QEP Resources, Inc.

    Print Page | Close Window

SEC Filings

10-Q
QEP RESOURCES, INC. filed this Form 10-Q on 04/25/2018
Entire Document
 
Document



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2018

o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ______ to ______

Commission File Number: 001-34778
http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12203079&doc=11
QEP RESOURCES, INC.

(Exact name of registrant as specified in its charter)
STATE OF DELAWARE
 
87-0287750
(State or other jurisdiction of
 
(I.R.S. Employer
incorporation or organization)
 
Identification No.)

1050 17th Street, Suite 800, Denver, Colorado 80265
(Address of principal executive offices)

Registrant's telephone number, including area code (303) 672-6900

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act:
Large accelerated filer
ý
Accelerated filer
o
Non-accelerated filer
o (Do not check if a smaller reporting company)
Smaller reporting company
o
 
 
Emerging growth company
o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o




Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý

At March 31, 2018, there were 237,708,346 shares of the registrant's common stock, $0.01 par value, outstanding.
 




QEP Resources, Inc.
Form 10-Q for the Quarter Ended March 31, 2018

TABLE OF CONTENTS
 
 
 
Page
 
 
 
 
 
ITEM 1.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
ITEM 2.
 
 
 
 
 
ITEM 3.
 
 
 
 
 
ITEM 4.
 
 
 
 
 
 
 
 
 
ITEM 1.
 
 
 
 
 
ITEM 1A.
 
 
 
 
 
ITEM 2.
 
 
 
 
 
ITEM 3.
 
 
 
 
 
ITEM 4.
 
 
 
 
 
ITEM 5.
 
 
 
 
 
ITEM 6.
 
 
 
 

1



PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS
QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
 
Three Months Ended
 
March 31,
 
2018
 
2017
REVENUES
(in millions, except per share amounts)
Oil and condensate, gas and NGL sales
$
409.8

 
$
385.2

Other revenue
5.0

 
4.0

Purchased oil and gas sales
14.1

 
30.9

Total Revenues
428.9

 
420.1

OPERATING EXPENSES
 
 
 
Purchased oil and gas expense
15.5

 
29.4

Lease operating expense
72.5

 
69.2

Transportation and processing costs
34.0

 
70.2

Gathering and other expense
2.8

 
1.5

General and administrative
60.1

 
33.6

Production and property taxes
28.9

 
29.1

Depreciation, depletion and amortization
196.5

 
191.8

Exploration expenses

 
0.4

Impairment
0.7

 
0.1

Total Operating Expenses
411.0

 
425.3

Net gain (loss) from asset sales
3.5

 

OPERATING INCOME (LOSS)
21.4

 
(5.2
)
Realized and unrealized gains (losses) on derivative contracts (Note 7)
(53.2
)
 
160.9

Interest and other income (expense)
(0.7
)
 
0.6

Interest expense
(35.0
)
 
(33.8
)
INCOME (LOSS) BEFORE INCOME TAXES
(67.5
)
 
122.5

Income tax (provision) benefit
13.9

 
(45.6
)
NET INCOME (LOSS)
$
(53.6
)
 
$
76.9

 
 
 
 
Earnings (loss) per common share
 
 
 
Basic
$
(0.22
)
 
$
0.32

Diluted
$
(0.22
)
 
$
0.32

 
 
 
 
Weighted-average common shares outstanding
 
 
 
Used in basic calculation
240.9

 
240.2

Used in diluted calculation
240.9

 
240.3

Dividends per common share
$

 
$


Refer to Notes accompanying the Condensed Consolidated Financial Statements.

2



QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
 
Three Months Ended
 
March 31,
 
2018
 
2017
 
(in millions)
Net income (loss)
$
(53.6
)
 
$
76.9

Other comprehensive income, net of tax:
 
 
 
Postretirement medical plan change(1)

 
1.6

Fair value of plan assets adjustment(2)
0.3

 

Pension and other postretirement plans adjustments:
 
 
 
Amortization of prior service costs(3)
0.1

 
0.1

Amortization of actuarial losses(4)
0.2

 
0.2

Other comprehensive income
0.6

 
1.9

Comprehensive income (loss)
$
(53.0
)
 
$
78.8

____________________________
(1) 
Presented net of income tax expense of $1.0 million for the three months ended March 31, 2017.
(2) 
Adjustment recorded during the three months ended March 31, 2018 related to a change in the fair value of plan assets as of December 31, 2017.
(3) 
Presented net of income tax expense of $0.1 million for the three months ended March 31, 2017.
(4) 
Presented net of income tax expense of $0.1 million for the three months ended March 31, 2018 and 2017, respectively.

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

3



QEP RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
 
March 31,
2018
 
December 31,
2017
ASSETS
(in millions)
Current Assets
 
 
 
Cash and cash equivalents
$

 
$

Accounts receivable, net
130.2

 
142.1

Income tax receivable
4.7

 
4.9

Fair value of derivative contracts
3.2

 
3.4

Hydrocarbon inventories, at lower of average cost or net realizable value
2.1

 
3.6

Prepaid expenses
9.4

 
10.7

Other current assets
0.2

 
0.7

Total Current Assets
149.8

 
165.4

Property, Plant and Equipment (successful efforts method for oil and gas properties)
 
 
 
Proved properties
12,676.1


12,470.9

Unproved properties
1,073.7


1,095.8

Gathering and other
383.4


319.7

Materials and supplies
38.4


37.8

Total Property, Plant and Equipment
14,171.6

 
13,924.2

Less Accumulated Depreciation, Depletion and Amortization
 
 
 
Exploration and production
6,660.8


6,642.9

Gathering and other
130.6


124.3

Total Accumulated Depreciation, Depletion and Amortization
6,791.4

 
6,767.2

Net Property, Plant and Equipment
7,380.2

 
7,157.0

Fair value of derivative contracts
4.5

 
0.1

Other noncurrent assets
74.1

 
72.3

TOTAL ASSETS
$
7,608.6


$
7,394.8

LIABILITIES AND EQUITY
 
 
 

Current Liabilities
 
 
 
Checks outstanding in excess of cash balances
$
19.8

 
$
44.0

Accounts payable and accrued expenses
400.9

 
364.6

Production and property taxes
31.9

 
31.6

Interest payable
33.4

 
26.0

Fair value of derivative contracts
116.9

 
103.6

Asset retirement obligations
10.1

 
7.5

Total Current Liabilities
613.0

 
577.3

Long-term debt
2,458.1

 
2,160.8

Deferred income taxes
504.0

 
518.0

Asset retirement obligations
200.4

 
206.6

Fair value of derivative contracts
32.8

 
31.8

Other long-term liabilities
103.6

 
102.4

Commitments and contingencies (Note 10)


 


EQUITY
 
 
 
Common stock – par value $0.01 per share; 500.0 million shares authorized;  240.3 million and 243.0 million shares issued, respectively
2.4

 
2.4

Treasury stock – 2.6 million and 2.0 million shares, respectively
(39.5
)
 
(34.2
)
Additional paid-in capital
1,408.0

 
1,398.2

Retained earnings
2,336.3

 
2,442.6

Accumulated other comprehensive income (loss)
(10.5
)
 
(11.1
)
Total Common Shareholders' Equity
3,696.7

 
3,797.9

TOTAL LIABILITIES AND EQUITY
$
7,608.6

 
$
7,394.8

 

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

4



QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENT OF EQUITY
(Unaudited)
 
Common Stock
 
Treasury Stock
 
Additional Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income(Loss)
 
Total
 
Shares
 
Amount
 
Shares
 
Amount
 
 
 
 
 
(in millions)
Balance at December 31, 2017
243.0

 
$
2.4

 
(2.0
)
 
$
(34.2
)
 
$
1,398.2

 
$
2,442.6

 
$
(11.1
)
 
$
3,797.9

Net income (loss)

 

 

 

 

 
(53.6
)
 

 
(53.6
)
Common stock repurchased and retired
(5.6
)
 
(0.1
)
 

 

 

 
(52.7
)
 

 
(52.8
)
Share-based compensation
2.9

 
0.1

 
(0.6
)
 
(5.3
)
 
9.8

 

 

 
4.6

Change in pension and postretirement liability, net of tax

 

 

 

 

 

 
0.6

 
0.6

Balance at March 31, 2018
240.3

 
$
2.4

 
(2.6
)
 
$
(39.5
)
 
$
1,408.0

 
$
2,336.3

 
$
(10.5
)
 
$
3,696.7


Refer to Notes accompanying the Condensed Consolidated Financial Statements.

