3.2 million
is reported on the Consolidated Balance Sheets within "Other long-term liabilities".
QEP accounted for revenues and expenses related to Pinedale, including the pre-tax
gain
on sale of
$180.4 million
, during the years ended
December 31, 2017
,
2016
and
2015
, as income on the Consolidated Statements of Operations because the sale of the Pinedale assets did not cause a strategic shift for the Company and as a result, did not qualify as discontinued operations under ASU 2014-08,
Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity
. The Pinedale Divestiture did, however, represent the sale of an individually significant component. 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
. For the year ended
December 31, 2016
, QEP recorded a net
loss
before income taxes of
$1,152.7 million
. The net
loss
before income taxes was primarily due to an impairment on proved properties of
$1,164.0 million
recognized in 2016 as a result of a decrease in expected future gas prices. For the year ended
December 31, 2015
, QEP recorded net
loss
before income taxes of
$45.6 million
related to Pinedale.
Other Divestitures
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 3 – 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.
During the year ended
December 31, 2016
, QEP sold its interest in certain non-core properties, primarily in the Other Southern area for aggregate proceeds of
$29.0 million
and recorded a pre-tax
gain
on sale of
$8.6 million
.
During the year ended
December 31, 2015
, QEP sold its interest in certain non-core properties in the Other Southern area for aggregate proceeds of
$31.7 million
, of which
$21.8 million
was cash and
$9.9 million
of accounts receivable and recorded a pre-tax
gain
on sale of
$21.0 million
. During the year ended
December 31, 2016
, QEP recorded a pre-tax
loss
of sale of
$0.9 million
, due to post-closing purchase price adjustments from the sale of such properties.
These gains and losses are reported on the Consolidated Statements of Operations within "Net gain (loss) from asset sales".
Note 3 – Capitalized Exploratory Well Costs
Net changes in capitalized exploratory well costs are presented in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalized Exploratory Well Costs
|
|
2017
|
|
2016
|
|
2015
|
|
(in millions)
|
Balance at January 1,
|
$
|
14.2
|
|
|
$
|
2.6
|
|
|
$
|
12.6
|
|
Additions to capitalized exploratory well costs
|
10.7
|
|
|
11.7
|
|
|
6.0
|
|
Reclassifications to proved properties
|
(3.6
|
)
|
|
—
|
|
|
(16.0
|
)
|
Capitalized exploratory well costs charged to expense
|
(21.3
|
)
|
|
(0.1
|
)
|
|
—
|
|
Balance at December 31,
|
$
|
—
|
|
|
$
|
14.2
|
|
|
$
|
2.6
|
|
The balance at
December 31, 2016
and
2015
represents the amount of capitalized exploratory well costs that are pending the determination of proved reserves.
During the years ended
December 31, 2017
and
2016
, 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 on the Central Basin Platform Divestiture for net cash proceeds of
$3.5 million
.
Note 4 – 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. Of the
$214.1 million
and
$231.6 million
ARO liability as of
December 31, 2017
and
2016
, respectively,
$7.5 million
and
$5.8 million
, respectively, was included as a liability in "Accounts payable and accrued expenses" on the Consolidated Balance Sheets.
The following is a reconciliation of the changes in the Company's ARO for the periods specified below:
|
|
|
|
|
|
|
|
|
|
Asset Retirement Obligations
|
|
2017
|
|
2016
|
|
(in millions)
|
ARO liability at January 1,
|
$
|
231.6
|
|
|
$
|
206.8
|
|
Accretion
|
7.7
|
|
|
8.9
|
|
Additions
(1)
|
23.5
|
|
|
17.0
|
|
Revisions
|
8.5
|
|
|
6.5
|
|
Liabilities related to assets sold
(2)
|
(34.9
|
)
|
|
—
|
|
Liabilities settled
|
(22.3
|
)
|
|
(7.6
|
)
|
ARO liability at December 31,
|
$
|
214.1
|
|
|
$
|
231.6
|
|
___________________________
|
|
(1)
|
Additions for the year ended
December 31, 2017
, include
$14.2 million
related to the 2017 Permian Basin Acquisition and additions for the year ended
December 31, 2016
, include
$11.6 million
related to the 2016 Permian Basin Acquisition (refer to
Note 2 – Acquisitions and Divestitures
for more information).
|
|
|
(2)
|
Liabilities related to assets sold for the year ended
December 31, 2017
, include
$34.9 million
related to the Pinedale Divestiture (refer to
Note 2 – Acquisitions and Divestitures
for more information).
|
Note 5 – 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 6 – Derivative Contracts
for additional 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, 2017
and
2016
, 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, 2017
|
Financial Assets
|
|
|
|
|
|
|
|
|
|
Fair value of derivative contracts – short-term
|
$
|
—
|
|
|
$
|
20.6
|
|
|
$
|
—
|
|
|
$
|
(17.2
|
)
|
|
$
|
3.4
|
|
Fair value of derivative contracts – long-term
|
—
|
|
|
2.3
|
|
|
—
|
|
|
(2.2
|
)
|
|
0.1
|
|
Total financial assets
|
$
|
—
|
|
|
$
|
22.9
|
|
|
$
|
—
|
|
|
$
|
(19.4
|
)
|
|
$
|
3.5
|
|
|
|
|
|
|
|
|
|
|
|
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of derivative contracts – short-term
|
$
|
—
|
|
|
$
|
120.8
|
|
|
$
|
—
|
|
|
$
|
(17.2
|
)
|
|
$
|
103.6
|
|
Fair value of derivative contracts – long-term
|
—
|
|
|
34.0
|
|
|
—
|
|
|
(2.2
|
)
|
|
31.8
|
|
Total financial liabilities
|
$
|
—
|
|
|
$
|
154.8
|
|
|
$
|
—
|
|
|
$
|
(19.4
|
)
|
|
$
|
135.4
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
Financial Assets
|
|
|
|
|
|
|
|
|
|
Fair value of derivative contracts – short-term
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Fair value of derivative contracts – long-term
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total financial assets
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of derivative contracts – short-term
|
$
|
—
|
|
|
$
|
169.8
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
169.8
|
|
Fair value of derivative contracts – long-term
|
—
|
|
|
32.0
|
|
|
—
|
|
|
—
|
|
|
32.0
|
|
Total financial liabilities
|
$
|
—
|
|
|
$
|
201.8
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
201.8
|
|
____________________________
|
|
(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 6 – Derivative Contracts
for additional information regarding the Company's derivative contracts.
|
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, 2017
|
|
December 31, 2016
|
Financial Assets
|
(in millions)
|
Cash and cash equivalents
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
443.8
|
|
|
$
|
443.8
|
|
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
Checks outstanding in excess of cash balances
|
$
|
44.0
|
|
|
$
|
44.0
|
|
|
$
|
12.3
|
|
|
$
|
12.3
|
|
Long-term debt
|
$
|
2,160.8
|
|
|
$
|
2,256.2
|
|
|
$
|
2,020.9
|
|
|
$
|
2,104.3
|
|
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 4 – 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 nonrecurring basis to review its proved oil and gas properties for potential impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. During the years ended
December 31, 2017
and
2016
, the Company recorded impairments of certain proved oil and gas properties of
$38.1 million
and
$1,172.7 million
, respectively, resulting in a reduction of the associated carrying value to fair value. The fair value of the property was measured utilizing the income approach and utilizing inputs which are primarily based upon internally developed cash flow models discounted at an appropriate weighted average cost of capital. 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. Refer to
Note 1 – Summary of Significant Accounting Policies
for additional information on impairment of oil and gas properties.
Acquisitions of proved and unproved properties are also measured at fair value on a nonrecurring basis. The Company utilizes a discounted cash flow model to estimate the fair value of acquired property as of the acquisition date which utilizes the following inputs to estimate future net cash flows: (i) estimated quantities of oil, gas and NGL reserves; (ii) estimates of future commodity prices; and (iii) estimated production rates, future operating and development costs, which are based on the Company's historic experience with similar properties. In some instances, market comparable information of recent transactions is used to estimate fair value of unproved acreage. Due to the unobservable characteristics of the inputs, the fair value of the acquired properties is considered Level 3 within the fair value hierarchy. Refer to
Note 2 – Acquisitions and Divestitures
for additional information on the fair value of acquired properties.
