ITEM 1. FINANCIAL STATEMENTS
QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
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Three Months Ended
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Nine Months Ended
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September 30,
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September 30,
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2020
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2019
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2020
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2019
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REVENUES
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(in millions, except per share amounts)
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|
Oil and condensate, gas and NGL sales
|
$
|
175.8
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|
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$
|
305.6
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|
|
$
|
515.9
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$
|
875.8
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Other revenues
|
1.4
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1.8
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1.6
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7.1
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Purchased oil and gas sales
|
0.6
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|
0.1
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6.7
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1.4
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Total Revenues
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177.8
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307.5
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524.2
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884.3
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OPERATING EXPENSES
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Purchased oil and gas expense
|
0.8
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0.1
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8.2
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1.5
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Lease operating expense
|
35.5
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|
38.3
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|
104.5
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|
135.5
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Transportation and processing costs
|
12.4
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18.0
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38.2
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|
38.8
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Gathering and other expense
|
3.4
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3.1
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8.9
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9.9
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General and administrative
|
20.9
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29.6
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63.1
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124.4
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Production and property taxes
|
14.0
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20.0
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42.3
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|
67.6
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Depreciation, depletion and amortization
|
133.0
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144.2
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|
424.6
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395.5
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Impairment
|
—
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—
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—
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5.0
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Total Operating Expenses
|
220.0
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|
253.3
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|
689.8
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|
778.2
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Net gain (loss) from asset sales, inclusive of restructuring costs
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0.1
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(2.1)
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3.8
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2.5
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OPERATING INCOME (LOSS)
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(42.1)
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52.1
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(161.8)
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108.6
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Realized and unrealized gains (losses) on derivative contracts
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(34.2)
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87.4
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317.0
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(55.8)
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Interest and other income (expense)
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7.7
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0.9
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7.7
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4.6
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Gain (loss) from early extinguishment of debt
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(7.4)
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—
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18.2
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—
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Interest expense
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(28.4)
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(32.8)
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(89.8)
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(100.0)
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INCOME (LOSS) BEFORE INCOME TAXES
|
(104.4)
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|
107.6
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91.3
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(42.6)
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Income tax (provision) benefit
|
55.2
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(26.6)
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42.5
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55.7
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NET INCOME (LOSS)
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$
|
(49.2)
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$
|
81.0
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$
|
133.8
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$
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13.1
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Earnings (loss) per common share
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Basic
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$
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(0.20)
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$
|
0.34
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$
|
0.55
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$
|
0.06
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Diluted
|
$
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(0.20)
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$
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0.34
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$
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0.55
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$
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0.06
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Weighted-average common shares outstanding
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Used in basic calculation
|
242.3
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237.9
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241.2
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237.7
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Used in diluted calculation
|
242.3
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237.9
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241.2
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237.7
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|
Refer to Notes accompanying the Condensed Consolidated Financial Statements.
QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited)
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Three Months Ended
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Nine Months Ended
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September 30,
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September 30,
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2020
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2019
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2020
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|
2019
|
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(in millions)
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Net income (loss)
|
$
|
(49.2)
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|
$
|
81.0
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$
|
133.8
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$
|
13.1
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Other comprehensive income (loss), net of tax:
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Pension and other postretirement plans adjustments:
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Amortization of prior service costs
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—
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0.1
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—
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0.2
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Amortization of actuarial losses(1)
|
0.1
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—
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0.5
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0.1
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Net curtailment(2)
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—
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—
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—
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(0.3)
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Other comprehensive income (loss)
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0.1
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0.1
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0.5
|
|
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—
|
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Comprehensive income (loss)
|
$
|
(49.1)
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|
$
|
81.1
|
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|
$
|
134.3
|
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|
$
|
13.1
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|
____________________________
(1)Presented net of income tax benefit of $0.1 million and $0.2 million for the three and nine months ended September 30, 2020, respectively.
(2)Presented net of income tax benefit of $0.1 million for the nine months ended September 30, 2019.
Refer to Notes accompanying the Condensed Consolidated Financial Statements.
QEP RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
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September 30,
2020
|
|
December 31,
2019
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|
ASSETS
|
(in millions)
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|
Current Assets
|
|
|
|
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Cash and cash equivalents
|
$
|
9.5
|
|
|
$
|
166.3
|
|
|
Accounts receivable, net
|
84.1
|
|
|
108.4
|
|
|
Income tax receivable
|
50.5
|
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|
37.4
|
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|
Fair value of derivative contracts
|
77.5
|
|
|
1.5
|
|
|
Prepaid expenses and other current assets
|
8.5
|
|
|
11.6
|
|
|
Total Current Assets
|
230.1
|
|
|
325.2
|
|
|
Property, Plant and Equipment (successful efforts method for oil and gas properties)
|
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Proved properties
|
9,812.9
|
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|
9,574.9
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Unproved properties
|
544.2
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|
599.1
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|
Gathering and other
|
165.5
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164.2
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Materials and supplies
|
16.9
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|
15.6
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Total Property, Plant and Equipment
|
10,539.5
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|
10,353.8
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Less Accumulated Depreciation, Depletion and Amortization
|
|
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Exploration and production
|
5,603.6
|
|
|
5,250.5
|
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|
Gathering and other
|
68.5
|
|
|
61.0
|
|
|
Total Accumulated Depreciation, Depletion and Amortization
|
5,672.1
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|
|
5,311.5
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|
Net Property, Plant and Equipment
|
4,867.4
|
|
|
5,042.3
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|
Fair value of derivative contracts
|
0.8
|
|
|
0.2
|
|
|
Operating lease right-of-use assets, net
|
52.7
|
|
|
56.8
|
|
|
Other noncurrent assets
|
85.7
|
|
|
53.3
|
|
|
TOTAL ASSETS
|
$
|
5,236.7
|
|
|
$
|
5,477.8
|
|
|
LIABILITIES AND EQUITY
|
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|
Current Liabilities
|
|
|
|
|
Checks outstanding in excess of cash balances
|
$
|
—
|
|
|
$
|
18.3
|
|
|
Accounts payable and accrued expenses
|
164.5
|
|
|
227.2
|
|
|
Production and property taxes
|
10.7
|
|
|
18.9
|
|
|
|
|
|
|
|
Interest payable
|
29.1
|
|
|
31.0
|
|
|
Fair value of derivative contracts
|
4.7
|
|
|
18.7
|
|
|
Current operating lease liabilities
|
22.6
|
|
|
18.0
|
|
|
Asset retirement obligations
|
7.1
|
|
|
6.0
|
|
|
Total Current Liabilities
|
238.7
|
|
|
338.1
|
|
|
Long-term debt
|
1,590.4
|
|
|
2,015.6
|
|
|
Deferred income taxes
|
440.0
|
|
|
274.5
|
|
|
Asset retirement obligations
|
94.8
|
|
|
94.9
|
|
|
Fair value of derivative contracts
|
6.7
|
|
|
0.5
|
|
|
Operating lease liabilities
|
35.4
|
|
|
44.8
|
|
|
Other long-term liabilities
|
32.1
|
|
|
48.8
|
|
|
|
|
|
|
|
Commitments and contingencies (Note 11)
|
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|
EQUITY
|
|
|
|
|
Common stock – par value $0.01 per share; 500.0 million shares authorized; 247.2 million and 242.1 million shares issued, respectively
|
2.5
|
|
|
2.4
|
|
|
Treasury stock – 5.0 million and 4.4 million shares, respectively
|
(56.7)
|
|
|
(55.4)
|
|
|
Additional paid-in capital
|
1,466.2
|
|
|
1,456.5
|
|
|
Retained earnings
|
1,398.6
|
|
|
1,269.6
|
|
|
Accumulated other comprehensive income (loss)
|
(12.0)
|
|
|
(12.5)
|
|
|
Total Common Shareholders' Equity
|
2,798.6
|
|
|
2,660.6
|
|
|
TOTAL LIABILITIES AND EQUITY
|
$
|
5,236.7
|
|
|
$
|
5,477.8
|
|
Refer to Notes accompanying the Condensed Consolidated Financial Statements.
QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(Unaudited)
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Common Stock
|
|
Treasury Stock
|
|
Additional Paid-in Capital
|
|
Retained Earnings
|
|
Accumulated Other Comprehensive Income (Loss)
|
|
Total
|
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Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
|
|
|
|
|
(in millions)
|
|
Balance at June 30, 2020
|
247.2
|
|
|
$
|
2.5
|
|
|
(4.9)
|
|
|
$
|
(56.6)
|
|
|
$
|
1,463.3
|
|
|
$
|
1,447.8
|
|
|
$
|
(12.1)
|
|
|
$
|
2,844.9
|
|
|
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(49.2)
|
|
|
—
|
|
|
(49.2)
|
|
|
Share-based compensation
|
—
|
|
|
—
|
|
|
(0.1)
|
|
|
(0.1)
|
|
|
2.9
|
|
|
—
|
|
|
—
|
|
|
2.8
|
|
|
Change in pension and postretirement liability, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.1
|
|
|
0.1
|
|
|
Balance at September 30, 2020
|
247.2
|
|
|
$
|
2.5
|
|
|
(5.0)
|
|
|
$
|
(56.7)
|
|
|
$
|
1,466.2
|
|
|
$
|
1,398.6
|
|
|
$
|
(12.0)
|
|
|
$
|
2,798.6
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2019
|
242.1
|
|
|
$
|
2.4
|
|
|
(4.4)
|
|
|
$
|
(55.4)
|
|
|
$
|
1,456.5
|
|
|
$
|
1,269.6
|
|
|
$
|
(12.5)
|
|
|
$
|
2,660.6
|
|
|
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
133.8
|
|
|
—
|
|
|
133.8
|
|
|
Cash dividends paid, $0.02 per share
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4.8)
|
|
|
—
|
|
|
(4.8)
|
|
|
Share-based compensation
|
5.1
|
|
|
0.1
|
|
|
(0.6)
|
|
|
(1.3)
|
|
|
9.7
|
|
|
—
|
|
|
—
|
|
|
8.5
|
|
|
Change in pension and postretirement liability, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.5
|
|
|
0.5
|
|
|
Balance at September 30, 2020
|
247.2
|
|
|
$
|
2.5
|
|
|
(5.0)
|
|
|
$
|
(56.7)
|
|
|
$
|
1,466.2
|
|
|
$
|
1,398.6
|
|
|
$
|
(12.0)
|
|
|
$
|
2,798.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at June 30, 2019
|
242.0
|
|
|
$
|
2.4
|
|
|
(4.1)
|
|
|
$
|
(53.6)
|
|
|
$
|
1,446.3
|
|
|
$
|
1,308.6
|
|
|
$
|
(14.4)
|
|
|
$
|
2,689.3
|
|
|
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
81.0
|
|
|
—
|
|
|
81.0
|
|
|
Cash dividends paid, $0.02 per share
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4.8)
|
|
|
—
|
|
|
(4.8)
|
|
|
Share-based compensation
|
0.1
|
|
|
—
|
|
|
(0.2)
|
|
|
(1.2)
|
|
|
5.6
|
|
|
—
|
|
|
—
|
|
|
4.4
|
|
|
Change in pension and postretirement liability, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.1
|
|
|
0.1
|
|
|
Balance at September 30, 2019
|
242.1
|
|
|
$
|
2.4
|
|
|
(4.3)
|
|
|
$
|
(54.8)
|
|
|
$
|
1,451.9
|
|
|
$
|
1,384.8
|
|
|
$
|
(14.3)
|
|
|
$
|
2,770.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2018
|
239.8
|
|
|
$
|
2.4
|
|
|
(3.1)
|
|
|
$
|
(45.6)
|
|
|
$
|
1,431.9
|
|
|
$
|
1,376.5
|
|
|
(14.3)
|
|
|
$
|
2,750.9
|
|
|
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
13.1
|
|
|
—
|
|
|
13.1
|
|
|
Cash dividends paid, $0.02 per share
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4.8)
|
|
|
—
|
|
|
(4.8)
|
|
|
Share-based compensation
|
2.3
|
|
|
—
|
|
|
(1.2)
|
|
|
(9.2)
|
|
|
20.0
|
|
|
—
|
|
|
—
|
|
|
10.8
|
|
|
Change in pension and postretirement liability, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Balance at September 30, 2019
|
242.1
|
|
|
$
|
2.4
|
|
|
(4.3)
|
|
|
$
|
(54.8)
|
|
|
$
|
1,451.9
|
|
|
$
|
1,384.8
|
|
|
$
|
(14.3)
|
|
|
$
|
2,770.0
|
|
Refer to Notes accompanying the Condensed Consolidated Financial Statements.
QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
September 30,
|
|
|
2020
|
|
2019
|
|
OPERATING ACTIVITIES
|
(in millions)
|
|
Net income (loss)
|
$
|
133.8
|
|
|
$
|
13.1
|
|
|
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
|
|
Depreciation, depletion and amortization
|
424.6
|
|
|
395.5
|
|
|
Deferred income taxes (benefit)
|
165.3
|
|
|
(61.2)
|
|
|
Impairment
|
—
|
|
|
5.0
|
|
|
Non-cash share-based compensation
|
9.3
|
|
|
16.2
|
|
|
Non-cash (gain) loss from warehouse inventory
|
0.7
|
|
|
—
|
|
|
Amortization of debt issuance costs and discounts
|
3.7
|
|
|
4.0
|
|
|
Net (gain) loss from asset sales, inclusive of restructuring costs
|
(3.8)
|
|
|
(2.5)
|
|
|
Gain from early extinguishment of debt
|
(18.2)
|
|
|
—
|
|
|
Unrealized (gains) losses on marketable securities
|
(1.1)
|
|
|
(2.8)
|
|
|
Unrealized (gains) losses on derivative contracts
|
(84.4)
|
|
|
29.0
|
|
|
Changes in operating assets and liabilities
|
(75.9)
|
|
|
(54.3)
|
|
|
Net Cash Provided by (Used in) Operating Activities
|
554.0
|
|
|
342.0
|
|
|
INVESTING ACTIVITIES
|
|
|
|
|
Property acquisitions
|
(4.1)
|
|
|
(3.6)
|
|
|
Expenditures for property, plant and equipment, including exploratory well expense
|
(284.5)
|
|
|
(465.2)
|
|
|
Proceeds from disposition of assets
|
13.4
|
|
|
676.5
|
|
|
Net Cash Provided by (Used in) Investing Activities
|
(275.2)
|
|
|
207.7
|
|
|
FINANCING ACTIVITIES
|
|
|
|
|
Checks outstanding in excess of cash balances
|
(18.3)
|
|
|
(13.9)
|
|
|
Long-term debt issuance costs paid
|
(0.5)
|
|
|
—
|
|
|
Repurchases and redemption of senior notes
|
(410.3)
|
|
|
—
|
|
|
Proceeds from credit facility
|
21.1
|
|
|
56.0
|
|
|
Repayments of credit facility
|
(21.1)
|
|
|
(486.0)
|
|
|
Treasury stock repurchases
|
(0.8)
|
|
|
(7.0)
|
|
|
Dividends paid
|
(4.8)
|
|
|
(4.8)
|
|
|
Net Cash Provided by (Used in) Financing Activities
|
(434.7)
|
|
|
(455.7)
|
|
|
Change in cash, cash equivalents and restricted cash(1)
|
(155.9)
|
|
|
94.0
|
|
|
Beginning cash, cash equivalents and restricted cash(1)
|
196.4
|
|
|
28.1
|
|
|
Ending cash, cash equivalents and restricted cash(1)
|
$
|
40.5
|
|
|
$
|
122.1
|
|
|
|
|
|
|
|
Supplemental Disclosures:
|
|
|
|
|
Cash paid for interest, net of capitalized interest
|
$
|
88.2
|
|
|
$
|
94.1
|
|
|
Cash paid (refunds received) for income taxes, net
|
$
|
(164.0)
|
|
|
$
|
5.0
|
|
|
Cash paid for amounts included in the measurement of lease liabilities
|
$
|
19.0
|
|
|
$
|
14.5
|
|
|
Other Non-cash Activities:
|
|
|
|
|
Right-of-use assets obtained in exchange for operating lease obligations
|
$
|
9.3
|
|
|
$
|
11.1
|
|
|
Non-cash Investing Activities:
|
|
|
|
|
Capital expenditure accruals as of September 30, 2020 and 2019
|
$
|
32.3
|
|
|
$
|
55.3
|
|
____________________________
(1)Refer to Cash, Cash Equivalents and Restricted Cash in Note 1 – Basis of Presentation.