5



QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
Three Months Ended
 
March 31,
 
2018
 
2017
OPERATING ACTIVITIES
(in millions)
Net income (loss)
$
(53.6
)
 
$
76.9

Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization
196.5

 
191.8

Deferred income taxes (benefit)
(14.1
)
 
45.6

Impairment
0.7

 
0.1

Share-based compensation
11.2

 
6.0

Amortization of debt issuance costs and discounts
1.3

 
1.5

Bargain purchase gain from acquisition

 
0.4

Net (gain) loss from asset sales
(3.5
)
 

Unrealized (gains) losses on marketable securities
0.1

 
(0.8
)
Unrealized (gains) losses on derivative contracts
10.0

 
(177.3
)
Changes in operating assets and liabilities
11.8

 
5.7

Net Cash Provided by (Used in) Operating Activities
160.4

 
149.9

INVESTING ACTIVITIES
 
 
 
Property acquisitions
(36.2
)
 
(68.2
)
Property, plant and equipment, including exploratory well expense
(370.7
)
 
(177.3
)
Proceeds from disposition of assets
33.3

 
0.2

Net Cash Provided by (Used in) Investing Activities
(373.6
)

(245.3
)
FINANCING ACTIVITIES
 
 
 
Checks outstanding in excess of cash balances
(24.2
)
 
(3.1
)
Proceeds from credit facility
1,068.5

 

Repayments of credit facility
(772.5
)
 

Common stock repurchased and retired
(52.8
)
 

Treasury stock repurchases
(4.7
)
 
(6.4
)
Net Cash Provided by (Used in) Financing Activities
214.3

 
(9.5
)
Change in cash, cash equivalents and restricted cash
1.1


(104.9
)
Beginning cash, cash equivalents and restricted cash(1)
23.4

 
465.4

Ending cash, cash equivalents and restricted cash(1)
$
24.5

 
$
360.5

 
 
 
 
Supplemental Disclosures:
 
 
 
Cash paid for interest, net of capitalized interest
$
26.0

 
$
32.3

Cash paid for income taxes, net
$

 
$

Non-cash Investing Activities:
 
 
 
Change in capital expenditure accruals and other non-cash adjustments
$
48.1

 
$
37.0

____________________________
(1) 
Refer to New Accounting Pronouncements in Note 1 – Basis of Presentation.

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

6



QEP RESOURCES, INC.
NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 1 – Basis of Presentation

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 Southern Region (primarily in Texas and Louisiana) and the Northern Region (primarily in North Dakota and Utah). 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".

Basis of Presentation of Interim Condensed Consolidated Financial Statements

The interim Condensed Consolidated Financial Statements contain the accounts of QEP and its majority-owned or controlled subsidiaries. The Condensed Consolidated Financial Statements were prepared in accordance with Generally Accepted Accounting Principles (GAAP) in the United States and with the instructions for Quarterly Reports on Form 10-Q and Regulation S-X. All significant intercompany accounts and transactions have been eliminated in consolidation.

The Condensed Consolidated Financial Statements reflect all normal recurring adjustments and accruals that are, in the opinion of management, necessary for a fair statement of financial position and results of operations for the interim periods presented. Interim Condensed Consolidated Financial Statements and the year-end balance sheet do not include all of the information and notes required by GAAP for audited annual consolidated financial statements. These Condensed Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 2017.

The preparation of the Condensed Consolidated Financial Statements and Notes in conformity with GAAP requires that management make estimates and assumptions that affect revenues, expenses, assets and liabilities, and disclosure of contingent assets and liabilities. Actual results could differ from estimates. The results of operations for the three months ended March 31, 2018, are not necessarily indicative of the results that may be expected for the year ending December 31, 2018.

Reclassifications

Certain prior period balances on the Condensed Consolidated Balance Sheets and Condensed Statements of Cash Flows have been reclassified to conform to the current year presentation. Such reclassifications had no effect on the Company's net income (loss), earnings (loss) per share or retained earnings previously reported.

Cash, Cash Equivalents and Restricted Cash

Cash equivalents consist principally of highly liquid investments in securities with original maturities of three months or less made through commercial bank accounts that result in available funds the next business day. Restricted cash are funds that are legally or contractually reserved for a specific purpose and therefore not available for immediate or general business use.

7




The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the Condensed Consolidated Balance Sheets to the amounts shown in the Condensed Consolidated Statements of Cash Flows:

 
March 31,
 
2018
 
2017
 
(in millions)
Cash and cash equivalents
$

 
$
338.4

Restricted cash(1)
24.5

 
22.1

Total cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows
$
24.5

 
$
360.5

_______________________
(1) 
As of March 31, 2018, the restricted cash balance consisted of $24.5 million included within "Other noncurrent assets" on the Condensed Consolidated Balance Sheet. As of March 31, 2017, the restricted cash balance consisted of $20.9 million included within "Other noncurrent assets" and $1.2 million included within "Prepaid expenses" on the Condensed Consolidated Balance Sheet provided within the Quarterly Report on Form 10-Q. QEP's restricted cash is primarily cash deposited into an escrow account related to a title dispute between third parties in the Williston Basin.

New Accounting Pronouncements

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 revenue 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 are required. The amendment was effective prospectively for reporting periods beginning on or after December 15, 2017, and early adoption was 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 has selected the modified retrospective method and adopted this standard in the first quarter of 2018. Refer to Note 2 – Revenue for more information.

In conjunction with ASU No. 2014-09, in March 2016, the FASB issued ASU No. 2016-08, Revenue from contracts with customers (Topic 606): Principal versus agent considerations (reporting revenue gross versus net), which clarifies the implementation guidance on principal versus agent considerations. In April 2016, the FASB issued ASU No. 2016-10, Revenue from contracts with customers (Topic 606): Identifying performance obligations and licensing, which clarifies guidance related to identifying performance obligations and licensing implementation guidance contained in the new revenue recognition standard. In May 2016, the FASB issued ASU No. 2016-11, Revenue recognition (Topic 605) and Derivatives and hedging (Topic 815): Rescission of SEC guidance because of ASU 2014-09 and 2014-16, which rescinds certain SEC staff observer comments that are codified in Topic 605, Revenue Recognition. In May 2016, the FASB issued ASU No. 2016-12, Revenue from contracts with customers (Topic 606): Narrow-scope improvements and practical expedients, which intends to reduce the cost and complexity of applying the new revenue standard by narrowing the scope of improvements to the guidance on collectability, non-cash consideration, and completed contracts at transition. In December 2016, the FASB issued ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers, which intends to make corrections or improvements to the FASB Accounting Standards Codification which includes guidance and reference clarification, simplification and minor improvements. These amendments were effective prospectively for reporting periods beginning on or after December 31, 2017, and early adoption is permitted for periods beginning on or after December 31, 2016. The Company adopted these ASUs in the first quarter of 2018. Refer to Note 2 – Revenue for more information.


8



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 disclosing key quantitative and qualitative information about leasing arrangements. The amendment will be effective for reporting periods beginning on or after December 15, 2018, and early adoption is permitted. The Company is currently assessing the impact of the ASU on the Company's Condensed Consolidated Financial Statements.

In October 2016, the FASB issued ASU No. 2016-16, Accounting for Income Taxes: Intra-Entity Asset Transfers of Assets Other than Inventory, which intends to reduce the complexity in accounting standards related to intra-entity asset transfers by requiring a reporting entity to recognize the tax effects from the sale of assets when a transfer occurs, even though the pre-tax effects of the transaction are eliminated in consolidation. This amendment was effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption was permitted. The Company adopted this standard in the first quarter of 2018 and the adoption of this new standard did not have a material impact on the Company's Condensed Consolidated Financial Statements.

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted cash, which intends to clarify how entities should present restricted cash and restricted cash equivalents in the statement of cash flows. This amendment was effective retrospectively for reporting periods after December 15, 2017, and early adoption was permitted. The Company adopted this standard in the first quarter of 2018 and the adoption of this standard did not have a material impact on the Company's Condensed Consolidated Statements of Cash Flows.