Note 6 – 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. In addition, QEP may enter 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 or oil price swaps that use ICE Brent oil prices as the reference price. Gas price derivative instruments are typically structured as fixed-price swaps or costless collars at NYMEX Henry Hub 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, 2017
:
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
Index
|
|
Total Volumes
|
|
Average Swap Price per Unit
|
|
|
|
|
(in millions)
|
|
|
Oil sales
|
|
|
|
(bbls)
|
|
|
($/bbl)
|
|
2018
|
|
NYMEX WTI
|
|
16.8
|
|
|
$
|
52.48
|
|
2019
|
|
NYMEX WTI
|
|
8.0
|
|
|
$
|
51.78
|
|
Gas sales
|
|
|
|
(MMBtu)
|
|
|
($/MMBtu)
|
|
2018 (Full Year)
|
|
NYMEX HH
|
|
109.5
|
|
|
$
|
2.99
|
|
2018 (July through December)
|
|
NYMEX HH
|
|
1.8
|
|
|
$
|
3.01
|
|
2019
|
|
NYMEX HH
|
|
36.5
|
|
|
$
|
2.88
|
|
QEP uses oil and gas basis swaps, combined with NYMEX WTI and NYMEX HH 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 and gas basis swaps as of
December 31, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
Index Less Differential
|
|
Index
|
|
Total Volumes
|
|
Weighted-Average Differential
|
|
|
|
|
|
|
(in millions)
|
|
|
Oil sales
|
|
|
|
|
|
(bbls)
|
|
|
($/bbl)
|
|
2018 (Full Year)
|
|
NYMEX WTI
|
|
Argus WTI Midland
|
|
7.3
|
|
|
$
|
(1.06
|
)
|
2018 (July through December)
|
|
NYMEX WTI
|
|
Argus WTI Midland
|
|
0.9
|
|
|
$
|
(0.71
|
)
|
2019
|
|
NYMEX WTI
|
|
Argus WTI Midland
|
|
4.0
|
|
|
$
|
(0.80
|
)
|
Gas sales
|
|
|
|
|
|
(MMBtu)
|
|
|
($/MMBtu)
|
|
2018
|
|
NYMEX HH
|
|
IFNPCR
|
|
7.3
|
|
|
$
|
(0.16
|
)
|
Derivative Contracts – Gas Storage
QEP enters into commodity derivative transactions to lock in a margin on gas volumes placed into storage. The following table presents QEP's volumes and average prices for its gas storage commodity derivative swap contracts as of
December 31, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
Type of Contract
|
|
Index
|
|
Total Volumes
|
|
Average Swap Price per Unit
|
|
|
|
|
|
|
(in millions)
|
|
|
Gas sales
|
|
|
|
|
|
(MMBtu)
|
|
|
($/MMBtu)
|
|
2018
|
|
SWAP
|
|
IFNPCR
|
|
0.6
|
|
|
$
|
3.06
|
|
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
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Current:
|
|
|
(in millions)
|
Commodity
|
Fair value of derivative contracts
|
|
$
|
20.6
|
|
|
$
|
—
|
|
|
$
|
120.8
|
|
|
$
|
169.8
|
|
Long-term:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
|
Fair value of derivative contracts
|
|
2.3
|
|
|
—
|
|
|
34.0
|
|
|
32.0
|
|
Total derivative instruments
|
|
$
|
22.9
|
|
|
$
|
—
|
|
|
$
|
154.8
|
|
|
$
|
201.8
|
|
The effects of the change in fair value and settlement of QEP's derivative contracts recorded in "Realized and unrealized gains (losses) on derivative contracts" on the Consolidated Statements of Operations are summarized in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative contracts not designated as cash flow hedges
|
|
Year Ended December 31,
|
|
2017
|
|
2016
|
|
2015
|
Realized gains (losses) on commodity derivative contracts
|
|
(in millions)
|
Production
|
|
|
|
|
|
|
Oil derivative contracts
|
|
$
|
6.8
|
|
|
$
|
86.3
|
|
|
$
|
353.7
|
|
Gas derivative contracts
|
|
(22.3
|
)
|
|
44.8
|
|
|
103.4
|
|
Gas Storage
|
|
|
|
|
|
|
|
|
Gas derivative contracts
|
|
—
|
|
|
2.9
|
|
|
3.8
|
|
Realized gains (losses) on commodity derivative contracts
|
|
(15.5
|
)
|
|
134.0
|
|
|
460.9
|
|
Unrealized gains (losses) on commodity derivative contracts
|
|
|
|
|
|
|
Production
|
|
|
|
|
|
|
Oil derivative contracts
|
|
(66.2
|
)
|
|
(217.2
|
)
|
|
(244.9
|
)
|
Gas derivative contracts
|
|
133.6
|
|
|
(145.4
|
)
|
|
62.0
|
|
Gas Storage
|
|
|
|
|
|
|
Gas derivative contracts
|
|
2.5
|
|
|
(4.4
|
)
|
|
(0.8
|
)
|
Unrealized gains (losses) on commodity derivative contracts
|
|
69.9
|
|
|
(367.0
|
)
|
|
(183.7
|
)
|
Total realized and unrealized gains (losses) on commodity derivative contracts related to production and storage contracts
|
|
$
|
54.4
|
|
|
$
|
(233.0
|
)
|
|
$
|
277.2
|
|
|
|
|
|
|
|
|
Derivatives associated with the Pinedale Divestiture
(1)
|
|
|
|
|
|
|
Unrealized gains (losses) on commodity derivative contracts
|
|
|
|
|
|
|
Production
|
|
|
|
|
|
|
Oil derivative contracts
|
|
$
|
(1.3
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
Gas derivative contracts
|
|
(23.5
|
)
|
|
—
|
|
|
—
|
|
NGL derivative contracts
|
|
(5.1
|
)
|
|
—
|
|
|
—
|
|
Unrealized gains (losses) on commodity derivative contracts related to the Pinedale Divestiture
|
|
$
|
(29.9
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
Total realized and unrealized gains (losses) on commodity derivative contracts
|
|
$
|
24.5
|
|
|
$
|
(233.0
|
)
|
|
$
|
277.2
|
|
_______________________
|
|
(1)
|
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 2 – 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" on the Consolidated Statements of Operations.
|
Note 7 – Restructuring Costs
In April 2016, the Company streamlined its organizational structure, resulting in a reduction of approximately
6%
of its total workforce. The total costs related to the 2016 restructuring were approximately
$1.9 million
and were related to one-time termination benefits. During the year ended
December 31, 2016
, restructuring costs of
$1.9 million
were incurred and paid related to the 2016 restructuring. The Company did not incur additional costs related to the 2016 restructuring in 2017.
During 2015, QEP had multiple restructuring events, including the closure of its Tulsa office, which occurred in the third quarter of 2015. The total costs related to the 2015 restructuring events were approximately
$8.3 million
, of which approximately
$5.3 million
was related to one-time termination benefits and approximately
$3.0 million
was related to relocation of certain employees. During the year ended
December 31, 2016
, restructuring costs of
$0.6 million
were incurred and paid related to the Tulsa office closure, all of which were related to the relocation of certain employees. The Company did not incur additional costs related to the closure of its Tulsa office.
All restructuring costs were recorded within "General and administrative" expense on the Consolidated Statements of Operations.
Note 8 – Debt
As of the indicated dates, the principal amount of QEP's debt consisted of the following:
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2017
|
|
2016
|
|
(in millions)
|
Revolving Credit Facility due 2022
|
$
|
89.0
|
|
|
$
|
—
|
|
6.80% Senior Notes due 2018
(1)
|
—
|
|
|
134.0
|
|
6.80% Senior Notes due 2020
(1)
|
51.7
|
|
|
136.0
|
|
6.875% Senior Notes due 2021
(1)
|
397.6
|
|
|
625.0
|
|
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
(1)
|
500.0
|
|
|
—
|
|
Less: unamortized discount and unamortized debt issuance costs
|
(27.5
|
)
|
|
(24.1
|
)
|
Total long-term debt outstanding
|
$
|
2,160.8
|
|
|
$
|
2,020.9
|
|
_______________________
|
|
(1)
|
During the quarter ended
December 31, 2017
, the Company issued
$500.0 million
of
5.625%
Senior Notes due in 2026. The Company used the majority of the proceeds from the offering to redeem all of its outstanding
6.80%
Senior Notes due in 2018 and fund tender offers for
$84.3 million
of
6.80%
Senior Notes due in 2020 and
$227.4 million
of its outstanding
6.875%
Senior Notes due in 2021. The Company recorded a
$32.7 million
loss from early extinguishment of debt related to the redemption and tender offers.
|
Of the total debt outstanding on
December 31, 2017
, the
6.80%
Senior Notes due
March 1, 2020
, the
6.875%
Senior Notes due
March 1, 2021
and the
5.375%
Senior Notes due
October 1, 2022
, will mature within the next five years. In addition, the revolving credit facility matures on
September 1, 2022
.