Refer to Notes accompanying the Condensed Consolidated Financial Statements.
QEP RESOURCES, INC.
NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1 – Basis of Presentation
Nature of Business
QEP Resources, Inc. (QEP or the Company) is an independent crude oil and natural gas exploration and production company with operations in two regions of the United States: the Southern Region (primarily in Texas) and the Northern Region (primarily in North Dakota). Unless otherwise specified or the context otherwise requires, all references to "QEP" or the "Company" are to QEP Resources, Inc. and its 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
The interim Condensed Consolidated Financial Statements (financial statements) contain the accounts of QEP and its majority-owned or controlled subsidiaries. The 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 intercompany accounts and transactions have been eliminated in consolidation.
The 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 financial statements do not include all of the information and notes required by GAAP for annual consolidated financial statements. These 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, 2019.
The preparation of the 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. Further, these estimates and other factors, including those outside the Company's control, such as the impact of sustained lower commodity prices, could have a significant adverse impact to the Company's financial condition, results of operations and cash flows. The results of operations for the three and nine months ended September 30, 2020 are not necessarily indicative of the results that may be expected for the year ending December 31, 2020.
Certain prior period balances on the Condensed Consolidated Balance Sheets (balance sheets) and Condensed Consolidated Statements of Cash Flows (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 primarily consist of highly liquid investments in securities with original maturities of three months or less made through commercial bank accounts that result in available funds the next business day. Restricted cash are funds that are legally or contractually reserved for a specific purpose and therefore not available for immediate or general business use.
The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the balance sheets to the amounts shown in the statements of cash flows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
2020
|
|
2019
|
|
|
(in millions)
|
|
Cash and cash equivalents
|
$
|
9.5
|
|
|
$
|
92.4
|
|
|
Restricted cash(1)
|
31.0
|
|
|
29.7
|
|
|
Total cash, cash equivalents and restricted cash shown in the statements of cash flows
|
$
|
40.5
|
|
|
$
|
122.1
|
|
_______________________
(1) As of September 30, 2020 and 2019, the restricted cash balance is cash held in an escrow account related to a title dispute between outside parties in the Williston Basin. The restricted cash balance is recorded within "Other noncurrent assets" on the balance sheets.
Income Tax
The tax legislation enacted in December 2017 reduced our federal corporate tax rate from 35% to 21% and eliminated the corporate Alternative Minimum Tax (AMT), allowing the Company to claim AMT refunds for AMT credits carried forward from prior tax years. The Coronavirus Aid, Relief, and Economic Security Act (CARES Act) enacted in March 2020 permitted the Company to carry back its net operating loss (NOL) generated in 2018 and 2019, creating additional AMT credits, and accelerate all of its AMT refunds. The Company received $170.7 million of AMT credit refunds, inclusive of $5.6 million in interest income, during the three months ended September 30, 2020 and $73.9 million of AMT credit refunds in 2019. As of September 30, 2020, the Company expects to receive an additional $81.0 million in AMT credit refunds due to additional NOL carrybacks relating to the 2018 and 2019 tax years. The NOLs that were generated are primarily due to the issuance of final regulations by the U.S Department of Treasury in July 2020 that relate to the deductibility of interest expense. Of the $81.0 million in AMT credit refunds to be received, $50.1 million is included in "Income taxes receivable" and $30.9 million is included in "Other noncurrent assets" on the balance sheets as of September 30, 2020.
QEP’s effective federal and state income tax rate was 52.9% during the third quarter of 2020 compared to a rate of 24.7% during the third quarter of 2019. The increase in the federal and state income tax rate was primarily driven by the impact of discrete items (unusual or infrequent items impacting the tax provision) and permanent differences recognized during the third quarter of 2020 and 2019. During the third quarter 2020 the effective rate was above the statutory rate due to discrete items recognized in the third quarter of 2020, including the remeasurement of deferred taxes due to NOL carrybacks under the CARES Act to a year with a higher federal tax rate, partially offset by a state tax payment. During the third quarter 2019 the rate was driven higher than the statutory rate by the recognition of a discrete item related to share-based compensation and a permanent difference related to the change in the estimated amount of non-deductible executive compensation.
QEP’s effective federal and state income tax rate was negative 46.5% during the nine months ended September 30, 2020 compared to a rate of 130.8% during the nine months ended September 30, 2019. The decrease in the federal and state income tax rate was primarily driven by the impact of discrete items and permanent differences recognized during the nine months ended September 30, 2020 and 2019. During the first three quarters of 2020 the primary discrete item lowering the effective tax rate was the remeasurement of deferred taxes due to NOL carrybacks under the CARES Act to a year with a higher federal tax rate. The primary discrete items recognized during the nine months ended September 30, 2019 related to the remeasurement of deferred taxes associated with the sale of QEP's Haynesville/Cotton Valley assets in January 2019, share-based compensation adjustments and a permanent difference related to the estimated amount of non-deductible executive compensation.
Impairment of Long-Lived Assets
During the nine months ended September 30, 2020, there were no impairment charges. During the nine months ended September 30, 2019, QEP recorded impairment charges of $5.0 million related to an office building lease.
Employee Benefits
QEP provides pension and other postretirement benefits to certain employees through three retiree 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. The Pension Plan was amended in June 2015 and was frozen, such that active participants do not earn any additional accrued benefits on or after January 1, 2016. The SERP is a nonqualified retirement plan that is unfunded and provides postretirement benefits to certain QEP employees. 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 nine months ended September 30, 2020, the Company made contributions of $11.5 million to its retiree benefit plans (including $4.0 million to the Pension Plan and $7.5 million to the SERP) and expects to contribute an additional $2.3 million during the remainder of 2020 (including $2.2 million to the SERP and $0.1 million to the Medical Plan). Contributions to the Pension Plan increase plan assets whereas contributions to the SERP and Medical Plan are used to fund current benefit payments.
The Company recognizes service costs related to SERP and Medical Plan benefits on the Condensed Consolidated Statements of Operations (statements of operations) within "General and administrative" expense. All other expenses related to the Pension Plan, SERP and Medical Plan are recognized on the statements of operations within "Interest and other income (expense)".