In February 2018, the FASB issued ASU No. 2018-02, Income statement - Reporting comprehensive income (Topic 220) - Reclassification of certain tax effects from accumulated other comprehensive income, which allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017. 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 Condensed Consolidated Financial Statements.

Note 2 – Revenue

Adoption of ASC Topic 606, Revenue from Contracts with Customers

On January 1, 2018, QEP adopted ASC Topic 606, Revenue from Contracts with Customers, using the modified retrospective approach, which was applied to those contracts which were not completed as of January 1, 2018. Results for reporting periods beginning January 1, 2018, are presented in accordance with ASC Topic 606, while prior period amounts are reported in accordance with ASC Topic 605, Revenue Recognition.

In accordance with ASC Topic 606, QEP now records transportation and processing costs that are incurred after control of its product has transferred to the customer as a reduction of "Oil and condensate, gas and NGL sales" on the Condensed Consolidated Statement of Operations. Prior to the adoption of ASC Topic 606, these transportation and processing costs were recorded as an expense within "Transportation and processing costs" on the Condensed Consolidated Statement of Operations. There was no impact to net income (loss) or opening retained earnings as a result of adopting ASC Topic 606.


9



The following table presents the impact to the Condensed Consolidated Statement of Operations as a result of adopting ASC Topic 606.

 
Three Months Ended
 
March 31, 2018
 
As Reported
 
ASC 606 Adjustments
 
As Adjusted(1)
REVENUES
(in millions, except per share amounts)
Oil and condensate, gas and NGL sales
$
409.8

 
$
12.7

 
$
422.5

Other revenue
5.0

 

 
5.0

Purchased oil and gas sales
14.1

 

 
14.1

Total Revenues
428.9

 
12.7

 
441.6

OPERATING EXPENSES
 
 
 
 
 
Purchased oil and gas expense
15.5

 

 
15.5

Lease operating expense
72.5

 

 
72.5

Transportation and processing costs
34.0

 
12.7

 
46.7

Gathering and other expense
2.8

 

 
2.8

General and administrative
60.1

 

 
60.1

Production and property taxes
28.9

 

 
28.9

Depreciation, depletion and amortization
196.5

 

 
196.5

Exploration expenses

 

 

Impairment
0.7

 

 
0.7

Total Operating Expenses
411.0


12.7

 
423.7

Net gain (loss) from asset sales
3.5

 

 
3.5

OPERATING INCOME (LOSS)
21.4



 
21.4

Realized and unrealized gains (losses) on derivative contracts (Note 7)
(53.2
)
 

 
(53.2
)
Interest and other income (expense)
(0.7
)
 

 
(0.7
)
Interest expense
(35.0
)
 

 
(35.0
)
INCOME (LOSS) BEFORE INCOME TAXES
(67.5
)


 
(67.5
)
Income tax (provision) benefit
13.9

 

 
13.9

NET INCOME (LOSS)
$
(53.6
)

$

 
$
(53.6
)
 
 
 
 
 
 
Earnings (loss) per common share
 
 
 
 
 
Basic
$
(0.22
)
 
$

 
$
(0.22
)
Diluted
$
(0.22
)
 
$

 
$
(0.22
)
 
 
 
 
 
 
Weighted-average common shares outstanding
 
 
 
 
 
Used in basic calculation
240.9

 

 
240.9

Used in diluted calculation
240.9

 

 
240.9

Dividends per common share
$

 
$

 
$

_______________________
(1) 
This column excludes the impact of adopting ASC Topic 606 and is consistent with the presentation prior to January 1, 2018.


10



Revenue Recognition

QEP recognizes revenue from the sales of oil and condensate, gas and NGL in the period that the performance obligations are satisfied. QEP's performance obligations are satisfied when the customer obtains control of product, when we have no further obligations to perform related to the sale, when the transaction price has been determined and when collectability is probable. The sales of oil and condensate, gas and NGL are made under contracts with customers, which typically include variable consideration that is based on pricing tied to local indices and volumes delivered in the current month. Revenues include estimates for the two most recent months using published commodity price indexes and volumes supplied by field operators. Performance obligations under our contracts with customers are typically satisfied at a point-in-time through monthly delivery of oil and condensate, gas and/or NGL. Our contracts with customers typically require payment for oil and condensate, gas and NGL sales within 30 days following the calendar month of delivery.

QEP's oil is typically sold at specific delivery points under contract terms that are common in our industry. QEP's gas and NGL are sold under a limited number of contract types that are also common in our industry; however, under these contracts, the gas and its components, including NGL, may be sold to a single purchaser or the residue gas and NGL may be sold to separate purchasers. Regardless of the contract type, the terms of these contracts compensate the Company for the value of the residue gas and NGL constituent components at current market prices for each product. 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 in the period that the performance obligations are satisfied. A wellhead imbalance liability is recorded to the extent that QEP has sold volumes in excess of its share of remaining reserves in an underlying property.


11



The following tables present our revenues disaggregated by revenue source and by geographic area. Transportation and processing costs in the following tables are not all of the transportation and processing costs that the Company incurs, only the expenses that are netted against revenues pursuant to ASC 606.

 
Oil and condensate sales
 
Gas sales
 
NGL sales
 
Transportation and processing costs included in revenue
 
Oil and condensate, gas and NGL sales, as presented
 
(in millions)
 
Three Months Ended March 31, 2018
Northern Region
 
 
 
 
 
 
 
 
 
Williston Basin
$
160.5

 
$
9.8

 
$
11.8

 
$
(9.9
)
 
$
172.2

Uinta Basin
8.4

 
10.1

 
1.7

 

 
20.2

Other Northern
1.9

 
1.0

 
(0.2
)
 

 
2.7

Southern Region
 
 
 
 
 
 
 
 
 
Permian Basin
129.8

 
4.6

 
6.5

 
(2.8
)
 
138.1

Haynesville/Cotton Valley
0.4

 
76.4

 

 

 
76.8

Other Southern
(0.3
)
 
0.1

 

 

 
(0.2
)
Total oil and condensate, gas and NGL sales
$
300.7

 
$
102.0

 
$
19.8

 
$
(12.7
)
 
$
409.8

 
 
 
 
 
 
 
 
 
 
 
Three Months Ended March 31, 2017(1)
Northern Region
 
Williston Basin
$
155.4

 
$
12.0

 
$
12.5

 
$

 
$
179.9

Pinedale
6.8

 
60.6

 
11.6

 

 
79.0

Uinta Basin
7.4

 
14.6

 
1.6

 

 
23.6

Other Northern
1.4

 
5.9

 
0.1

 

 
7.4

Southern Region
 
 
 
 
 
 
 
 
 
Permian Basin
50.2

 
3.2

 
3.1

 

 
56.5

Haynesville/Cotton Valley
0.4

 
38.2

 
0.1

 

 
38.7

Other Southern
0.1

 

 

 

 
0.1

Total oil and condensate, gas and NGL sales
$
221.7

 
$
134.5

 
$
29.0

 
$

 
$
385.2

_______________________
(1) 
Prior period amounts have not been adjusted under the modified retrospective method.

Note 3 – Acquisitions and Divestitures

Acquisitions

During the three months ended March 31, 2018, QEP acquired various oil and gas properties, which primarily included proved and unproved leasehold acreage in the Permian Basin for an aggregate purchase price of $36.2 million, subject to customary purchase price adjustments. Of the $36.2 million, $35.7 million was related to acquisitions from various persons who owned additional oil and gas interests in certain properties included in the 2017 acquisition of oil and gas properties in the Permian Basin (the 2017 Permian Basin Acquisition) on substantially the same terms and conditions as the 2017 Permian Basin Acquisition in the fourth quarter of 2017.

During the three months ended March 31, 2017, QEP acquired various oil and gas properties, which primarily included proved and unproved leasehold acreage and additional surface acreage in the Permian Basin, for an aggregate purchase price of $68.2 million. In conjunction with these acquisitions, the Company recorded $5.3 million of goodwill, which was subsequently impaired in 2017.