Credit Facility
In November 2017, QEP entered into the Seventh Amendment to its Credit Agreement, which, among other things, reduced the aggregate principal amount of commitments to
$1.25 billion
and extended the maturity date, subject to satisfaction of certain conditions, to September 1, 2022. The credit facility provides for borrowings at short-term interest rates and contains customary covenants and restrictions. The amended 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 4.25 times consolidated EBITDA (as defined in the credit agreement) for the fiscal quarter ending December 31, 2017, 4.00 times commencing with the fiscal quarter ending March 31, 2018, through the fiscal quarter ending December 31, 2018, and 3.75 times thereafter, and (iii) during a ratings trigger period (as defined), a present value coverage ratio under which the present value of the Company's proved reserves must exceed net funded debt by 1.25 times at any time prior to January 1, 2019, must exceed net funded debt by 1.40 times commencing on January 1, 2019, through December 31, 2019, and must exceed net funded debt by 1.50 times at any time on or after January 1, 2020. The company is currently not subject to the present value coverage ratio. As of
December 31, 2017
and
2016
, QEP was in compliance with the covenants under the credit agreement.
During the year ended
December 31, 2017
, QEP's weighted-average interest rates on borrowings from its credit facility were
3.52%
. As of
December 31, 2017
, QEP had
$89.0 million
of borrowings outstanding and
$1.0 million
in letters of credit outstanding under the credit facility. As of
December 31, 2016
, QEP had no borrowings outstanding and
$2.8 million
in letters of credit outstanding under the credit facility.
Senior Notes
At
December 31, 2017
, the Company had
$2,099.3 million
principal amount of senior notes outstanding with maturities ranging from
March 2020
to
March 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.
Note 9 – 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.
Litigation
Landowner 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 are seeking money damages and a declaratory judgment that portions of the oil and gas leases covering the properties are no longer in effect. The Company continues to evaluate the allegations and its defenses. The Company is unable to make an estimate of the reasonably possible loss at this early stage.
Commitments
QEP has contracted for gathering, processing, firm transportation and storage 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, storage, drilling, and fractionation contracts are as follows (in millions):
|
|
|
|
|
Year
|
Amount
|
2018
|
$
|
95.6
|
|
2019
|
$
|
68.4
|
|
2020
|
$
|
54.9
|
|
2021
|
$
|
29.9
|
|
2022
|
$
|
28.3
|
|
After 2022
|
$
|
122.5
|
|
QEP rents office space throughout its scope of operations from third-party lessors. Rental expense from operating leases amounted to
$9.6 million
,
$9.1 million
, and
$8.0 million
during the years ended
December 31, 2017
,
2016
and
2015
, respectively. Minimum future payments under the terms of long-term operating leases for the Company's primary office locations are as follows (in millions):
|
|
|
|
|
Year
|
Amount
|
2018
|
$
|
7.0
|
|
2019
|
$
|
7.2
|
|
2020
|
$
|
7.4
|
|
2021
|
$
|
7.4
|
|
2022
|
$
|
7.2
|
|
After 2022
|
$
|
4.8
|
|
Note 10 – Share-Based Compensation
QEP issues stock options, restricted share awards and restricted share units under its LTSIP and awards performance share units under its CIP to certain officers, employees, and non-employee directors. QEP recognizes expense over the vesting periods for the stock options, restricted share awards, restricted share units and performance share units. There were
5.0 million
shares available for future grants under the LTSIP at
December 31, 2017
.
Share-based compensation expense related to continuing operations is recognized within "General and administrative" expense on the Consolidated Statements of Operations and is summarized in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2017
|
|
2016
|
|
2015
|
|
(in millions)
|
Stock options
|
$
|
2.3
|
|
|
$
|
2.3
|
|
|
$
|
2.9
|
|
Restricted share awards
|
24.6
|
|
|
23.7
|
|
|
25.6
|
|
Performance share units
|
(4.5
|
)
|
|
9.4
|
|
|
6.2
|
|
Restricted share units
|
—
|
|
|
0.2
|
|
|
—
|
|
Total share-based compensation expense
|
$
|
22.4
|
|
|
$
|
35.6
|
|
|
$
|
34.7
|
|
Stock Options
QEP uses 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 utilizes the "simplified" method to estimate the expected term of the stock options granted as there is limited historical exercise data available in estimating the expected term of the stock options. QEP uses a historical volatility method to estimate the fair value of stock options awards and the risk-free interest rate is based on the yield on U.S. Treasury strips with maturities similar to those of the expected term of the stock options. The stock options typically vest in equal installments over a three-year period from the grant date and are exercisable immediately upon vesting through the seventh anniversary of the grant date. To fulfill options exercised, QEP either reissues treasury stock or issues new shares. The Company expenses forfeitures of stock options as they occur.
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
|
|
2016
|
|
2015
|
Weighted-average grant date fair value of awards granted during the period
|
$
|
6.44
|
|
|
$
|
3.77
|
|
|
$
|
6.82
|
|
Risk-free interest rate range
|
1.66% - 1.81%
|
|
|
0.99% - 1.15%
|
|
|
1.38% - 1.38%
|
|
Weighted-average risk-free interest rate
|
1.8
|
%
|
|
1.2
|
%
|
|
1.4
|
%
|
Expected price volatility range
|
43.82% - 46.70%
|
|
|
43.42% - 43.66%
|
|
|
36.8% - 36.8%
|
|
Weighted-average expected price volatility
|
43.9
|
%
|
|
43.4
|
%
|
|
36.8
|
%
|
Expected dividend yield
|
—
|
%
|
|
—
|
%
|
|
0.37
|
%
|
Expected term in years at the date of grant
|
4.5
|
|
|
4.5
|
|
|
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, 2016
|
2,151,957
|
|
|
$
|
25.26
|
|
|
|
|
|
Granted
|
418,752
|
|
|
16.77
|
|
|
|
|
|
Forfeited
|
(14,172
|
)
|
|
15.33
|
|
|
|
|
|
Cancelled
|
(202,260
|
)
|
|
27.55
|
|
|
|
|
|
Outstanding at December 31, 2017
|
2,354,277
|
|
|
$
|
23.62
|
|
|
3.50
|
|
$
|
—
|
|
Options Exercisable at December 31, 2017
|
1,551,861
|
|
|
$
|
27.90
|
|
|
2.47
|
|
$
|
—
|
|
Unvested Options at December 31, 2017
|
802,416
|
|
|
$
|
15.33
|
|
|
5.48
|
|
$
|
—
|
|
During the years ended
December 31, 2017
and
2016
, 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 options exercised was
$0.1 million
during the year ended
December 31, 2015
. There was no income tax impact for the year ended
December 31, 2017
. The Company realized an income tax
benefit
of
$0.2 million
for the year ended
December 31, 2016
and
$6.4 million
of income tax
expense
for the year ended
December 31, 2015
. As of
December 31, 2017
,
$1.6 million
of unrecognized compensation cost related to stock options granted under the LTSIP is expected to be recognized over a weighted-average period of
2.04
years.
Restricted Share Awards
Restricted share award grants typically vest in equal installments over a
three
-year period from the grant date. The grant date fair value is determined based on the closing bid price of the Company's common stock on the grant date. The Company expenses forfeitures of restricted share awards as they occur. The total fair value of restricted share awards that vested during the years ended
December 31, 2017
,
2016
and
2015
, was
$18.4 million
,
$24.3 million
and
$22.7 million
, respectively. There was no income tax impact for the year ended
December 31, 2017
and
2016
. The Company realized an income tax
benefit
of
$3.2 million
for the year ended
December 31, 2015
. The weighted-average grant date fair value of restricted share awards granted was
$13.90
per share,
$10.50
per share and
$20.92
per share for the years ended
December 31, 2017
,
2016
and
2015
, respectively. As of
December 31, 2017
,
$19.2 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
1.99
years.