QEP also offers a nonqualified, unfunded deferred compensation wrap plan (Wrap Plan) to certain individuals. The Wrap Plan provides participants with certain tax planning benefits as well as supplemental funds for retirement and allows participants to defer the receipt of various types of compensation. Participants are able to select from a variety of investment options, including mutual funds and phantom QEP shares. As of September 30, 2020 and December 31, 2019, the Wrap Plan obligations for participants' future benefits were $25.0 million and $26.8 million, respectively, and are included in "Other long-term liabilities" on the balance sheets. The Company established a trust (Rabbi Trust) to hold the investments associated with the Wrap Plan (other than phantom QEP shares) and to pay Wrap Plan obligations as they arise. As of September 30, 2020 and December 31, 2019, the marketable securities held in the Rabbi Trust were $23.6 million and $23.1 million, respectively, and are included in "Other noncurrent assets" on the balance sheets.
Changes in the fair value of Wrap Plan obligations and marketable securities are recorded as "Deferred compensation mark-to-market adjustments" and "Unrealized gain/loss on marketable securities" within "General and administrative" and "Interest and other income (expense)", respectively, on the statements of operations. "Deferred compensation mark-to-market adjustments" and "Unrealized gain/loss on marketable securities" for the three and nine months ended September 30, 2020 and 2019, respectively, are summarized in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2020
|
|
2019
|
|
|
|
2020
|
|
2019
|
|
|
|
|
(in millions)
|
|
Deferred compensation mark-to-market adjustments
|
$
|
0.5
|
|
|
$
|
(3.1)
|
|
|
|
|
$
|
(2.7)
|
|
|
$
|
0.6
|
|
|
|
|
Unrealized (gain)/loss on marketable securities
|
(1.1)
|
|
|
(0.1)
|
|
|
|
|
(1.1)
|
|
|
(2.8)
|
|
|
|
Refer to Note 6 – Fair Value Measurements for information on the fair value measurement of the marketable securities held in the Rabbi Trust and the Wrap Plan obligations.
Recent Accounting Developments
In June 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-13, Financial Instruments - Credit Losses (Topic 326) - Measurement of credit losses on financial instruments, which requires a company immediately recognize management's current estimated credit losses ("CECL") for all financial instruments that are not accounted for at fair value through net income. Previously, credit losses on financial assets were only required to be recognized when they were incurred. The Company adopted ASU 2016-13 on January 1, 2020. The guidance did not have a significant impact on the financial statements or notes accompanying the financial statements.
In August 2018, the FASB issued ASU No. 2018-13, Fair value measurement (Topic 820) - Disclosure framework - Changes to the disclosure requirements for fair value measurement, which modifies the disclosure requirements on fair value
measurements in Topic 820. The Company adopted ASU 2018-13 on January 1, 2020. The guidance did not have a significant impact on the financial statements or notes accompanying the financial statements.
In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform, which provides temporary optional guidance to companies impacted by the transition away from the London Interbank Offered Rate (LIBOR). The amendment provides certain expedients and exceptions to applying GAAP in order to lessen the potential accounting burden when contracts, hedging relationships, and other transactions that reference LIBOR as a benchmark rate are modified. This amendment is effective upon issuance and expires on December 31, 2022. The Company is currently assessing the impact of the LIBOR transition and this ASU on the Company's financial statements.
Note 2 – Revenue
Revenue Recognition
QEP recognizes revenue from the sale of oil and condensate, gas and NGL in the period that the performance obligations are satisfied. QEP's performance obligations are satisfied when the customer obtains control of product, when QEP has no further obligations to perform related to the sale, when the transaction price has been determined and when collectability is probable. The sale of oil and condensate, gas and NGL are made under contracts with customers, which typically include consideration that is based on pricing tied to local indices and volumes delivered in the current month. Reported revenues include estimates for the two most recent months using published commodity price indices and volumes supplied by field operators. Performance obligations under our contracts with customers are typically satisfied at a point in time through monthly delivery of oil and condensate, gas and/or NGL. Our contracts with customers typically require payment for oil and condensate, gas and NGL sales within 30 days following the calendar month of delivery.
QEP's oil and condensate is typically sold at specific delivery points under contract terms that are common in the industry. QEP's gas and NGL are also sold under contract types that are common in the industry; however, under these contracts, the gas and its components, including NGL, may be sold to a single purchaser or the residue gas and NGL may be sold to separate purchasers. Regardless of the contract type, the terms of these contracts compensate QEP for the value of the residue gas and NGL constituent components at market prices for each product. QEP also purchases and resells oil and gas primarily to fulfill volume commitments when production does not fulfill contractual commitments and to capture additional margin from subsequent sales of third party purchases. QEP recognizes revenue from these resale activities in the period that the performance obligations are satisfied.
The following tables present QEP's revenues that are disaggregated by revenue source and by geographic area. Transportation and processing costs in the following table are not all of the transportation and processing costs that QEP incurs, only the costs that are netted against revenues pursuant to ASC Topic 606, Revenue Recognition.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate sales
|
|
Gas sales
|
|
NGL sales
|
|
Transportation and processing costs included in revenue
|
|
Oil and condensate, gas and NGL sales, as reported
|
|
|
(in millions)
|
|
|
Three Months Ended September 30, 2020
|
|
Northern Region
|
|
|
Williston Basin
|
$
|
58.6
|
|
|
$
|
3.3
|
|
|
$
|
4.1
|
|
|
$
|
(9.4)
|
|
|
$
|
56.6
|
|
|
Other Northern
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
110.7
|
|
|
6.0
|
|
|
9.1
|
|
|
(6.6)
|
|
|
119.2
|
|
|
Other Southern
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total oil and condensate, gas and NGL sales
|
$
|
169.3
|
|
|
$
|
9.3
|
|
|
$
|
13.2
|
|
|
$
|
(16.0)
|
|
|
$
|
175.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2019
|
|
Northern Region
|
|
|
Williston Basin
|
$
|
88.9
|
|
|
$
|
5.5
|
|
|
$
|
2.4
|
|
|
$
|
(7.0)
|
|
|
$
|
89.8
|
|
|
Other Northern
|
—
|
|
|
0.1
|
|
|
0.1
|
|
|
—
|
|
|
0.2
|
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
209.9
|
|
|
3.4
|
|
|
9.4
|
|
|
(7.2)
|
|
|
215.5
|
|
|
Other Southern
|
—
|
|
|
0.1
|
|
|
—
|
|
|
—
|
|
|
0.1
|
|
|
Total oil and condensate, gas and NGL sales
|
$
|
298.8
|
|
|
$
|
9.1
|
|
|
$
|
11.9
|
|
|
$
|
(14.2)
|
|
|
$
|
305.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate sales
|
|
Gas sales
|
|
NGL sales
|
|
Transportation and processing costs included in revenue
|
|
Oil and condensate, gas and NGL sales, as reported
|
|
|
(in millions)
|
|
|
Nine Months Ended September 30, 2020
|
|
Northern Region
|
|
|
Williston Basin
|
$
|
173.2
|
|
|
$
|
10.9
|
|
|
$
|
8.1
|
|
|
$
|
(27.3)
|
|
|
$
|
164.9
|
|
|
Other Northern
|
0.1
|
|
|
1.2
|
|
|
—
|
|
|
—
|
|
|
1.3
|
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
334.5
|
|
|
12.5
|
|
|
21.0
|
|
|
(18.3)
|
|
|
349.7
|
|
|
Other Southern
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total oil and condensate, gas and NGL sales
|
$
|
507.8
|
|
|
$
|
24.6
|
|
|
$
|
29.1
|
|
|
$
|
(45.6)
|
|
|
$
|
515.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2019
|
|
Northern Region
|
|
|
Williston Basin
|
$
|
306.3
|
|
|
$
|
25.5
|
|
|
$
|
15.6
|
|
|
$
|
(26.0)
|
|
|
$
|
321.4
|
|
|
Other Northern
|
0.9
|
|
|
0.4
|
|
|
0.1
|
|
|
—
|
|
|
1.4
|
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
526.7
|
|
|
7.4
|
|
|
27.4
|
|
|
(14.7)
|
|
|
546.8
|
|
|
Other Southern
|
0.1
|
|
|
6.1
|
|
|
—
|
|
|
—
|
|
|
6.2
|
|
|
Total oil and condensate, gas and NGL sales
|
$
|
834.0
|
|
|
$
|
39.4
|
|
|
$
|
43.1
|
|
|
$
|
(40.7)
|
|
|
$
|
875.8
|
|
Note 3 – Acquisitions and Divestitures
Acquisitions
During the nine months ended September 30, 2020 and 2019, QEP acquired various oil and gas properties, which primarily included proved leasehold acreage in the Permian Basin for an aggregate purchase price of $4.1 million and $3.6 million, respectively, subject to post-closing purchase price adjustments.