12



2018 Strategic Initiatives

In February 2018, QEP's Board of Directors unanimously approved certain strategic and financial initiatives (Strategic Initiatives) including plans to market its assets in the Williston Basin, the Uinta Basin and Haynesville/Cotton Valley and focus its activities in the Permian Basin. As a part of this process, in February 2018, the Company engaged advisors to assist with the divestitures of its Williston Basin and Uinta Basin assets and has provided data for potential buyers in April 2018. The assets will be considered held for sale once it is deemed unlikely that there will be any significant changes to QEP's divestiture plan, which QEP believes will be upon the execution of purchase and sale agreements.

Pinedale Divestiture

In September 2017, QEP sold its assets in Pinedale (the Pinedale Divestiture), for net cash proceeds (after purchase price adjustments) of $718.2 million, subject to additional post-closing purchase price adjustments. For the three months ended March 31, 2018, QEP recorded a pre-tax gain on sale of $1.0 million, due to post-closing purchase price adjustments, which were recorded within "Net gain (loss) from asset sales" on the Condensed Consolidated Statements of Operations. For the three months ended March 31, 2017, QEP had net income before income taxes related to the divested Pinedale properties of $28.0 million.

As a part of the Pinedale Divestiture, QEP agreed to reimburse the buyer for certain deficiency charges it incurs related to gas processing and NGL transportation and fractionation contracts between the effective date of the sale and December 31, 2019, in an aggregate amount not to exceed $45.0 million. As of March 31, 2018, the liability associated with estimated future payments for this commitment was $27.3 million, of which $22.9 million is reported on the Condensed Consolidated Balance Sheets within "Accounts payable and accrued expenses" and $4.4 million is reported on the Condensed Consolidated Balance Sheets within "Other long-term liabilities".

Other Divestitures

During the three months ended March 31, 2018, QEP received proceeds of $33.3 million and recorded a pre-tax gain on sale of $2.5 million, primarily related to the divestiture of properties outside our main operating areas in the Williston Basin and Other Northern area.

The gains and losses were recorded within "Net gain (loss) from asset sales" on the Condensed Consolidated Statements of Operations.

Note 4 – Earnings Per Share

Basic earnings 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 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. During the three months ended March 31, 2018 and 2017, there were no anti-dilutive shares.


13



The following is a reconciliation of the components of basic and diluted shares used in the EPS calculation:
 
Three Months Ended
 
March 31,
 
2018
 
2017
 
(in millions)
Weighted-average basic common shares outstanding
240.9

 
240.2

Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan

 
0.1

Average diluted common shares outstanding
240.9

 
240.3


Note 5 – Asset Retirement Obligations

QEP records asset retirement obligations (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 $210.5 million and $214.1 million ARO liability for the periods ended March 31, 2018 and December 31, 2017, respectively, $10.1 million and $7.5 million, respectively, were included as a current liability within "Asset retirement obligations" on the Condensed Consolidated Balance Sheets.

The following is a reconciliation of the changes in the Company's ARO for the period specified below:
 
Asset Retirement Obligations
 
2018
 
(in millions)
ARO liability at January 1,
$
214.1

Accretion
1.7

Additions
1.5

Revisions
(3.4
)
Liabilities related to assets sold
(3.4
)
ARO liability at March 31,
$
210.5


Note 6 – Fair Value Measurements

QEP measures and discloses fair values in accordance with the provisions of ASC 820, Fair Value Measurements and Disclosures. This guidance defines fair value in applying GAAP, establishes a framework for measuring fair value and expands disclosures about fair value measurements. ASC 820 also establishes a fair value hierarchy. Level 1 inputs are quoted prices (unadjusted) for identical assets or liabilities in active markets that the Company has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability.

QEP has determined that its commodity derivative instruments are Level 2. The Level 2 fair value of commodity derivative contracts (refer to Note 7 – Derivative Contracts) 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.


14



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 March 31, 2018 and December 31, 2017, is shown in the table below:
 
Fair Value Measurements
 
Gross Amounts of Assets and Liabilities
 
Netting Adjustments(1)
 
Net Amounts Presented on the Condensed Consolidated Balance Sheets
 
Level 1
 
Level 2
 
Level 3
 
 
 
March 31, 2018
Financial Assets
(in millions)
Fair value of derivative contracts – short-term
$

 
$
16.3

 
$

 
$
(13.1
)
 
$
3.2

Fair value of derivative contracts – long-term

 
8.1

 

 
(3.6
)
 
4.5

Total financial assets
$

 
$
24.4

 
$

 
$
(16.7
)
 
$
7.7


 
 
 
 
 
 
 
 
 
Financial Liabilities
 
 
 
 
 
 
 
 
 
Fair value of derivative contracts – short-term
$

 
$
130.0

 
$

 
$
(13.1
)
 
$
116.9

Fair value of derivative contracts – long-term

 
36.4

 

 
(3.6
)
 
32.8

Total financial liabilities
$

 
$
166.4

 
$

 
$
(16.7
)
 
$
149.7

 
 
 
 
 
 
 
 
 
 
 
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

_______________________
(1) 
The Company nets its derivative contract assets and liabilities outstanding with the same counterparty on the Condensed Consolidated Balance Sheets, for the contracts that contain netting provisions. Refer to Note 7 – Derivative Contracts for additional information regarding the Company's derivative contracts.


15



The following table discloses the fair value and related carrying amount of certain financial instruments not disclosed in other Notes to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q:
 
Carrying Amount
 
Level 1 Fair Value
 
Carrying Amount
 
Level 1 Fair Value
 
March 31, 2018
 
December 31, 2017
Financial Assets
(in millions)
Cash and cash equivalents
$

 
$

 
$

 
$

Financial Liabilities
 
 
 
 
 
 
 
Checks outstanding in excess of cash balances
$
19.8

 
$
19.8

 
$
44.0

 
$
44.0

Long-term debt
$
2,458.1

 
$
2,456.7

 
$
2,160.8

 
$
2,256.2


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 quarter.

The fair value of the deficiency charge obligation associated with the Pinedale Divestiture 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.

The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and is based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the calculation of ARO includes plugging costs and reserve lives. A reconciliation of the Company's ARO is presented in Note 5 – Asset Retirement Obligations.

Nonrecurring Fair Value Measurements

The provisions of the fair value measurement standard are also applied to the Company's nonrecurring measurements. The Company utilizes fair value on a periodic basis 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. The fair value of property is measured utilizing the income approach and utilizing inputs that are primarily based upon internally developed cash flow models discounted at an appropriate weighted average cost of capital. Given the unobservable nature of the inputs, fair value calculations associated with proved oil and gas property impairments are considered Level 3 within the fair value hierarchy. During the three months ended March 31, 2018, the Company recorded impairments on certain proved oil and gas properties of $0.5 million, resulting in a reduction of the associated carrying amount to fair value. During the three months ended March 31, 2017, the Company recorded no impairments on proved 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 and condensate, 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.

Note 7 – Derivative Contracts

QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. In the normal course of business, QEP uses commodity price derivative instruments to reduce the impact of potential downward movements in commodity prices on cash flow, returns on capital investment, and other financial results. However, these instruments typically limit gains from favorable price movements. The volume of production subject to commodity derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. QEP may enter into commodity derivative contracts for up to 100% of forecasted production, but generally, QEP enters into commodity derivative contracts for approximately 50% to 75% of its forecasted annual production by the end of the first quarter of each fiscal year. 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.