Transactions involving restricted share awards under the terms of the LTSIP are summarized below:
|
|
|
|
|
|
|
|
|
Restricted Share Awards Outstanding
|
|
Weighted-Average Grant Date Fair Value
|
|
|
|
(per share)
|
Unvested balance at December 31, 2016
|
3,208,503
|
|
|
$
|
14.32
|
|
Granted
|
2,219,763
|
|
|
13.90
|
|
Vested
|
(1,392,043
|
)
|
|
16.53
|
|
Forfeited
|
(314,889
|
)
|
|
14.49
|
|
Unvested balance at December 31, 2017
|
3,721,334
|
|
|
$
|
13.23
|
|
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 a three-year period. The awards are denominated in share units and have historically been paid in cash. Beginning with awards granted in 2015, the Company has the option to settle earned awards in cash or shares of common stock under the Company's LTSIP; however, as of
December 31, 2017
, the Company expects to settle all awards in cash. 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
$5.3 million
,
$2.8 million
and
$3.1 million
for vested performance share units during the years ended
December 31, 2017
,
2016
and
2015
, respectively. The weighted-average grant date fair value of the performance share units granted during the years ended
December 31, 2017
,
2016
and
2015
, was
$16.90
,
$10.16
, and
$21.69
per share, respectively. As of
December 31, 2017
,
$1.2 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
1.89
years.
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, 2016
|
1,027,280
|
|
|
$
|
17.24
|
|
Granted
|
405,014
|
|
|
16.90
|
|
Vested and paid
|
(215,439
|
)
|
|
31.63
|
|
Forfeited
|
(17,519
|
)
|
|
13.88
|
|
Unvested balance at December 31, 2017
|
1,199,336
|
|
|
$
|
14.59
|
|
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 a three-year period and are deferred into the Company's nonqualified, unfunded deferred compensation plan at the time of vesting. These awards are ultimately delivered in cash. They 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
$16.98
and
$10.12
per share for the years ended
December 31, 2017
and
2016
, respectively. As of
December 31, 2017
,
$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
1.03
years.
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, 2016
|
18,034
|
|
|
$
|
10.12
|
|
Granted
|
9,924
|
|
|
16.98
|
|
Vested
|
(6,012
|
)
|
|
10.12
|
|
Unvested balance at December 31, 2017
|
21,946
|
|
|
$
|
13.22
|
|
Note 11 – Employee Benefits
Pension and other postretirement benefits
The Company provides pension and other postretirement benefits to certain employees through three retirement benefit plans: the QEP Resources, Inc. Retirement Plan (the Pension Plan), the Supplemental Executive Retirement Plan (the SERP), and a postretirement medical plan (the 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, 2017
, covers
30
active and suspended participants, or
5%
, of QEP's active employees, and
184
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, 2017
, the Company made contributions of
$4.0 million
to the Pension Plan and expects to contribute approximately
$4.0 million
to the Pension Plan in
2018
. Contributions to the Pension Plan increase plan assets. Due to the Pension Plan freeze on January 1, 2016, the Company began making additional contributions for eligible employees who were active participants in the Pension Plan on December 31, 2015 based on the eligible employee's age as of December 31, 2015. During the year ended
December 31, 2017
, QEP contributed
$0.4 million
for these employees.
As a result of the Company's 2014 divestitures and retirements in 2015, the number of active participants in the Pension Plan fell to 50 participants during the year ended December 31, 2015, which is the minimum number of active participants for a plan to meet the qualification requirements of the minimum participation rules under the Internal Revenue Code. In order to prevent disqualification, the Pension Plan was amended in June 2015 and was frozen effective January 1, 2016, such that employees do not earn additional defined benefits for future services except for purposes of determining eligibility for an early retirement benefit. This change resulted in a non-cash curtailment loss of
$11.2 million
recognized on the Consolidated Statements of Operations within "Interest and other income (expense)" expense during the year ended
December 31, 2015
. A curtailment is recognized immediately when there is a significant reduction in, or an elimination of, defined benefit accruals for present employees' future services.
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, 2017
, the Company made contributions of
$2.0 million
to its SERP and expects to contribute approximately
$0.7 million
in
2018
. 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".
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
30
active, pension eligible employees,
17
are also eligible for the Medical Plan when they retire. As of
December 31, 2017
,
55
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, 2017
, the Company made contributions of
$0.1 million
and expects to contribute approximately
$0.3 million
of benefits in
2018
. At
December 31, 2017
and
2016
, 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.
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 recast years ended
December 31, 2016
and
2015
by recognizing 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
$128.7 million
and
$124.5 million
at
December 31, 2017
and
2016
, 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, 2017
and
2016
, as well as the funded status of the plans and amounts recognized in the financial statements at
December 31, 2017
and
2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Plan and SERP benefits
|
|
Medical Plan benefits
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Change in benefit obligation
|
(in millions)
|
Benefit obligation at January 1,
|
$
|
129.2
|
|
|
$
|
120.3
|
|
|
$
|
5.4
|
|
|
$
|
5.2
|
|
Service cost
|
0.8
|
|
|
1.2
|
|
|
—
|
|
|
—
|
|
Interest cost
|
4.7
|
|
|
5.2
|
|
|
0.1
|
|
|
0.2
|
|
Curtailments
|
(0.3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
Benefit payments
|
(6.9
|
)
|
|
(7.8
|
)
|
|
(0.1
|
)
|
|
(0.4
|
)
|
Plan amendments
|
—
|
|
|
—
|
|
|
(2.4
|
)
|
|
—
|
|
Actuarial loss (gain)
|
2.5
|
|
|
10.3
|
|
|
(0.1
|
)
|
|
0.4
|
|
Benefit obligation at December 31,
|
$
|
130.0
|
|
|
$
|
129.2
|
|
|
$
|
2.9
|
|
|
$
|
5.4
|
|
Change in plan assets
|
|
|
|
|
|
|
|
Fair value of plan assets at January 1,
|
$
|
86.1
|
|
|
$
|
79.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Actual return on plan assets
|
15.3
|
|
|
7.4
|
|
|
—
|
|
|
—
|
|
Company contributions to the plan
|
6.0
|
|
|
7.2
|
|
|
0.1
|
|
|
0.4
|
|
Benefit payments
|
(6.9
|
)
|
|
(7.8
|
)
|
|
(0.1
|
)
|
|
(0.4
|
)
|
Fair value of plan assets at December 31,
|
100.5
|
|
|
86.1
|
|
|
—
|
|
|
—
|
|
Underfunded status (current and long-term)
|
$
|
(29.5
|
)
|
|
$
|
(43.1
|
)
|
|
$
|
(2.9
|
)
|
|
$
|
(5.4
|
)
|
Amounts recognized in balance sheets
|
|
|
|
|
|
|
|
Accounts payable and accrued expenses
|
$
|
(1.5
|
)
|
|
$
|
(2.5
|
)
|
|
$
|
(0.2
|
)
|
|
$
|
(0.3
|
)
|
Other long-term liabilities
|
(27.9
|
)
|
|
(40.6
|
)
|
|
(2.6
|
)
|
|
(5.1
|
)
|
Total amount recognized in balance sheet
|
$
|
(29.4
|
)
|
|
$
|
(43.1
|
)
|
|
$
|
(2.8
|
)
|
|
$
|
(5.4
|
)
|
Amounts recognized in AOCI
|
|
|
|
|
|
|
|
Net actuarial loss (gain)
|
$
|
15.0
|
|
|
$
|
23.5
|
|
|
$
|
(0.5
|
)
|
|
$
|
(0.4
|
)
|
Prior service cost
|
1.2
|
|
|
2.9
|
|
|
(1.2
|
)
|
|
1.0
|
|
Total amount recognized in AOCI
|
$
|
16.2
|
|
|
$
|
26.4
|
|
|
$
|
(1.7
|
)
|
|
$
|
0.6
|
|
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
|
|
2017
|
|
2016
|
|
2015
|
|
2017
|
|
2016
|
|
2015
|
Components of net periodic benefit cost
|
(in millions)
|
Service cost
|
$
|
0.8
|
|
|
$
|
1.2
|
|
|
$
|
2.1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Interest cost
|
4.7
|
|
|
5.2
|
|
|
4.9
|
|
|
0.1
|
|
|
0.2
|
|
|
0.2
|
|
Expected return on plan assets
|
(5.4
|
)
|
|
(5.6
|
)
|
|
(5.7
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
Curtailment loss
|
0.7
|
|
|
—
|
|
|
11.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Settlements
|
0.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Amortization of prior service costs
|
1.0
|
|
|
1.1
|
|
|
1.7
|
|
|
(0.3
|
)
|
|
0.2
|
|
|
0.2
|
|
Amortization of actuarial loss
|
0.5
|
|
|
0.8
|
|
|
0.5
|
|
|
(0.1
|
)
|
|
—
|
|
|
—
|
|
Periodic expense
|
$
|
2.5
|
|
|
$
|
2.7
|
|
|
$
|
14.7
|
|
|
$
|
(0.3
|
)
|
|
$
|
0.4
|
|
|
$
|
0.4
|
|
Components recognized in accumulated other comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
Current period prior service cost
|
$
|
(0.7
|
)
|
|
$
|
—
|
|
|
$
|
0.9
|
|
|
$
|
(2.5
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
Current period actuarial (gain) loss
|
(7.5
|
)
|
|
8.5
|
|
|
2.2
|
|
|
(0.1
|
)
|
|
0.4
|
|
|
(1.4
|
)
|
Amortization of prior service cost
|
(1.0
|
)
|
|
(1.1
|
)
|
|
(12.9
|
)
|
|
0.3
|
|
|
(0.2
|
)
|
|
(0.2
|
)
|
Amortization of actuarial gain (loss)
|
(0.5
|
)
|
|
(0.8
|
)
|
|
(0.5
|
)
|
|
0.1
|
|
|
—
|
|
|
—
|
|
Loss on curtailment in current period
|
(0.3
|
)
|
|
—
|
|
|
(7.1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
Settlements
|
(0.2
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total amount recognized in accumulated other comprehensive income
|
$
|
(10.2
|
)
|
|
$
|
6.6
|
|
|
$
|
(17.4
|
)
|
|
$
|
(2.2
|
)
|
|
$
|
0.2
|
|
|
$
|
(1.6
|
)
|
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
2018
is
$1.9 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
2018
is
$0.3 million
, which represents amortization of prior service cost recognized and actuarial
gains
. 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, 2017
and
2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Plan and SERP benefits
|
|
Medical Plan benefits
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Discount rate
|
3.52
|
%
|
|
3.96
|
%
|
|
3.60
|
%
|
|
4.10
|
%
|
Rate of increase in compensation
(1)
|
3.50
|
%
|
|
3.50
|
%
|
|
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 value of the Pension Plan. As such, for the years ended
December 31, 2017
and
2016
, the rate of increase in compensation only includes the SERP and Medical Plan.