Divestitures
During the nine months ended September 30, 2020, QEP received proceeds of $13.4 million and recorded a pre-tax gain on sale of $3.8 million, primarily related to the divestiture of certain properties outside its main operating areas. Gains and losses on divestitures of properties are reported on the statements of operations within "Net gain (loss) from asset sales, inclusive of restructuring costs".
Haynesville/Cotton Valley Divestiture
In January 2019, QEP sold its Haynesville/Cotton Valley assets (Haynesville Divestiture), and during the year ended December 31, 2019, reached final settlement on asserted environmental and title defects and received aggregate net cash proceeds of $633.9 million. QEP recorded a total net pre-tax loss on sale, including restructuring costs of $4.0 million. During the three and nine months ended September 30, 2019, QEP recorded $0.3 million and $1.0 million of pre-tax loss on sale, respectively, within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the statements of operations.
During the three and nine months ended September 30, 2019, QEP accounted for revenues and expenses related to Haynesville/Cotton Valley, including the pre-tax loss on sale of $0.3 million and $1.0 million, respectively, as income from continuing operations on the statements of operations because the Haynesville Divestiture did not cause a strategic shift for the Company and therefore did not qualify as discontinued operations. During the three months ended September 30, 2019, QEP recorded net loss before income taxes related to the divested Haynesville/Cotton Valley properties of $0.2 million, which includes the pre-tax loss on sale of $0.3 million.
Other Divestitures
In addition to the Haynesville Divestiture, during the nine months ended September 30, 2019, QEP received net cash proceeds of $42.6 million and recorded a pre-tax gain on sale of $3.5 million, primarily related to the divestiture of properties outside its main operating areas.
These gains and losses were recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the statements of operations.
Note 4 – Earnings Per Share
Basic earnings (loss) per share (EPS) are computed by dividing net income (loss) by the weighted-average number of common shares outstanding during the reporting period. Diluted EPS includes the potential increase in the number of outstanding shares that could result from the exercise of in-the-money stock options. QEP's unvested restricted share awards are included in weighted-average basic common shares outstanding because, once the shares are granted, the restricted share awards are considered issued and outstanding, the historical forfeiture rate is minimal and the restricted share awards are eligible to receive dividends.
Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings (loss) per share pursuant to the two-class method. The Company's unvested restricted share awards contain non-forfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company's unvested restricted share awards do not have a contractual obligation to share in losses of the Company. The Company's unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings (loss) per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings (loss) per common share. For the three months ended September 30, 2020, the Company was in a net loss position, therefore, all potentially dilutive securities were anti-dilutive.
The following is a reconciliation of the components of basic and diluted shares used in the EPS calculation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
September 30,
|
|
September 30,
|
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
|
|
(in millions)
|
|
Weighted-average basic common shares outstanding
|
242.3
|
|
|
237.9
|
|
|
241.2
|
|
|
237.7
|
|
|
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Average diluted common shares outstanding
|
242.3
|
|
|
237.9
|
|
|
241.2
|
|
|
237.7
|
|
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 or estimated lives. The ARO liability is adjusted each period through an accretion calculation using a credit-adjusted risk-free interest rate.
The balance sheet line items of QEP's ARO liability are presented in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Retirement Obligations
|
|
|
September 30,
|
|
December 31,
|
|
|
2020
|
|
2019
|
|
Balance Sheet line item
|
(in millions)
|
|
Current:
|
|
|
|
|
Asset retirement obligations, current liability
|
$
|
7.1
|
|
|
$
|
6.0
|
|
|
Long-term:
|
|
|
|
|
Asset retirement obligations
|
94.8
|
|
|
94.9
|
|
|
Total ARO Liability
|
$
|
101.9
|
|
|
$
|
100.9
|
|
The following is a reconciliation of the changes in the Company's ARO for the period specified below:
|
|
|
|
|
|
|
|
|
Asset Retirement Obligations
|
|
|
(in millions)
|
|
ARO liability at January 1, 2020
|
$
|
100.9
|
|
|
Accretion
|
2.9
|
|
|
Additions
|
1.1
|
|
|
Revisions
|
(0.5)
|
|
|
Liabilities related to assets sold
|
(1.4)
|
|
|
Liabilities settled
|
(1.1)
|
|
|
ARO liability at September 30, 2020
|
$
|
101.9
|
|
Note 6 – Fair Value Measurements
QEP measures and discloses fair values in accordance with the provisions of ASC 820, Fair Value Measurements and Disclosures. This guidance defines fair value in applying GAAP, establishes a framework for measuring fair value and expands disclosures about fair value measurements. ASC 820 also establishes a fair value hierarchy. Level 1 inputs are quoted prices (unadjusted) for identical assets or liabilities in active markets that the Company has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability.
QEP has determined that its commodity derivative instruments are Level 2. The Level 2 fair value of commodity derivative contracts (refer to Note 7 – Derivative Contracts for more information) is based on market prices posted on the respective commodity exchange on the last trading day of the reporting period and industry standard discounted cash flow models. QEP primarily applies the market approach for recurring fair value measurements and maximizes its use of observable inputs and minimizes its use of unobservable inputs. QEP considers bid and ask prices for valuing the majority of its assets and liabilities measured and reported at fair value. In addition to using market data, QEP makes assumptions in valuing its assets and liabilities, including assumptions about risk and the risks inherent in the inputs to the valuation technique. The Company's policy is to recognize transfers between levels at the end of the reporting period.
Certain of the Company's commodity derivative instruments are valued using industry standard models that consider various inputs, including quoted forward prices for commodities, time value, volatility, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable prices at which transactions are executed in the marketplace. The determination of fair value for derivative assets and liabilities also incorporates nonperformance risk for counterparties and for QEP. Derivative contract fair values are reported on a net basis to the extent a legal right of offset with the counterparty exists.
QEP has determined that the marketable securities held in the Rabbi Trust and the Wrap Plan obligations are Level 1. The fair value of the marketable securities in the Rabbi Trust is based on actively traded mutual funds. The Wrap Plan obligations, which represent the underlying liabilities to the participants in the Wrap Plan, are recorded at amounts due to participants, based on the fair value of participants' selected investments, including both actively traded mutual funds and phantom QEP shares. Refer to Note 1 – Basis of Presentation for additional information.