16




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 Intercontinental Exchange, Inc. (ICE) Brent oil prices as the reference price. Gas price derivative instruments are typically structured as fixed-price swaps or 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 March 31, 2018:
Year
 
Index
 
Total Volumes
 
Average Swap Price per Unit
 
 
 
 
(in millions)
 
 
Oil sales
 
 
 
(bbls)

 
($/bbl)

2018 (April through December)
 
NYMEX WTI
 
12.7

 
$
52.48

2019
 
NYMEX WTI
 
9.5

 
$
52.66

Gas sales
 
 
 
(MMBtu)

 
($/MMBtu)

2018 (April through December)
 
 NYMEX HH
 
82.5

 
$
2.99

2018 (July through December)
 
 NYMEX HH
 
1.8

 
$
3.01

2019
 
NYMEX HH
 
43.8

 
$
2.86


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 March 31, 2018:
Year
 
Index Less Differential
 
Index
 
Total Volumes
 
Weighted-Average Differential
 
 
 
 
 
 
(in millions)
 
 
Oil sales
 
 
 
 
 
(bbls)

 
($/bbl)

2018 (April through December)
 
NYMEX WTI
 
Argus WTI Midland
 
5.5

 
$
(1.06
)
2018 (July through December)
 
NYMEX WTI
 
Argus WTI Midland
 
0.9

 
$
(0.71
)
2019
 
NYMEX WTI
 
Argus WTI Midland
 
4.7

 
$
(0.77
)
Gas sales
 
 
 
 
 
(MMBtu)

 
($/MMBtu)

2018 (April through December)
 
NYMEX HH
 
IFNPCR
 
5.5

 
$
(0.16
)

17




QEP Derivative Financial Statement Presentation
The following table identifies the Condensed Consolidated Balance Sheet location of QEP's outstanding derivative contracts on a gross contract basis as opposed to the net contract basis presentation on the Condensed 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
 
Balance Sheet line item
 
March 31,
2018
 
December 31,
2017
 
March 31,
2018
 
December 31,
2017
Current:
 
 
(in millions)
Commodity
Fair value of derivative contracts
 
$
16.3

 
$
20.6

 
$
130.0

 
$
120.8

Long-term:
 
 
 
 
 
 
 
 
 
Commodity
Fair value of derivative contracts
 
8.1

 
2.3

 
36.4

 
34.0

Total derivative instruments
 
$
24.4

 
$
22.9

 
$
166.4

 
$
154.8


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 Condensed Consolidated Statements of Operations are summarized in the following table:
 
Three Months Ended
Derivative contracts not designated as cash flow hedges
March 31,
2018
 
2017
Realized gains (losses) on commodity derivative contracts
(in millions)
Production
 
 
 
Oil derivative contracts
$
(44.3
)
 
$
(2.0
)
Gas derivative contracts
0.9

 
(14.2
)
Gas Storage
 
 
 
Gas derivative contracts
0.2

 
(0.2
)
Realized gains (losses) on commodity derivative contracts
(43.2
)
 
(16.4
)
Unrealized gains (losses) on commodity derivative contracts
 
 
 
Production
 
 
 
Oil derivative contracts
(6.9
)
 
104.3

Gas derivative contracts
(2.8
)
 
71.1

Gas Storage
 
 
 
Gas derivative contracts
(0.3
)
 
1.9

Unrealized gains (losses) on commodity derivative contracts
(10.0
)
 
177.3

Total realized and unrealized gains (losses) on commodity derivative contracts
$
(53.2
)
 
$
160.9


Note 8 – Restructuring

On February 28, 2018, QEP announced its intention to become a pure-play Permian Basin company, which includes plans to market its assets in the Williston Basin, the Uinta Basin and Haynesville/Cotton Valley. As a part of the Strategic Initiatives, QEP has incurred or expects to incur costs associated with contractual termination benefits including severance and accelerated vesting of share-based compensation. These termination benefits will be accounted for under ASC 712, Compensation - Nonretirement Postemployment Benefits and ASC 718, Compensation - Stock Compensation. During the first quarter of 2018, the Company incurred but has not yet paid $6.2 million of costs associated with these termination benefits, including $3.4 million of severance and $2.8 million of accelerated share-based compensation, recorded in "Accounts payable and accrued expenses" and "General and administrative" expense in the Condensed Consolidated Financial Statements. Due to the nature of the Strategic Initiatives and uncertain factors such as timing and terms of the potential divestitures, the Company is not able to reasonably estimate the total cost to be incurred as a part of this restructuring.

18




In connection with the Strategic Initiatives, QEP also approved an employee retention program and recognized $1.7 million of expense during the three months ended March 31, 2018 and recorded these costs in "Accounts payable and accrued expenses" and "General and administrative" expense in the Condensed Consolidated Financial Statements. QEP expects to incur an additional $18.3 million of expense in 2018 and $5.0 million in 2019 related to the retention program.

Note 9 – Debt

As of the indicated dates, the principal amount of QEP's debt consisted of the following:
 
March 31,
2018
 
December 31,
2017
 
(in millions)
Revolving Credit Facility due 2022
$
385.0

 
$
89.0

6.80% Senior Notes due 2020
51.7

 
51.7

6.875% Senior Notes due 2021
397.6

 
397.6

5.375% Senior Notes due 2022
500.0

 
500.0

5.25% Senior Notes due 2023
650.0

 
650.0

5.625% Senior Notes due 2026
500.0

 
500.0

Less: unamortized discount and unamortized debt issuance costs
(26.2
)
 
(27.5
)
Total long-term debt outstanding
$
2,458.1

 
$
2,160.8


Of the total debt outstanding on March 31, 2018, 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
QEP's revolving credit facility, which matures, subject to satisfaction of certain conditions, in September 2022, provides for loan commitments of $1.25 billion. The credit facility provides for borrowings at short-term interest rates and contains customary covenants and restrictions. The credit agreement contains financial covenants (that are defined in the credit agreement) that limit the amount of debt the Company can incur and may limit the amount available to be drawn under the credit facility including: (i) a net funded debt to capitalization ratio that may not exceed 60%, (ii) a leverage ratio under which net funded debt may not exceed 4.00 times consolidated EBITDA (as defined in the credit agreement) 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. At March 31, 2018 and December 31, 2017, QEP was in compliance with the covenants under the credit agreement.

During the three months ended March 31, 2018, QEP's weighted-average interest rates on borrowings from its credit facility were 3.75%. As of March 31, 2018, QEP had $385.0 million of borrowings outstanding and $1.0 million in letters of credit outstanding under the credit facility. 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.

Senior Notes
At March 31, 2018, 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.


19



Note 10 – 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 Condensed 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.

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.

Note 11 – Share-Based Compensation

QEP issues stock options, restricted share awards and restricted share units under its Long-Term Stock Incentive Plan (LTSIP) and awards performance share units under its Cash Incentive Plan (CIP) to certain officers, employees and non-employee directors. QEP recognizes the expense over the vesting periods for the stock options, restricted share awards, restricted share units and performance share units. There were 2.4 million shares available for future grants under the LTSIP at March 31, 2018.

Share-based compensation expense is recognized within "General and administrative" expense on the Condensed Consolidated Statements of Operations and is summarized in the table below. During the three months ended March 31, 2018, the Company recorded an additional $2.8 million of share-based compensation expense related to the acceleration of vesting incurred as part of the severance program (refer to Note 8 – Restructuring for additional information):
 
Three Months Ended
 
March 31,
 
2018
 
2017
 
(in millions)
Stock options
$
0.5

 
$
0.6

Restricted share awards
8.8

 
7.3

Performance share units
1.9

 
(1.9
)
Restricted share units

 

Total share-based compensation expense
$
11.2

 
$
6.0


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 recognizes forfeitures of stock options as they occur.

In 2018, QEP did not issue stock options as the Company continues to evaluate the components of its incentive compensation package to better align our Long-Term Incentive awards with those typical of the industry.

20




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, 2017
2,354,277

 
$
23.62

 
 
 
 
Canceled
(202,235
)
 
39.07

 
 
 
 
Outstanding at March 31, 2018
2,152,042

 
$
22.17

 
3.56
 
$

Options Exercisable at March 31, 2018
1,743,963

 
$
23.96

 
3.10
 
$

Unvested Options at March 31, 2018
408,079

 
$
14.51

 
5.56
 
$


During the three months ended March 31, 2018 and 2017, there were no exercises of stock options. As of March 31, 2018, $1.1 million of unrecognized compensation expense related to stock options granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 1.87 years. The weighted-average vesting period may be reduced under the severance program (refer to Note 8 – Restructuring for additional information).

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 recognizes restricted share forfeitures as they occur. The total fair value of restricted share awards that vested during the three months ended March 31, 2018 and 2017 was $21.0 million and $20.3 million, respectively. The weighted-average grant date fair value of restricted share awards was $9.55 per share and $17.02 per share for the three months ended March 31, 2018 and 2017, respectively. As of March 31, 2018, $37.4 million of unrecognized compensation expense related to restricted share awards granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 2.59 years. The weighted-average vesting period may be reduced under the severance program (refer to Note 8 – Restructuring for additional information).