|
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
|
|
2017
|
|
2016
|
|
2015
|
|
2017
|
|
2016
|
|
2015
|
Discount rate
|
4.00
|
%
|
|
4.23
|
%
|
|
3.94
|
%
|
|
4.10
|
%
|
|
4.40
|
%
|
|
4.00
|
%
|
Expected long-term return on plan assets
|
6.00
|
%
|
|
6.50
|
%
|
|
6.75
|
%
|
|
n/a
|
|
|
n/a
|
|
|
n/a
|
|
Rate of increase in compensation
(1)
|
3.50
|
%
|
|
4.00
|
%
|
|
4.00
|
%
|
|
3.50
|
%
|
|
4.00
|
%
|
|
4.00
|
%
|
_______________________
|
|
(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 years ended
December 31, 2017
and
2016
, the rate of increase in compensation only includes the SERP and Medical Plan.
|
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
2018
. 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.
In conjunction with the issuance of ASU 2015-07,
Fair Value Measurements (Topic 820): Disclosures for Investment in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent)
, QEP no longer presents its Pension Plan assets in the fair value hierarchy, in accordance with the provisions of ASC 820,
Fair Value Measurements and Disclosures,
as all investments are measured at NAV as a practical expedient, which are now required to be excluded from the fair value hierarchy.
The following table summarizes investments for which fair value is measured using the NAV per share practical expedient as of
December 31, 2017
and
2016
, respectively:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
|
December 31, 2016
|
|
Total
|
|
Percentage of total
|
|
Total
|
|
Percentage of total
|
|
(in millions, except percentages)
|
Cash and short-term investments
|
$
|
0.5
|
|
|
—
|
%
|
|
$
|
3.5
|
|
|
4
|
%
|
Equity securities:
|
|
|
|
|
|
|
|
Domestic
|
35.0
|
|
|
35
|
%
|
|
39.3
|
|
|
46
|
%
|
International
|
15.3
|
|
|
15
|
%
|
|
21.6
|
|
|
25
|
%
|
Fixed income
|
49.7
|
|
|
50
|
%
|
|
21.7
|
|
|
25
|
%
|
Total investments
|
$
|
100.5
|
|
|
100
|
%
|
|
$
|
86.1
|
|
|
100
|
%
|
Expected Benefit Payments
As of
December 31, 2017
, the following future benefit payments are expected to be paid:
|
|
|
|
|
|
|
|
|
|
Pension Plan and SERP benefits
|
|
Medical Plan benefits
|
|
(in millions)
|
2018
|
$
|
6.6
|
|
|
$
|
0.2
|
|
2019
|
$
|
8.1
|
|
|
$
|
0.2
|
|
2020
|
$
|
7.6
|
|
|
$
|
0.2
|
|
2021
|
$
|
8.3
|
|
|
$
|
0.2
|
|
2022
|
$
|
6.8
|
|
|
$
|
0.2
|
|
2023 through 2026
|
$
|
39.1
|
|
|
$
|
0.6
|
|
Employee Investment Plan
QEP employees may participate in the QEP Employee Investment Plan, a defined-contribution plan (the 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. 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,
|
|
2017
|
|
2016
|
|
2015
|
Employees not covered by the Pension Plan or SERP
(1)
|
|
|
|
|
|
Maximum employer matching of qualifying earnings
|
8
|
%
|
|
8
|
%
|
|
8
|
%
|
|
|
|
|
|
|
Employees covered by the Pension Plan but not the SERP
(1)
|
|
|
|
|
|
Maximum employer matching of qualifying earnings
|
8
|
%
|
|
8
|
%
|
|
6
|
%
|
|
|
|
|
|
|
Employees covered by both the Pension Plan and the SERP
(1)
|
|
|
|
|
|
Maximum employer matching of qualifying earnings
|
6
|
%
|
|
6
|
%
|
|
6
|
%
|
_______________________
|
|
(1)
|
The Pension Plan was frozen effective January 1, 2016.
|
The Company may contribute a discretionary portion beyond the Company's matching contribution to employees not in the Pension Plan or SERP. The Company recognizes expense equal to its yearly contributions, which amounted to
$6.0 million
,
$5.6 million
and
$6.3 million
during the years ended
December 31, 2017
,
2016
and
2015
, respectively.
Note 12 – Income Taxes
On December 22, 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 Tax Legislation also repeals the corporate alternative minimum tax (AMT). Several provisions of the new tax law such as limitations on the deductibility of interest expense and certain executive compensation and the inability to use Section 1031 like-kind exchanges for assets such as machinery and equipment could apply to QEP; however, we do not believe that they will materially impact QEP's financial statements. 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. The Company will continue to analyze the Tax Legislation to determine the full impact of the new law, 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,
|
|
2017
|
|
2016
|
|
2015
|
Federal income tax provision (benefit)
|
(in millions)
|
Current
|
$
|
2.1
|
|
|
$
|
(55.5
|
)
|
|
$
|
(112.3
|
)
|
Deferred
|
(339.8
|
)
|
|
(614.3
|
)
|
|
34.5
|
|
State income tax provision (benefit)
|
|
|
|
|
|
Current
|
0.5
|
|
|
(1.5
|
)
|
|
(6.6
|
)
|
Deferred
|
25.0
|
|
|
(36.9
|
)
|
|
(9.2
|
)
|
Total income tax provision (benefit)
|
$
|
(312.2
|
)
|
|
$
|
(708.2
|
)
|
|
$
|
(93.6
|
)
|
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,
|
|
2017
|
|
2016
|
|
2015
|
Federal income taxes statutory rate
|
35.0
|
%
|
|
35.0
|
%
|
|
35.0
|
%
|
Increase (decrease) in rate as a result of:
|
|
|
|
|
|
State income taxes, net of federal income tax benefit
(1)
|
(40.1
|
)%
|
|
2.4
|
%
|
|
4.2
|
%
|
Federal rate change
(2)
|
741.3
|
%
|
|
—
|
%
|
|
—
|
%
|
State rate change
|
2.1
|
%
|
|
(1.1
|
)%
|
|
—
|
%
|
Penalties
|
(0.4
|
)%
|
|
—
|
%
|
|
(0.3
|
)%
|
Return to provision adjustment
|
(0.7
|
)%
|
|
—
|
%
|
|
(0.3
|
)%
|
Uncertain tax provision (federal rate change)
|
(7.7
|
)%
|
|
—
|
%
|
|
—
|
%
|
Other
|
(1.8
|
)%
|
|
—
|
%
|
|
(0.1
|
)%
|
Effective income tax rate
|
727.7
|
%
|
|
36.3
|
%
|
|
38.5
|
%
|
____________________________
|
|
(1)
|
State income taxes changed significantly from prior years mainly due to the change in valuation allowance during the year of
$36.2 million
.