The fair value of financial assets and liabilities at September 30, 2020 and December 31, 2019, is shown in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements
|
|
|
Gross Amounts of Assets and Liabilities
|
|
Netting Adjustments(1)
|
|
Net Amounts Presented on the Balance Sheets
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
|
|
(in millions)
|
|
Financial Assets
|
September 30, 2020
|
|
Fair value of derivative contracts – short-term
|
$
|
—
|
|
|
$
|
89.0
|
|
|
$
|
—
|
|
|
$
|
(11.5)
|
|
|
$
|
77.5
|
|
|
Fair value of derivative contracts – long-term
|
—
|
|
|
0.9
|
|
|
—
|
|
|
(0.1)
|
|
|
0.8
|
|
|
Fair value of Rabbi Trust marketable securities
|
23.6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
23.6
|
|
|
Total financial assets
|
$
|
23.6
|
|
|
$
|
89.9
|
|
|
$
|
—
|
|
|
$
|
(11.6)
|
|
|
$
|
101.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
|
Fair value of derivative contracts – short-term
|
$
|
—
|
|
|
$
|
16.2
|
|
|
$
|
—
|
|
|
$
|
(11.5)
|
|
|
$
|
4.7
|
|
|
Fair value of derivative contracts – long-term
|
—
|
|
|
6.8
|
|
|
—
|
|
|
(0.1)
|
|
|
6.7
|
|
|
Fair value of Wrap Plan obligations
|
25.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
25.0
|
|
|
Total financial liabilities
|
$
|
25.0
|
|
|
$
|
23.0
|
|
|
$
|
—
|
|
|
$
|
(11.6)
|
|
|
$
|
36.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2019
|
|
Financial Assets
|
|
|
|
|
|
|
|
|
|
|
Fair value of derivative contracts – short-term
|
$
|
—
|
|
|
$
|
1.5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1.5
|
|
|
Fair value of derivative contracts – long-term
|
—
|
|
|
0.2
|
|
|
—
|
|
|
—
|
|
|
0.2
|
|
|
Fair value of Rabbi Trust marketable securities
|
23.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
23.1
|
|
|
Total financial assets
|
$
|
23.1
|
|
|
$
|
1.7
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
24.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
|
Fair value of derivative contracts – short-term
|
$
|
—
|
|
|
$
|
18.7
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
18.7
|
|
|
Fair value of derivative contracts – long-term
|
—
|
|
|
0.5
|
|
|
—
|
|
|
—
|
|
|
0.5
|
|
|
Fair value of Wrap Plan obligations
|
26.8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
26.8
|
|
|
Total financial liabilities
|
$
|
26.8
|
|
|
$
|
19.2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
46.0
|
|
_______________________
(1)The Company nets its derivative contract assets and liabilities outstanding with the same counterparty on the balance sheets for the contracts that contain netting provisions. Refer to Note 7 – Derivative Contracts for additional information regarding the Company's derivative contracts.
The following table discloses the fair value and related carrying amount of certain financial instruments not disclosed in other notes to the financial statements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Carrying Amount
|
|
Level 1 Fair Value
|
|
Carrying Amount
|
|
Level 1 Fair Value
|
|
|
September 30, 2020
|
|
December 31, 2019
|
|
Financial Liabilities
|
(in millions)
|
|
Total debt outstanding
|
$
|
1,590.4
|
|
|
$
|
1,128.4
|
|
|
$
|
2,015.6
|
|
|
$
|
2,029.4
|
|
The carrying amounts of cash and cash equivalents, accounts receivable, accounts payable 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. At times when the Company has outstanding debt under the credit facility, the
carrying amount of variable-rate long-term debt approximates fair value because the floating interest rate paid on such debt is set for periods of one month or less.
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 reviews its proved oil and gas properties and operating lease right-of-use assets for potential impairment at least annually and when events and changes in circumstances indicate that the carrying amount of such property may not be recoverable. If impairment is indicated, the fair value of property is measured utilizing the income approach and utilizing inputs that are primarily based upon internally developed cash flow models discounted at an appropriate weighted average cost of capital. In addition, the signing of a purchase and sale agreement could also trigger an impairment of proved properties. For assets subject to a purchase and sale agreement, the terms of the purchase and sale agreement are used as an indicator of fair value. If a range is estimated for the amount of future cash flows, the fair value of property is measured utilizing a probability-weighted approach in which the likelihood of possible outcomes is taken into consideration. Given the unobservable nature of the inputs, fair value calculations associated with long-term operating lease right-of-use assets and proved oil and gas property impairments are considered Level 3 within the fair value hierarchy. During the nine months ended September 30, 2020, the Company did not have an impairment charge. During the nine months ended September 30, 2019, the Company recorded impairment charges of $5.0 million related to an office building lease.
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, and future operating and development costs, which are based on the Company's historic experience with similar properties. In some instances, market comparable information of recent transactions is used to estimate fair value of unproved acreage. Due to the unobservable characteristics of the inputs, the fair value of the acquired properties is considered Level 3 within the fair value hierarchy. Refer to Note 3 – Acquisitions and Divestitures for more information on the fair value of acquired properties.
Note 7 – Derivative Contracts
QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. In the normal course of business, QEP uses commodity price derivative instruments to reduce the impact of potential downward movements in commodity prices on cash flow, returns on capital investment, and other financial results. However, these instruments typically limit gains from favorable price movements. The volume of production subject to commodity derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. QEP may enter into commodity derivative contracts for up to 100% of forecasted production, but generally, QEP enters into commodity derivative contracts for approximately 50% to 75% of its forecasted annual production by the end of the first quarter of each fiscal year. QEP does not enter into commodity derivative contracts for speculative purposes.
QEP uses commodity derivative instruments known as fixed-price swaps, basis 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. QEP also enters into oil price derivative swaps that use Intercontinental Exchange, Inc. (ICE) Brent or regional price indices as the reference price. In addition, QEP enters into oil basis swaps to achieve a fixed-price swap for a portion of its oil sales at prices that reference specific regional index prices. Gas price derivative instruments are typically structured as fixed-price swaps or collars at NYMEX Henry Hub or regional price indices.
QEP does not currently have any commodity derivative instruments 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 September 30, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
Index
|
|
Total Volumes
|
|
Average Swap Price per Unit
|
|
|
|
|
|
(in millions)
|
|
|
|
Oil sales
|
|
|
|
(bbls)
|
|
($/bbl)
|
|
2020
|
|
NYMEX WTI
|
|
3.9
|
|
|
$
|
57.60
|
|
|
2020
|
|
Argus WTI Midland
|
|
0.4
|
|
|
$
|
57.30
|
|
|
2021 (January - June)
|
|
NYMEX WTI
|
|
5.0
|
|
|
$
|
44.78
|
|
|
2021 (July - December)
|
|
NYMEX WTI
|
|
5.0
|
|
|
$
|
42.22
|
|
|
Gas sales
|
|
|
|
(MMbtu)
|
|
($/MMbtu)
|
|
2020
|
|
IF Waha(1)
|
|
3.7
|
|
|
$
|
0.97
|
|
|
2020
|
|
NYMEX HH
|
|
2.8
|
|
|
$
|
2.20
|
|
|
2021
|
|
IF Waha(1)
|
|
18.2
|
|
|
$
|
1.92
|
|
|
2021
|
|
NYMEX HH
|
|
9.1
|
|
|
$
|
2.44
|
|
_______________________
(1)IF Waha Index pricing reported in Platts' Inside FERC's Gas Market Report, reflects the weighted average price of Natural Gas transactions at the Waha Hub in west Texas on the first day of the month.