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, 2017
3,721,334

 
$
13.23

Granted
2,929,369

 
9.55

Vested
(1,414,155
)
 
14.83

Forfeited
(86,386
)
 
11.31

Unvested balance at March 31, 2018
5,150,162

 
$
10.73


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 March 31, 2018, 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 Condensed Consolidated Balance Sheets. As these awards are dependent upon the Company's total shareholder return and stock price, they are remeasured at fair value at the end of each reporting period. The weighted-average grant date fair value of the performance share units was $9.55 per share and $16.98 per share for the three months ended March 31, 2018 and 2017, respectively. As of March 31, 2018, $10.1 million of unrecognized compensation expense, which represents the unvested portion of the fair market value of performance shares granted, is expected to be recognized over a weighted-average vesting period of 2.39 years. The weighted-average vesting period may be reduced under the severance program (refer to Note 8 – Restructuring for additional information).


21



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, 2017
1,199,336

 
$
14.59

Granted
724,095

 
9.55

Vested and Paid
(229,620
)
 
21.69

Unvested balance at March 31, 2018
1,693,811

 
$
11.47


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 paid in cash. They are classified as liabilities and are included in "Other long-term liabilities" on the Condensed 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 $9.55 and $16.98 per share for the three months ended March 31, 2018 and 2017, respectively. As of March 31, 2018, $0.3 million of unrecognized compensation expense, 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 2.00 years. The weighted-average vesting period may be reduced under the severance program (refer to Note 8 – Restructuring for additional information).

Transactions involving restricted share units under the terms of the LTSIP are summarized below:
 
Restricted Share Units Outstanding
 
Weighted-Average Grant Date Fair Value
 
 
 
(per share)
Unvested balance at December 31, 2017
21,946

 
$
13.22

Granted
31,835

 
9.55

Vested
(9,320
)
 
12.56

Unvested balance at March 31, 2018
44,461

 
$
10.73


Note 12 – 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. During the three months ended March 31, 2018, the Company made contributions of $2.0 million to the Pension Plan and expects to make an additional $2.0 million to the Pension Plan during the remainder of 2018. Contributions to the Pension Plan increase plan assets. 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.

The SERP is a nonqualified retirement plan that is unfunded and provides pension benefits to certain QEP employees. During the three months ended March 31, 2018, the Company made contributions of $0.2 million to its SERP and expects to contribute an additional $0.5 million to its SERP during the remainder of 2018. Contributions to the SERP are used to fund current benefit payments. The SERP was amended and restated in June 2015 and was closed to new participants effective January 1, 2016.

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. During the three months ended March 31, 2018, the Company made contributions of $0.1 million to its Medical Plan and expects to contribute an additional $0.1 million to its Medical Plan during the remainder of 2018. Contributions to the Medical Plan are used to fund current benefit payments.


22



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 retirees and spouses that are both Medicare eligible. In addition, the Company no longer offers life insurance to individuals retiring on or after July 1, 2017.

The Company recognizes service costs related to SERP and Medical Plan benefits on the Condensed 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 Condensed Consolidated Statements of Operations within "Interest and other income (expense)".

The following table sets forth the Company's net periodic benefit costs related to its Pension Plan, SERP and Medical Plan:
 
Three Months Ended
 
March 31,
 
2018
 
2017
Pension Plan and SERP benefits
(in millions)
Service cost
$
0.2

 
$
0.3

Interest cost
1.1

 
1.2

Expected return on plan assets
(1.4
)
 
(1.3
)
Amortization of prior service costs(1)
0.2

 
0.3

Amortization of actuarial losses(1)
0.3

 
0.3

Periodic expense
$
0.4

 
$
0.8

 
 
 
 
Medical Plan benefits
 
 
 
Amortization of prior service costs(1)
(0.1
)
 
(0.1
)
Periodic expense
$
(0.1
)
 
$
(0.1
)
____________________________
(1) 
Amortization of prior service costs and actuarial losses out of accumulated other comprehensive income are recognized on the Condensed Consolidated Statements of Operations within "Interest and other income (expense)".

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company's operating results. MD&A should be read in conjunction with the Condensed Consolidated Financial Statements and related Notes included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

The following information updates the discussion of QEP's financial condition provided in its Annual Report on Form 10-K for the year ended December 31, 2017 (2017 Form 10-K) and analyzes the changes in the results of operations between the three months ended March 31, 2018 and 2017. For definitions of commonly used oil and gas terms found in this Quarterly Report on Form 10-Q, please refer to the "Glossary of Terms" provided in the 2017 Form 10-K.

OVERVIEW

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 Southern Region (primarily in Texas and Louisiana) and the Northern Region (primarily in North Dakota and Utah). 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".

23




In February 2018, QEP's Board of Directors unanimously approved certain strategic and financial initiatives (Strategic Initiatives), including plans to market its assets in the Williston Basin, the Uinta Basin and Haynesville/Cotton Valley and focus its activities in the Permian Basin. As a part of this process, in February 2018, the Company engaged advisors to assist with the divestitures of its Williston Basin and Uinta Basin assets and has provided data for potential buyers in April 2018. The Company expects to have these asset sales completed during the second half of 2018. As a part of the Strategic Initiatives, QEP has incurred or expects to incur costs associated with contractual termination benefits including severance and accelerated vesting of share-based compensation. Refer to Note 3 – Acquisitions and Divestitures and Note 8 – Restructuring, in Item I of Part I of this Quarterly Report on Form 10-Q for additional information.

Since the beginning of 2014, the Company has made approximately $2.5 billion of acquisitions of properties in the Permian Basin and spent approximately 40% of its capital expenditures (excluding property acquisitions) on its properties in the Permian Basin. In 2018, the Company plans to spend approximately 70% of total planned capital expenditures to develop the Permian Basin.

Outlook

Since the commodity price downturn in late 2014, the Company has focused on operating costs, per well drilling costs and managing its liquidity while continuing its transition from a natural gas weighted company to a pure play Permian Basin company. We believe our balance sheet and sufficient liquidity will allow us to grow oil and condensate production in the Permian Basin and achieve our Strategic Initiatives.

Based on current commodity prices, we expect to be able to fund our planned capital program for the remainder of 2018 with cash flow from operating activities and borrowings under our credit facility. Our total capital expenditures (excluding property acquisitions) for 2018 are expected to be approximately $1,120.0 million, a decrease of approximately 8% from 2017 capital expenditures. We continuously evaluate our level of drilling and completion activity in light of drilling results, commodity prices and changes in our operating and development costs and may make adjustments to our capital investment program based on such evaluations. See "Cash Flow from Investing Activities" for further discussion of our capital expenditures.

Acquisitions and Divestitures

While we believe our extensive inventory of identified drilling locations provides a solid base for growth in production and reserves, the Company continues to evaluate and acquire properties in the Permian Basin to add additional development opportunities and facilitate the drilling of long lateral wells. As part of the Company's plan to focus its operations in the Permian Basin, the Company has engaged advisors to assist in divesting its Williston and Uinta basin assets.

Acquisitions

In the fourth quarter of 2017, QEP acquired additional oil and gas properties in the Permian Basin (the 2017 Permian Basin Acquisition) for an aggregate purchase price of $720.7 million, subject to post-closing purchase price adjustments. 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 sale of QEP's Pinedale assets. 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. During the three months ended March 31, 2018, QEP acquired various oil and gas properties, which primarily included proved and unproved leasehold acreage in the Permian Basin for an aggregate purchase price of $36.2 million, subject to customary purchase price adjustments. Of the $36.2 million, $35.7 million was related to the 2017 Permian Basin Acquisition. If all remaining offers are accepted, QEP now expects that the aggregate purchase price will not exceed $10.5 million, and these transactions are expected to be funded with borrowings under the credit facility and are expected to close in the second quarter of 2018.

During the three months ended March 31, 2017, QEP acquired various oil and gas properties, which primarily included proved and unproved leasehold acreage and additional surface acreage in the Permian Basin, for an aggregate purchase price of $68.2 million. In conjunction with these acquisitions, the Company recorded $5.3 million of goodwill, which was subsequently impaired in 2017.