|
|
|
(2)
|
The new 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.
|
Significant components of the Company's deferred income taxes were as follows:
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2017
(1)
|
|
2016
|
Deferred tax liabilities
|
(in millions)
|
Property, plant and equipment
|
$
|
898.7
|
|
|
$
|
1,135.0
|
|
Deferred tax assets
|
|
|
|
Net operating loss and tax credit carryforwards
|
$
|
308.8
|
|
|
$
|
161.6
|
|
Employee benefits and compensation costs
|
26.4
|
|
|
49.0
|
|
Bonus and vacation accrual
|
6.2
|
|
|
11.4
|
|
Commodity price derivatives
|
29.9
|
|
|
74.3
|
|
Other
|
9.4
|
|
|
12.8
|
|
Total deferred tax assets
|
380.7
|
|
|
309.1
|
|
Net deferred income tax liability
|
$
|
518.0
|
|
|
$
|
825.9
|
|
Balance sheet classification
|
|
|
|
Deferred income tax liability – noncurrent
|
518.0
|
|
|
825.9
|
|
Net deferred income tax liability
|
$
|
518.0
|
|
|
$
|
825.9
|
|
____________________________
|
|
(1)
|
The
$307.9 million
decrease in net deferred income tax liability as of December 31, 2017 is primarily related to a
$318.0 million
decrease from the federal rate change from
35%
to
21%
.
|
The amounts and expiration dates of net operating loss and tax credit carryforwards at
December 31, 2017
, are as follows:
|
|
|
|
|
|
|
|
Expiration Dates
|
|
Amounts
|
|
|
|
(in millions)
|
State net operating loss and tax credit carryforwards
|
2018-2037
|
|
$
|
95.8
|
|
State net operating loss valuation allowance
|
|
|
$
|
(56.8
|
)
|
U.S. net operating loss
|
2036-2037
|
|
$
|
250.4
|
|
U.S. alternative minimum tax credit
|
Indefinite
|
|
$
|
19.5
|
|
The valuation allowance of
$56.8 million
was established in 2014 and 2017 against the available state net operating loss and is related primarily to losses incurred in Oklahoma and Louisiana. Due to the 2014 property sales in the Other Southern area in which the Company sold its interests in most of its properties in Oklahoma, the Company does not forecast sufficient taxable income to utilize the net operating loss in Oklahoma. In 2017, a valuation allowance of
$31.8 million
was established against Louisiana's net operating loss as the Company does not forecast sufficient taxable income to utilize the entire net operating loss in Louisiana.
The Tax Legislation eliminated AMT, and allowed the ability to offset our regular tax liability or claim refunds for taxable years 2018 through 2021 for AMT credits carried forward from prior years. The Company currently anticipates it will realize approximately
$19.5 million
in AMT value over the next four years with approximately half of this value estimated to be realized in 2019 for taxable year 2018.
Unrecognized Tax Benefit
As of
December 31, 2017
and
2016
, QEP had
$19.0 million
and
$15.6 million
, respectively, of unrecognized tax benefits 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. The
$15.6 million
uncertain tax position the Company reported during the year ended
December 31, 2016
, was expensed during the year ended December 31, 2014, with an additional
$3.4 million
expensed during the year ended
December 31, 2017
with the new Tax Legislation. 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. Our policy is to recognize any interest expense related to uncertain tax positions in "Interest expense" on the Consolidated Statements of Operations and to recognize any penalties related to uncertain tax positions in "General and administrative" expense on the Consolidated Statements of Operations. During the year ended
December 31, 2017
, the Company incurred
$0.7 million
of estimated interest expense related to uncertain tax positions. During the year ended
December 31, 2016
, the Company incurred
$0.7 million
of estimated interest expense and
$0.6 million
of estimated penalties 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, 2017
and
2016
:
|
|
|
|
|
|
|
|
|
|
Unrecognized Tax Benefits
|
|
2017
|
|
2016
|
|
(in millions)
|
Balance as of January 1,
|
$
|
15.6
|
|
|
$
|
15.6
|
|
Federal benefit of state (change from 35% to 21%)
|
3.4
|
|
|
—
|
|
Balance as of December 31,
|
$
|
19.0
|
|
|
$
|
15.6
|
|
As of
December 31, 2017
and
2016
, QEP had approximately
$19.0 million
and
$15.6 million
, respectively, of unrecognized tax benefit that would impact its effective tax rate if recognized. The difference is due to the change in the Federal tax rate in 2017 from
35%
to
21%
, which affects the federal benefit of the state deduction to the unrecognized tax position.
Note 13 – Quarterly Financial Information (unaudited)
The following table provides a summary of unaudited quarterly financial information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
Second Quarter
|
|
Third Quarter
|
|
Fourth Quarter
|
|
Year
|
2017
|
(in millions, except per share amounts or otherwise specified)
|
Revenues
|
$
|
420.1
|
|
|
$
|
383.7
|
|
|
$
|
390.1
|
|
|
$
|
429.0
|
|
|
$
|
1,622.9
|
|
Operating income (loss)
|
(5.2
|
)
|
|
(0.9
|
)
|
|
132.1
|
|
|
(24.5
|
)
|
|
101.5
|
|
Net income (loss)
|
76.9
|
|
|
45.4
|
|
|
(3.3
|
)
|
|
150.3
|
|
|
269.3
|
|
Net gain (loss) from asset sales and impairment
|
(0.1
|
)
|
|
19.8
|
|
|
157.1
|
|
|
(42.2
|
)
|
|
134.6
|
|
Nonrecurring items in operating income (loss)
(1)
|
—
|
|
|
—
|
|
|
8.2
|
|
|
—
|
|
|
8.2
|
|
Per share information
|
|
|
|
|
|
|
|
|
|
Basic EPS
|
$
|
0.32
|
|
|
$
|
0.19
|
|
|
$
|
(0.01
|
)
|
|
$
|
0.62
|
|
|
$
|
1.12
|
|
Diluted EPS
|
0.32
|
|
|
0.19
|
|
|
(0.01
|
)
|
|
0.62
|
|
|
1.12
|
|
Production information
|
|
|
|
|
|
|
|
|
|
Total equivalent production (Mboe)
|
13,090.3
|
|
|
13,860.6
|
|
|
14,124.1
|
|
|
12,069.9
|
|
|
53,144.9
|
|
Total equivalent production (Bcfe)
|
78.6
|
|
|
83.2
|
|
|
84.7
|
|
|
72.1
|
|
|
318.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
Revenues
|
$
|
261.3
|
|
|
$
|
333.7
|
|
|
$
|
382.4
|
|
|
$
|
399.7
|
|
|
$
|
1,377.1
|
|
Operating income (loss)
|
(1,379.0
|
)
|
|
(92.1
|
)
|
|
(93.1
|
)
|
|
(36.5
|
)
|
|
(1,600.7
|
)
|
Net income (loss)
|
(863.8
|
)
|
|
(197.0
|
)
|
|
(50.9
|
)
|
|
(133.3
|
)
|
|
(1,245.0
|
)
|
Net gain (loss) from asset sales and impairment
|
(1,181.9
|
)
|
|
(1.6
|
)
|
|
0.3
|
|
|
(6.1
|
)
|
|
(1,189.3
|
)
|
Nonrecurring items in operating income (loss)
(1)
|
7.7
|
|
|
—
|
|
|
25.0
|
|
|
—
|
|
|
32.7
|
|
Per share information
|
|
|
|
|
|
|
|
|
|
Basic EPS
|
$
|
(4.55
|
)
|
|
$
|
(0.90
|
)
|
|
$
|
(0.21
|
)
|
|
$
|
(0.56
|
)
|
|
$
|
(5.62
|
)
|
Diluted EPS
|
(4.55
|
)
|
|
(0.90
|
)
|
|
(0.21
|
)
|
|
(0.56
|
)
|
|
(5.62
|
)
|
Production information
|
|
|
|
|
|
|
|
|
|
Total equivalent production (Mboe)
|
13,776.4
|
|
|
13,882.4
|
|
|
14,445.7
|
|
|
13,675.7
|
|
|
55,780.2
|
|
Total equivalent production (Bcfe)
|
82.7
|
|
|
83.3
|
|
|
86.6
|
|
|
82.1
|
|
|
334.7
|
|
____________________________
|
|
(1)
|
Reflects legal expenses and loss contingencies incurred during the years ended
December 31, 2017
and
2016
.
|
Note 14 – Supplemental Oil and Gas Information (unaudited)
The Company is making the following supplemental disclosures of oil and gas producing activities, in accordance with ASC 932,
Extractive Activities
–
Oil and Gas,
as amended by ASU 2010-03,
Oil and Gas Reserve Estimation and Disclosures,
and SEC Regulation S-X. The Company uses the successful efforts accounting method for its oil and gas exploration and development activities. All of QEP's properties are located in the United States.