QEP uses oil basis swaps, combined with NYMEX WTI fixed-price swaps, to achieve fixed price swaps for the location at which it physically sells its production. The following table presents details of QEP's oil basis swaps as of September 30, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
Index
|
|
Basis
|
|
Total Volumes
|
|
Weighted-Average Differential
|
|
|
|
|
|
|
|
(in millions)
|
|
|
|
Oil sales
|
|
|
|
|
|
(bbls)
|
|
($/bbl)
|
|
2020
|
|
NYMEX WTI
|
|
Argus WTI Midland
|
|
1.8
|
|
|
$
|
0.22
|
|
|
2021
|
|
NYMEX WTI
|
|
Argus WTI Midland
|
|
4.4
|
|
|
$
|
0.99
|
|
The following table presents QEP's volumes and average prices for its commodity derivative costless oil collars as of September 30, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
Index
|
|
Total Volumes
|
|
Average Price Floor
|
|
Average Price Ceiling
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
|
|
|
|
(bbls)
|
|
($/bbl)
|
|
($/bbl)
|
|
2021
|
|
NYMEX WTI
|
|
0.4
|
|
|
$
|
40.00
|
|
|
$
|
49.20
|
|
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 statements of operations are summarized in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
Derivative contracts
|
September 30,
|
|
September 30,
|
|
2020
|
|
2019
|
|
2020
|
|
2019(1)
|
|
Realized gains (losses) on commodity derivative contracts
|
(in millions)
|
|
Oil derivative contracts
|
$
|
70.3
|
|
|
$
|
(4.9)
|
|
|
$
|
233.1
|
|
|
$
|
(23.9)
|
|
|
Gas derivative contracts
|
(0.7)
|
|
|
—
|
|
|
(0.5)
|
|
|
(2.9)
|
|
|
Realized gains (losses) on commodity derivative contracts
|
69.6
|
|
|
(4.9)
|
|
|
232.6
|
|
|
(26.8)
|
|
|
Unrealized gains (losses) on commodity derivative contracts
|
|
|
|
|
|
|
|
|
Oil derivative contracts
|
(91.7)
|
|
|
92.3
|
|
|
105.0
|
|
|
(30.5)
|
|
|
Gas derivative contracts
|
(12.1)
|
|
|
—
|
|
|
(20.6)
|
|
|
(0.3)
|
|
|
Unrealized gains (losses) on commodity derivative contracts
|
(103.8)
|
|
|
92.3
|
|
|
84.4
|
|
|
(30.8)
|
|
|
Total realized and unrealized gains (losses) on commodity derivative contracts related to production
|
$
|
(34.2)
|
|
|
$
|
87.4
|
|
|
$
|
317.0
|
|
|
$
|
(57.6)
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives associated with Haynesville Divestiture
|
|
|
|
|
|
|
|
|
Unrealized gains (losses) on commodity derivative contracts
|
|
|
|
|
|
|
|
|
Gas derivative contracts
|
—
|
|
|
—
|
|
|
—
|
|
|
1.8
|
|
|
Unrealized gains (losses) on commodity derivative contracts related to divestitures (1)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1.8
|
|
|
|
|
|
|
|
|
|
|
|
Total realized and unrealized gains (losses) on commodity derivative contracts
|
$
|
(34.2)
|
|
|
$
|
87.4
|
|
|
$
|
317.0
|
|
|
$
|
(55.8)
|
|
_______________________
(1)During the nine months ended September 30, 2019, the unrealized gains (losses) on commodity derivative contracts related to the Haynesville Divestiture were comprised of derivatives included as part of the Haynesville/Cotton Valley purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in January 2019. Refer to Note 3 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Haynesville Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the statements of operations.
Note 8 – Leases
QEP enters into contractual lease arrangements to rent office space, compressors, generators, drilling rigs and other equipment from third-party lessors. QEP records a net operating lease right-of-use (ROU) asset and operating lease liability on the balance sheets for all operating leases with a contract term in excess of 12 months. ROU assets represent QEP’s right to use an underlying asset for the lease term and lease liabilities represent QEP’s obligation to make future lease payments arising from the lease. Operating lease ROU assets and liabilities are recorded at commencement date based on the present value of lease payments over the lease term. Leases with an initial term of 12 months or less are not recorded on the balance sheets. The Company recognizes lease expense for these short-term leases on a straight-line basis over the lease term. With the exception of generators, QEP does not account for lease components separately from the non-lease components. The contractual consideration provided under QEP's leased generators is allocated between lease components, such as equipment, and non-lease components, such as maintenance service fees, based on estimated costs from the vendor. QEP uses its incremental borrowing rate at commencement date of the contract in calculating the present value of future lease payments. The incremental borrowing rate is calculated using a risk-free interest rate adjusted for QEP's risk. The operating lease ROU asset also includes any lease incentives received in the recognition of the present value of future lease payments. Certain of QEP's leases may also include escalation clauses or options to extend or terminate the lease. These options are included in the present value recorded for the leases when it is reasonably certain that QEP will exercise that option. Lease expense for lease payments is recognized on a straight-line basis over the lease term.
QEP determines if an arrangement is a lease at inception of the contract and records the resulting operating lease asset on the balance sheets as “Operating lease right-of-use assets, net” with offsetting liabilities recorded as “Current operating lease
liabilities” and “Operating lease liabilities.” QEP recognizes a lease in the financial statements when the arrangement either explicitly or implicitly involves property, plant, or equipment (PP&E), the contract terms are dependent on the use of the PP&E, and QEP has the ability or right to operate the PP&E or to direct others to operate the PP&E and receive the majority of the economic benefits of the assets. As of September 30, 2020, QEP does not have any financing leases.
Lease costs represent the straight-line lease expense of ROU assets and short-term leases. The components of lease cost are classified as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
September 30,
|
|
September 30,
|
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
|
Lease Cost included in the Condensed Consolidated Balance Sheets
|
(in millions)
|
|
Property, Plant and Equipment acquisitions(1)
|
$
|
2.1
|
|
|
$
|
2.5
|
|
|
$
|
9.2
|
|
|
$
|
11.3
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
September 30,
|
|
September 30,
|
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
|
Lease Cost included in the Condensed Consolidated Statement of Operations
|
(in millions)
|
|
Lease operating expense
|
$
|
3.4
|
|
|
$
|
2.9
|
|
|
$
|
8.8
|
|
|
$
|
9.0
|
|
|
Gathering and other expense
|
1.9
|
|
|
2.0
|
|
|
5.7
|
|
|
5.8
|
|
|
General and administrative
|
1.5
|
|
|
1.3
|
|
|
4.5
|
|
|
4.5
|
|
|
|
|
|
|
|
|
|
|
|
Total lease cost
|
$
|
8.9
|
|
|
$
|
8.7
|
|
|
$
|
28.2
|
|
|
$
|
30.6
|
|
____________________________
(1)Represents short-term lease capital expenditures related to drilling rigs for the three and nine months ended September 30, 2020 and 2019. These costs are capitalized as a part of "Proved properties" on the balance sheets.
Lease term and discount rate related to the Company's leases are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2020
|
|
September 30, 2019
|
|
Weighted-average remaining lease term (years)
|
|
3.5
|
|
3.4
|
|
Weighted-average discount rate
|
|
7.2
|
%
|
|
7.7
|
%
|
As of September 30, 2020 and December 31, 2019, the maturity analysis for long-term operating leases under the scope of ASC 842 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2020
|
|
December 31, 2019
|
|
Year
|
(in millions)
|
|
2020
|
$
|
6.8
|
|
|
$
|
22.3
|
|
|
2021
|
25.0
|
|
|
20.4
|
|
|
2022
|
17.0
|
|
|
15.9
|
|
|
2023
|
11.4
|
|
|
10.6
|
|
|
2024
|
2.3
|
|
|
1.4
|
|
|
After 2024
|
2.6
|
|
|
2.4
|
|
|
Less: Interest(1)
|
(7.1)
|
|
|
(10.2)
|
|
|
Present value of lease liabilities(2)
|
$
|
58.0
|
|
|
$
|
62.8
|
|
____________________________
(1)Calculated using the estimated interest rate for each lease.