24



Divestitures

In September 2017, QEP sold its assets in Pinedale (the Pinedale Divestiture), for net cash proceeds (after purchase price adjustments) of $718.2 million, subject to post-closing purchase price adjustments. For the three months ended March 31, 2018, QEP recorded a pre-tax gain on sale of $1.0 million, which was recorded within "Net gain (loss) from asset sales" on the Condensed Consolidated Statements of Operations related to additional post-closing purchase price adjustments. During the year ended December 31, 2017, QEP recorded a pre-tax gain on sale of $180.4 million, which was recorded within "Net gain (loss) from asset sales" on the Consolidated Statements of Operations. In connection with the Pinedale Divestiture, QEP agreed to reimburse the buyer for certain deficiency charges it incurs related to gas processing and NGL transportation and fractionation contracts between the effective date of the sale and December 31, 2019, in an aggregate amount not to exceed $45.0 million. As of March 31, 2018, the liability associated with estimated future payments for this commitment was $27.3 million.

In addition to the $1.0 million gain on sale related to the Pinedale Divestiture, during the three months ended March 31, 2018, QEP received proceeds of $33.3 million and recorded a pre-tax gain on sale of $2.5 million, primarily related to the divestiture of properties in the Williston Basin and in the Other Northern area.

Financial and Operating Results

During the three months ended March 31, 2018, QEP:

Delivered oil and condensate production of 5.0 MMbbls, including a record 2.2 MMbbls in the Permian Basin;
Increased gas production in Haynesville/Cotton Valley to 25.7 Bcf, a 111% increase over 2017 volumes, primarily due to a successful refracturing program and initiation of a drilling program;
Reported realized oil prices of $51.54 per bbl, a 10% increase over 2017, realized gas prices of $2.94 per Mcf, a 4% increase over 2017 and realized NGL prices of $21.99 per bbl, a 3% increase over 2017;
Repurchased and retired 5.6 million shares of the Company's outstanding shares of common stock for $52.8 million;
Generated a net loss of $53.6 million, or $0.22 per diluted share; and
Reported Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of $171.9 million, a 1% increase over 2017.

Factors Affecting Results of Operations

Supply, Demand, Market Risk and their Impact on Oil and Gas Prices
Oil and gas prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials, export capacity, strength of the U.S. dollar and other factors. In recent years, oil and gas prices have been affected by supply growth, particularly in U.S. oil and gas production, driven by advances in drilling and completion technologies, and fluctuations in demand driven by a variety of factors.

Changes in the market prices for oil, gas and NGL directly impact many aspects of QEP's business, including its financial condition, revenues, results of operations, planned drilling and completion activity and related capital expenditures, our proved undeveloped (PUD) reserves conversion rate, liquidity, rate of growth, costs of goods and services required to drill, complete and operate wells, and the carrying value of its oil and gas properties. Historically, field-level prices received for QEP's oil and gas production have been volatile. During the past five years, the posted price for WTI crude oil has ranged from a low of $26.19 per barrel in February 2016 to a high of $110.62 per barrel in September 2013. The Henry Hub spot market price of natural gas has ranged from a low of $1.49 per MMBtu in March 2016 to a high of $8.15 per MMBtu in February 2014. If prices of oil, gas or NGL decline to early 2016 levels or further, our operations, financial condition and level of expenditures for the development of our oil and gas reserves may be materially and adversely affected.

NGL prices have also been affected by increased U.S. hydrocarbon production and insufficient domestic demand and export capacity. Prices of heavier NGL components, typically correlated to oil prices, have declined in concert with weakening oil prices. Concurrently, the lighter NGL components, ethane and propane, have experienced declines as a result of growing North American oversupply. In addition to commodity price movements, QEP's composite NGL prices are affected by ethane recovery or rejection. When ethane is recovered as a discrete NGL component instead of being sold as part of the natural gas stream, the average sales price of a NGL barrel decreases as the ethane price is generally lower than the prices of the remaining NGL components. As permitted in some of its processing agreements, QEP recovers ethane when gas processing economics support the recovery of ethane from the natural gas stream. When gas processing economics do not support ethane recovery, and processing agreements permit it to do so, QEP elects to reject ethane from the NGL stream.

25




Global Geopolitical and Macroeconomic Factors
QEP continues to monitor the global economy, including Europe and China's economic outlook; the Organization of Petroleum Exporting Countries (OPEC) countries oil production and policies regarding production quotas; political unrest and economic issues in South America, Asia, Europe, the Middle East, and Africa; slowing growth in certain emerging market economies; actions taken by the United States Congress and the president of the United States; the U.S. federal budget deficit; changes in regulatory oversight policy; commodity price volatility; tariffs on goods we use in our operations or on the products we sell; the impact of a potential increase in interest rates; volatility in various global currencies; and other factors. A dramatic decline in regional or global economic conditions, a major recession or depression, regional political instability, economic sanctions, war, or other factors beyond the control of QEP could have a significant impact on oil, gas and NGL supply, demand and prices and the Company's ability to continue its planned drilling programs and could materially impact the Company's financial position, results of operations and cash flow from operations. In December 2015, the U.S. lifted a 40-year ban on the export of oil, giving U.S. producers access to a wider market. As a result, the U.S. may in the future become a significant exporter of oil if the necessary infrastructure is built to support oil exports. Disruption to the global oil supply system, political and/or economic instability, fluctuations in currency values, and/or other factors could trigger additional volatility in oil prices.

Due to continued global economic uncertainty and the corresponding volatility of commodity prices, QEP continues to focus on maintaining a sufficient liquidity position to ensure financial flexibility. QEP uses commodity derivatives to reduce the volatility of the prices QEP receives for a portion of its production and to partially protect cash flow and returns on invested capital from a drop in commodity prices. Generally, QEP intends to enter into commodity derivative contracts for approximately 50% to 75% of its forecasted annual production by the end of the first quarter of each fiscal year. At March 31, 2018, QEP forecasted its 2018 annual production to be approximately 50.1 MMboe and had approximately 76% of its forecasted oil production and 78% of its forecasted gas production covered with fixed-price swaps and collars. See Part 1, Item 3 – "Quantitative and Qualitative Disclosures about Market Risk-Commodity Price Risk Management" for further details on QEP's commodity derivatives transactions.

Potential for Future Asset Impairments
The carrying values of the Company's properties are sensitive to declines in oil, gas and NGL prices as well as increases in various development and operating costs and expenses and, therefore, are at risk of impairment. The Company uses a cash flow model to assess its proved properties for impairment. The cash flow model includes numerous assumptions, including estimates of future oil, gas and NGL production, estimates of future prices for production that are based on the price forecast that management uses to make investment decisions, including estimates of basis differentials, future operating costs, transportation expenses, production taxes, and development costs that management believes are consistent with its price forecast, and discount rates. Management also considers a number of other factors, including the forward curve for future oil and gas prices, and developments in regional transportation infrastructure when developing its estimate of future prices for production. All inputs for the cash flow model are evaluated at each date of estimate.

We base our fair value estimates on projected financial information that we believe to be reasonably likely to occur. An assessment of the sensitivity of our capitalized costs to changes in the assumptions in our cash flow calculations is not practicable, given the numerous assumptions (e.g., future oil, gas and NGL prices; production and reserves; pace and timing of development plans; timing of capital expenditures; operating costs; drilling and development costs; and inflation and discount rates) that can materially affect our estimates. Unfavorable adjustments to some of the above listed assumptions would likely be offset by favorable adjustments in other assumptions. For example, the impact of sustained reduced oil, gas and NGL prices on future undiscounted cash flows would likely be offset by lower drilling and development costs and lower operating costs.

If forward oil prices decline from March 31, 2018 levels or we experience negative changes in estimated reserve quantities or we enter into purchase and sale agreements for less than net book value, we have proved and unproved property with a net book value of approximately $3.3 billion at risk for impairment, primarily associated with our Williston Basin and Uinta Basin fields as of March 31, 2018. The actual amount of impairment incurred, if any, for these properties will depend on a variety of factors including, but not limited to, subsequent forward price curve changes, the additional risk-adjusted value of probable and possible reserves associated with the properties, weighted-average cost of capital, operating cost estimates and future capital expenditure estimates.