Capitalized Costs
The aggregate amounts of costs capitalized for oil and gas exploration and development activities and the related amounts of accumulated depreciation, depletion and amortization are shown below:
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2017
|
|
2016
|
|
(in millions)
|
Proved properties
|
$
|
12,470.9
|
|
|
$
|
14,232.5
|
|
Unproved properties, net
|
1,095.8
|
|
|
871.5
|
|
Total proved and unproved properties
|
13,566.7
|
|
|
15,104.0
|
|
Accumulated depreciation, depletion and amortization
|
(6,642.9
|
)
|
|
(8,797.7
|
)
|
Net capitalized costs
|
$
|
6,923.8
|
|
|
$
|
6,306.3
|
|
Costs Incurred
The costs incurred in oil and gas acquisition, exploration and development activities are displayed in the table below. Development costs are net of the change in accrued capital costs of
$60.6 million
and ARO additions and revisions of
$32.0 million
during the year ended
December 31, 2017
. The costs incurred for the development of reserves that were classified as proved undeveloped were approximately
$389.3 million
in
2017
,
$258.1 million
in
2016
, and
$490.4 million
in
2015
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2017
|
|
2016
|
|
2015
|
|
(in millions)
|
Proved property acquisitions
|
$
|
269.6
|
|
|
$
|
431.6
|
|
|
$
|
49.6
|
|
Unproved property acquisitions
|
532.4
|
|
|
208.7
|
|
|
39.8
|
|
Other acquisitions
|
13.2
|
|
|
—
|
|
|
—
|
|
Exploration costs (capitalized and expensed)
|
32.7
|
|
|
13.4
|
|
|
8.7
|
|
Development costs
|
1,189.3
|
|
|
509.2
|
|
|
1,010.3
|
|
Total costs incurred
|
$
|
2,037.2
|
|
|
$
|
1,162.9
|
|
|
$
|
1,108.4
|
|
Results of Operations
Following are the results of operations of QEP's oil and gas producing activities, before allocated corporate overhead and interest expenses.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2017
|
|
2016
|
|
2015
|
|
(in millions)
|
Revenues
|
$
|
1,548.1
|
|
|
$
|
1,271.0
|
|
|
$
|
1,390.4
|
|
Production costs
|
675.4
|
|
|
616.7
|
|
|
654.1
|
|
Exploration expenses
|
22.0
|
|
|
1.7
|
|
|
2.7
|
|
Depreciation, depletion and amortization
|
735.1
|
|
|
852.3
|
|
|
870.8
|
|
Impairment
|
72.3
|
|
|
1,194.3
|
|
|
55.6
|
|
Total expenses
|
1,504.8
|
|
|
2,665.0
|
|
|
1,583.2
|
|
Income (loss) before income taxes
|
43.3
|
|
|
(1,394.0
|
)
|
|
(192.8
|
)
|
Income tax benefit (expense)
|
(16.0
|
)
|
|
517.2
|
|
|
70.6
|
|
Results of operations from producing activities excluding allocated corporate overhead and interest expenses
|
$
|
27.3
|
|
|
$
|
(876.8
|
)
|
|
$
|
(122.2
|
)
|
Estimated Quantities of Proved Oil and Gas Reserves
Estimates of proved oil and gas reserves have been completed in accordance with professional engineering standards and the Company's established internal controls, which includes the 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, 2017
and
2016
, and retained RSC and DeGolyer and MacNaughton to prepare the estimates of all of its proved reserves as of
December 31, 2015
. 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, 2017
, 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, 2017
, all of the Company's oil and gas reserves are attributable to properties within the United Sates. A summary of the Company's change in quantities of proved oil, gas and NGL reserves for the years ended
December 31, 2015
,
2016
and
2017
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
Gas
|
|
NGL
|
|
Total
(13)
|
|
|
(MMbbl)
|
|
(Bcf)
|
|
(MMbbl)
|
|
(MMboe)
|
Balance at December 31, 2014
|
|
172.5
|
|
|
2,317.2
|
|
|
96.6
|
|
|
655.3
|
|
Revisions of previous estimates
(1)
|
|
(47.0
|
)
|
|
(463.8
|
)
|
|
(55.3
|
)
|
|
(179.6
|
)
|
Extensions and discoveries
(2)
|
|
85.6
|
|
|
467.7
|
|
|
21.8
|
|
|
185.4
|
|
Purchase of reserves in place
(3)
|
|
2.0
|
|
|
3.2
|
|
|
0.6
|
|
|
3.1
|
|
Sale of reserves in place
(4)
|
|
(0.4
|
)
|
|
(34.3
|
)
|
|
(0.2
|
)
|
|
(6.3
|
)
|
Production
|
|
(19.6
|
)
|
|
(181.1
|
)
|
|
(4.7
|
)
|
|
(54.5
|
)
|
Balance at December 31, 2015
|
|
193.1
|
|
|
2,108.9
|
|
|
58.8
|
|
|
603.4
|
|
Revisions of previous estimates
(5)
|
|
(9.7
|
)
|
|
412.8
|
|
|
(0.3
|
)
|
|
58.8
|
|
Extensions and discoveries
(6)
|
|
13.0
|
|
|
158.1
|
|
|
3.3
|
|
|
42.6
|
|
Purchase of reserves in place
(7)
|
|
62.7
|
|
|
54.6
|
|
|
11.5
|
|
|
83.3
|
|
Sale of reserves in place
(8)
|
|
(0.2
|
)
|
|
(3.6
|
)
|
|
(0.1
|
)
|
|
(0.9
|
)
|
Production
|
|
(20.3
|
)
|
|
(177.0
|
)
|
|
(6.0
|
)
|
|
(55.8
|
)
|
Balance at December 31, 2016
|
|
238.6
|
|
|
2,553.8
|
|
|
67.2
|
|
|
731.4
|
|
Revisions of previous estimates
(9)
|
|
3.7
|
|
|
12.5
|
|
|
(3.1
|
)
|
|
2.7
|
|
Extensions and discoveries
(10)
|
|
59.1
|
|
|
101.9
|
|
|
10.4
|
|
|
86.4
|
|
Purchase of reserves in place
(11)
|
|
46.6
|
|
|
125.5
|
|
|
8.7
|
|
|
76.3
|
|
Sale of reserves in place
(12)
|
|
(7.9
|
)
|
|
(831.2
|
)
|
|
(12.6
|
)
|
|
(159.0
|
)
|
Production
|
|
(19.6
|
)
|
|
(168.9
|
)
|
|
(5.4
|
)
|
|
(53.1
|
)
|
Balance at December 31, 2017
|
|
320.5
|
|
|
1,793.6
|
|
|
65.2
|
|
|
684.7
|
|
Proved developed reserves
|
|
|
|
|
|
|
|
|
Balance at December 31, 2014
|
|
99.3
|
|
|
1,288.4
|
|
|
52.2
|
|
|
366.2
|
|
Balance at December 31, 2015
|
|
109.7
|
|
|
1,245.3
|
|
|
34.4
|
|
|
351.6
|
|
Balance at December 31, 2016
|
|
103.2
|
|
|
1,309.8
|
|
|
35.7
|
|
|
357.2
|
|
Balance at December 31, 2017
|
|
116.0
|
|
|
655.5
|
|
|
27.9
|
|
|
253.1
|
|
Proved undeveloped reserves
|
|
|
|
|
|
|
|
|
Balance at December 31, 2014
|
|
73.2
|
|
|
1,028.8
|
|
|
44.4
|
|
|
289.1
|
|
Balance at December 31, 2015
|
|
83.4
|
|
|
863.6
|
|
|
24.4
|
|
|
251.8
|
|
Balance at December 31, 2016
|
|
135.4
|
|
|
1,244.0
|
|
|
31.5
|
|
|
374.2
|
|
Balance at December 31, 2017
|
|
204.5
|
|
|
1,138.1
|
|
|
37.3
|
|
|
431.6
|
|
___________________________
|
|
(1)
|
Revisions of previous estimates in 2015 include:
126.2
MMboe of negative revisions due to lower pricing and
67.2
MMboe of negative revisions unrelated to pricing, partially offset by
13.7
MMboe of positive performance revisions. Negative pricing revisions were driven by lower oil, gas and NGL prices. Negative other revisions included operating in ethane rejection in Pinedale and the Uinta Basin.
|
|
|
(2)
|
Extensions and discoveries in 2015 increased proved reserves by
185.4
MMboe, primarily related to extensions and discoveries in the Williston Basin of
68.2
MMboe, the Uinta Basin of
53.2
MMboe, and the Permian Basin of
49.6
MMboe. All of these extensions and discoveries related to new well completions and associated new PUD locations.
|
|
|
(3)
|
Purchase of reserves in place in 2015 related to the acquisition of additional interests in QEP operated wells in the Williston and Permian basins as discussed in
Note 2 – Acquisitions and Divestitures
.
|
|
|
(4)
|
Sale of reserves in place in 2015 relate to the divestiture of QEP's interest in certain non-core properties as discussed in
Note 2 – Acquisitions and Divestitures
.
|
|
|
(5)
|
Revisions of previous estimates in 2016 include
77.3
MMboe of positive revisions, primarily related to successful workovers in Haynesville/Cotton Valley; reserves associated with increased density wells in areas that have been previously developed on lower density spacing; and
5.5
MMboe of positive performance revisions. These positive revisions were partially offset by
18.5
MMboe of negative revisions related to pricing, driven by lower oil, gas and NGL prices.
|
|
|
(6)
|
Extensions and discoveries in 2016 were primarily in the Permian and Uinta basins and related to new well completions and associated new PUD locations.
|
|
|
(7)
|
Purchase of reserves in place in 2016 primarily relates to QEP's 2016 Permian Basin Acquisition as discussed in
Note 2 – Acquisitions and Divestitures
.
|
|
|
(8)
|
Sale of reserves in place in 2016 relates to the divestiture of QEP's interest in certain non-core properties as discussed in
Note 2 – Acquisitions and Divestitures
.
|
|
|
(9)
|
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.
|
|
|
(10)
|
Extensions and discoveries in 2017 primarily related to new well completions and associated new PUD locations in the Permian Basin.
|
|
|
(11)
|
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 2 – Acquisitions and Divestitures
.
|
|
|
(12)
|
Sale of reserves in place in
2017
was primarily related to QEP's Pinedale Divestiture as discussed in
Note 2 – Acquisitions and Divestitures
.
|
|
|
(13)
|
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.
|
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves
Future net cash flows were calculated at
December 31, 2017
,
2016
and
2015
, 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
2017
,
2016
and
2015
, 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the year ended December 31,
|
|
2017
|
|
2016
|
|
2015
|
Average benchmark price per unit:
|
|
|
|
|
|
Oil price (per bbl)
|
$
|
51.34
|
|
|
$
|
42.75
|
|
|
$
|
50.28
|
|
Gas price (per MMBtu)
|
$
|
2.98
|
|
|
$
|
2.48
|
|
|
$
|
2.59
|
|
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
$486.5 million
in
2018
,
$710.0 million
in
2019
and
$1,006.2 million
in
2020
. 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. In addition, QEP estimates that its future development costs relating to wells waiting on completion and its refracturing program, which are not classified as PUD, are approximately
$132.6 million
in 2018.
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:
|
|
•
|
Future commodity prices received for selling the Company's net production will likely differ from those required to be used in these calculations.
|
|
|
•
|
Future operating and capital costs will likely differ from those required to be used in these calculations.
|
|
|
•
|
Future market conditions, government regulations, reservoir conditions and risks inherent in the production of oil and gas may cause production rates in future years to vary significantly from those rates used in the calculations.
|
|
|
•
|
Future revenues may be subject to different production, severance and property taxation rates.
|
|
|
•
|
The selection of a 10% discount rate is arbitrary and may not be a reasonable factor in adjusting for future economic conditions or in considering the risk that is part of realizing future net cash flows from the reserves.
|
The standardized measure of discounted future net cash flows relating to proved reserves is presented in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2017
|
|
2016
|
|
2015
|
|
(in millions)
|
Future cash inflows
|
$
|
22,028.9
|
|
|
$
|
16,239.8
|
|
|
$
|
15,325.3
|
|
Future production costs
|
(9,074.2
|
)
|
|
(7,789.0
|
)
|
|
(7,389.9
|
)
|
Future development costs
(1)
|
(4,726.0
|
)
|
|
(3,432.9
|
)
|
|
(2,202.5
|
)
|
Future income tax expenses
(2)
|
(1,439.1
|
)
|
|
(913.4
|
)
|
|
(1,169.3
|
)
|
Future net cash flows
|
6,789.6
|
|
|
4,104.5
|
|
|
4,563.6
|
|
10% annual discount for estimated timing of net cash flows
|
(3,692.3
|
)
|
|
(2,176.5
|
)
|
|
(2,087.3
|
)
|
Standardized measure of discounted future net cash flows
|
$
|
3,097.3
|
|
|
$
|
1,928.0
|
|
|
$
|
2,476.3
|
|
___________________________
|
|
(1)
|
Future development costs include future abandonment and salvage costs.
|
|
|
(2)
|
The standardized measure of discounted future net cash flows for the year ended December 31, 2017, assumes the new
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2017
|
|
2016
|
|
2015
|
|
(in millions)
|
Balance at January 1,
|
$
|
1,928.0
|
|
|
$
|
2,476.3
|
|
|
$
|
5,340.0
|
|
Sales of oil, gas and NGL produced, net of production costs
|
(872.7
|
)
|
|
(654.3
|
)
|
|
(736.3
|
)
|
Net change in sales prices and in production (lifting) costs related to future production
|
1,457.2
|
|
|
(739.4
|
)
|
|
(6,307.8
|
)
|
Net change due to extensions and discoveries
|
556.8
|
|
|
81.8
|
|
|
1,765.7
|
|
Net change due to revisions of quantity estimates
|
9.9
|
|
|
122.7
|
|
|
(1,350.2
|
)
|
Net change due to purchases of reserves in place
|
342.7
|
|
|
256.5
|
|
|
29.7
|
|
Net change due to sales of reserves in place
|
(504.7
|
)
|
|
(4.3
|
)
|
|
(48.8
|
)
|
Previously estimated development costs incurred during the period
|
475.4
|
|
|
374.6
|
|
|
865.0
|
|
Changes in estimated future development costs
|
(283.4
|
)
|
|
(476.5
|
)
|
|
560.7
|
|
Accretion of discount
|
235.7
|
|
|
311.1
|
|
|
752.9
|
|
Net change in income taxes
|
(227.4
|
)
|
|
205.4
|
|
|
1,554.4
|
|
Other
|
(20.2
|
)
|
|
(25.9
|
)
|
|
51.0
|
|
Net change
|
1,169.3
|
|
|
(548.3
|
)
|
|
(2,863.7
|
)
|
Balance at December 31,
|
$
|
3,097.3
|
|
|
$
|
1,928.0
|
|
|
$
|
2,476.3
|
|
Note 15 – Subsequent Event
In February 2018, in conjunction with the 2017 Permian Basin Acquisition, QEP entered into agreements to acquire oil and gas properties in the Permian Basin for an aggregate purchase price of
$36.1 million
, subject to customary purchase price adjustments. The transactions are expected to be funded with borrowings under the credit facility and are expected to close in the first half of 2018.
In February 2018, the Board of Directors approved a retention and severance program in conjunction with the announcement of several strategic initiatives, which include selling assets and focusing the Company's activities on its Permian Basin operations. The estimated amount of general and administrative expenses to be incurred related to this program in 2018 is approximately
$20.0 million
.