26



Multi-Well Pad Drilling and Completion
To reduce the costs of well location construction and rig mobilization and demobilization and to obtain other efficiencies, QEP utilizes multi-well pad drilling where practical. For example, in the Permian Basin QEP utilizes "tank-style" development, in which we simultaneously develop multiple subsurface targets by drilling and completing all wells in a given "tank" before any individual well is turned to production. In certain of our producing areas, wells drilled on a pad are not completed and brought into production until all wells on the pad are drilled and the drilling rig is moved from the location. As a result, multi-well pad drilling delays the completion of wells and the commencement of production. In addition, existing wells that offset new wells being completed by QEP or offset operators may need to be temporarily shut-in during the completion process. Such delays and well shut-ins have caused and may continue to cause volatility in QEP's quarterly operating results. In addition, delays in completion of wells may impact planned conversion of PUD reserves to proved developed reserves.

Uncertainties Related to Claims
QEP is currently subject to claims that could adversely impact QEP's liquidity, operating results and/or capital expenditures for a particular reporting period, including, but not limited to those described in Note 10 – Commitments and Contingencies, in Item 1 of Part I of this Quarterly Report on Form 10-Q. Given the uncertainties involved in these matters, QEP is unable to predict the ultimate outcomes.

Critical Accounting Estimates
QEP's significant accounting policies are described in Item 7 of Part II of its 2017 Form 10-K. The Company's Condensed Consolidated Financial Statements are prepared in accordance with GAAP. The preparation of the Company's Condensed Consolidated Financial Statements requires management to make assumptions and estimates that affect the reported results of operations and financial position. QEP's accounting policies on oil and gas reserves, successful efforts accounting for oil and gas operations, capitalized exploratory well costs, impairment of long-lived assets, asset retirement obligations, revenue recognition, litigation and other contingencies, environmental obligations, derivative contracts, pension and other postretirement benefits, share-based compensation, income taxes and purchase price allocations, among others, may involve a high degree of complexity and judgment on the part of management.

Drilling, Completion and Production Activities
The following table presents operated and non-operated wells in the process of being drilled or waiting on completion at March 31, 2018:
 
 
 
Operated
 
Non-operated
 
Drilling
 
Drilling
 
Waiting on completion
 
Drilling
 
Waiting on completion
 
Rigs
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Northern Region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Williston Basin
1

 
1

 
0.5

 
10

 
9.6

 

 

 
8

 
0.1

Uinta Basin

 

 

 

 

 

 

 

 

Other Northern

 

 

 

 

 

 

 

 

Southern Region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Permian Basin(1)
6

 
20

 
19.6

 
38

 
37.1

 

 

 

 

Haynesville/Cotton Valley
1

 
2

 
2.0

 

 

 
3

 
0.2

 
12

 
0.4

Other Southern

 

 

 

 

 

 

 

 

____________________________
(1) 
The gross operated drilling well count in the Permian Basin includes nine wells for which surface casing has been set, but as of March 31, 2018, did not have a rig drilling.

Each gross well completed in more than one producing zone is counted as a single well. To reduce the costs of well location construction and rig mobilization and demobilization and to obtain other efficiencies, QEP utilizes multi-well pad drilling where practical. Delays and well shut-ins resulting from multi-well pad drilling have caused and may continue to cause volatility in QEP's quarterly operating results. In addition, delays in completion of wells could impact planned conversion of PUD reserves to proved developed reserves. QEP had 48 gross operated wells waiting on completion as of March 31, 2018.


27



The following table presents the number of operated and non-operated wells completed and turned to sales (put on production) for the three months ended March 31, 2018:
 
Operated Put on Production
 
Non-operated Put on Production
 
Three Months Ended
 
Three Months Ended
 
March 31, 2018
 
March 31, 2018
 
Gross
 
Net
 
Gross
 
Net
Northern Region
 
 
 
 
 
 
 
Williston Basin

 

 

 

Uinta Basin
2

 
2.0

 

 

Other Northern

 

 

 

Southern Region
 
 
 
 
 
 
 
Permian Basin
31

 
31.0

 

 

Haynesville/Cotton Valley
2

 
2.0

 
6

 
0.6

Other Southern

 

 

 


The following table presents the number of operated wells in the process of being drilled or waiting on completion at March 31, 2018 and operated wells completed and turned to sales (put on production) for the three months ended March 31, 2018:
 
Permian Basin
 
Williston Basin
 
Haynesville/Cotton Valley
 
Uinta Basin
 
As of March 31, 2018
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Well Progress
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Drilling
20

 
19.6

 
1

 
0.5

 
2

 
2.0

 

 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
At total depth - under drilling rig
8

 
7.7

 
5

 
5.0

 

 

 

 

Waiting to be completed
15

 
14.4

 
2

 
2.0

 

 

 

 

Undergoing completion
6

 
6.0

 
2

 
2.0

 

 

 

 

Completed, awaiting production
9

 
9.0

 
1

 
1.0

 

 

 

 

Waiting on completion
38

 
37.1

 
10

 
10.0

 

 

 

 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Put on production
31

 
31.0

 

 

 
2

 
2.0

 
2

 
2.0


RESULTS OF OPERATIONS

Net Income

QEP generated a net loss during the first quarter of 2018 of $53.6 million, or $0.22 per diluted share, compared to a net income of $76.9 million, or $0.32 per diluted share, in the first quarter of 2017. QEP's net loss was primarily due to a $187.3 million increase in unrealized derivative losses, a $26.5 million increase in general and administrative expenses and a 10% decrease in oil equivalent production, primarily due to the Pinedale Divestiture. These decreases were partially offset by a 15% increase in average realized oil equivalent prices, a $59.5 million increase in income tax benefit and a $23.5 million decrease in adjusted transportation and processing costs (refer to Operating Expense discussion for adjusted transportation and processing costs non-GAAP financial measure disclosures) in the first quarter of 2018 compared to the first quarter of 2017.


28



Adjusted EBITDA (Non-GAAP)

Management defines Adjusted EBITDA (a non-GAAP measure) as earnings before interest, income taxes, depreciation, depletion and amortization (EBITDA), adjusted to exclude changes in fair value of derivative contracts, exploration expenses, gains and losses from asset sales, impairment and certain other items. Management uses Adjusted EBITDA to evaluate QEP's financial performance and trends, make operating decisions and allocate resources. Management believes the measure is useful supplemental information for investors because it eliminates the impact of certain nonrecurring, non-cash and/or other items that management does not consider as indicative of QEP's performance from period to period. QEP's Adjusted EBITDA may be determined or calculated differently than similarly titled measures of other companies in our industry, which would reduce the usefulness of this non-GAAP financial measure when comparing our performance to that of other companies.

Below is a reconciliation of net income (loss) (a GAAP measure) to Adjusted EBITDA. This non-GAAP measure should be considered by the reader in addition to, but not instead of, the financial statements prepared in accordance with GAAP.

 
Three Months Ended March 31,
 
2018
 
2017
 
(in millions)
Net income (loss)
$
(53.6
)
 
$
76.9

Interest expense
35.0

 
33.8

Interest and other (income) expense
0.7

 
(0.6
)
Income tax provision (benefit)
(13.9
)
 
45.6

Depreciation, depletion and amortization
196.5

 
191.8

Unrealized (gains) losses on derivative contracts
10.0

 
(177.3
)
Exploration expenses

 
0.4

Net (gain) loss from asset sales
(3.5
)
 

Impairment
0.7

 
0.1

Adjusted EBITDA
$
171.9

 
$
170.7


Adjusted EBITDA increased to $171.9 million in the first quarter of 2018 from $170.7 million in the first quarter of 2017, primarily due to a 15% increase in average realized oil equivalent prices and a 106% increase in oil equivalent production in Permian Basin and Haynesville/Cotton Valley. These changes were partially offset by the loss of Adjusted EBITDA from the Pinedale Divestiture and a $26.5 million increase in general and administrative expense and a $3.3 million increase in lease operating expense in the first quarter of 2018 compared to the first quarter of 2017.

Revenue

The following table presents our revenues disaggregated by revenue source.

 
Three Months Ended
 
March 31,
 
2018
 
2017(1)
 
Change
 
(in millions)
Oil and condensate sales
$
300.7

 
$
221.7

 
$
79.0

Gas sales
102.0

 
134.5

 
(32.5
)
NGL sales
19.8

 
29.0