(2)As of September 30, 2020 and December 31, 2019, of the total present value of lease liabilities, $22.6 million and $18.0 million, was recorded in "Current operating lease liabilities", respectively, and $35.4 million and $44.8 million was recorded in "Operating lease liabilities", respectively, on the balance sheets.
Note 9 – Restructuring
In February 2018, QEP's Board of Directors (Board) approved certain strategic and financial initiatives. In February 2019, QEP's Board commenced a comprehensive review of strategic alternatives to maximize shareholder value. In connection with these activities, QEP has incurred various restructuring costs associated with contractual termination benefits including severance, accelerated vesting of share-based compensation and other expenses. The termination benefits are accounted for under ASC 712, Compensation – Nonretirement Postemployment Benefits and ASC 718, Compensation – Stock Compensation.
There were no restructuring costs recognized during the three months ended September 30, 2020. Restructuring costs recognized are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total recognized
|
|
Recognized in "General and administrative"
|
|
Recognized in "Net (gain) loss from asset sales, inclusive of restructuring costs"
|
|
Recognized in "Interest and other (income) expense"
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2020
|
|
|
|
|
|
|
|
|
|
|
Termination benefits
|
$
|
1.0
|
|
|
$
|
1.0
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Accelerated share-based compensation
|
0.5
|
|
|
0.5
|
|
|
—
|
|
|
—
|
|
|
Retention expense (including share-based compensation)
|
0.4
|
|
|
0.4
|
|
|
—
|
|
|
—
|
|
|
Total restructuring costs
|
$
|
1.9
|
|
|
$
|
1.9
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2019
|
|
Termination benefits
|
$
|
4.3
|
|
|
$
|
4.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Accelerated share-based compensation
|
1.6
|
|
|
1.6
|
|
|
—
|
|
|
—
|
|
|
Retention expense (including share-based compensation)
|
4.5
|
|
|
4.5
|
|
|
—
|
|
|
—
|
|
|
Pension and Medical Plan curtailment
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total restructuring costs
|
$
|
10.4
|
|
|
$
|
10.4
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2019
|
|
Termination benefits
|
$
|
11.0
|
|
|
$
|
10.9
|
|
|
$
|
0.1
|
|
|
$
|
—
|
|
|
Office lease termination costs
|
0.6
|
|
|
0.6
|
|
|
—
|
|
|
—
|
|
|
Accelerated share-based compensation
|
11.3
|
|
|
9.8
|
|
|
1.5
|
|
|
—
|
|
|
Retention expense (including share-based compensation)
|
15.4
|
|
|
15.4
|
|
|
—
|
|
|
—
|
|
|
Pension and Medical Plan curtailment
|
(0.4)
|
|
|
—
|
|
|
(0.2)
|
|
|
(0.2)
|
|
|
Total restructuring costs
|
$
|
37.9
|
|
|
$
|
36.7
|
|
|
$
|
1.4
|
|
|
$
|
(0.2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs recognized from inception through September 30, 2020(1)
|
|
Total remaining costs expected to be incurred
|
|
|
(in millions)
|
|
Termination benefits
|
$
|
45.6
|
|
|
$
|
—
|
|
|
Office lease termination costs
|
1.6
|
|
|
—
|
|
|
Accelerated share-based compensation
|
24.1
|
|
|
—
|
|
|
Retention expense (including share-based compensation)
|
38.7
|
|
|
—
|
|
|
Pension and Medical Plan curtailment
|
1.3
|
|
|
—
|
|
|
Total restructuring costs
|
$
|
111.3
|
|
|
$
|
—
|
|
____________________________
(1)Represents costs incurred since February 2018 when QEP's Board approved certain strategic and financial initiatives.
The following table is a reconciliation of QEP's restructuring liability, which is included within "Accounts payable and accrued expenses" on the balance sheets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restructuring liability
|
|
|
Termination benefits
|
|
Office lease termination costs
|
|
Accelerated share-based compensation
|
|
Retention expense
|
|
Pension curtailment
|
|
Total
|
|
|
(in millions)
|
|
Balance at December 31, 2019
|
$
|
1.2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
6.5
|
|
|
$
|
—
|
|
|
$
|
7.7
|
|
|
Costs incurred and charged to expense
|
1.0
|
|
|
—
|
|
|
0.5
|
|
|
0.4
|
|
|
—
|
|
|
1.9
|
|
|
Costs paid or otherwise settled
|
(2.2)
|
|
|
—
|
|
|
(0.5)
|
|
|
(6.9)
|
|
|
—
|
|
|
(9.6)
|
|
|
Balance at September 30, 2020
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Note 10 – Debt
As of the indicated dates, QEP's long-term debt outstanding consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
2020
|
|
December 31,
2019
|
|
|
(in millions)
|
|
Revolving Credit Facility due 2022
|
$
|
—
|
|
|
$
|
—
|
|
|
6.875% Senior Notes due 2021
|
—
|
|
|
382.4
|
|
|
5.375% Senior Notes due 2022
|
465.1
|
|
|
500.0
|
|
|
5.25% Senior Notes due 2023
|
636.8
|
|
|
650.0
|
|
|
5.625% Senior Notes due 2026
|
500.0
|
|
|
500.0
|
|
|
Less: unamortized discount and unamortized debt issuance costs
|
(11.5)
|
|
|
(16.8)
|
|
|
Total long-term debt outstanding
|
$
|
1,590.4
|
|
|
$
|
2,015.6
|
|
Of the total debt outstanding on September 30, 2020, the 5.375% Senior Notes due October 1, 2022 and the 5.25% Senior Notes due May 1, 2023, will mature within the next five years. In addition, the revolving credit facility matures on September 1, 2022.
Credit Facility
In June 2020, QEP entered into the Eighth Amendment to its credit agreement, which, among other things, reduced the aggregate principal amount of commitments to $850.0 million, requires the Company’s material subsidiaries to guarantee the obligations under the credit agreement as well as certain swap obligations and modified the leverage ratio and present value financial covenants, such that they only pertain to net priority guaranteed debt (primarily consisting of borrowings under the credit facility and letters of credit). The amended credit agreement also provides the ability to use up to $500.0 million of loan proceeds to repurchase outstanding senior notes, provides the ability to issue subsidiary guarantees of up to $500.0 million of unsecured debt, with such guarantees being subordinated to the obligations under the credit agreement, and may limit the Company’s ability to make certain restricted payments, including dividends. The amended credit agreement, which matures on September 1, 2022, provides for borrowings at short-term interest rates and contains customary covenants and restrictions and 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 minimum liquidity amount of at least $100.0 million (ii) a net priority guaranteed leverage ratio under which net priority guaranteed debt may not exceed 2.50 times consolidated EBITDAX (as defined in the credit agreement), and (iii) a present value coverage ratio under which the present value of the Company's proved reserves must exceed net priority guaranteed debt by at least 1.50 times. At September 30, 2020 and December 31, 2019, QEP was in compliance with the covenants under its credit agreement. During the nine months ended September 30, 2020, the Company recorded a $1.5 million loss associated with the write-off of non-cash deferred financing costs as part of amending the credit facility and recorded the loss within "Gain (loss) from early extinguishment of debt" on the statements of operations.
During the nine months ended September 30, 2020, QEP's weighted average interest rate on borrowings under its credit facility was 2.60%. As of September 30, 2020, QEP had no borrowings outstanding and $11.9 million in letters of credit outstanding under the credit facility. As of December 31, 2019, QEP had no borrowings outstanding and $2.9 million in letters of credit outstanding under the credit facility.
Senior Notes
At September 30, 2020, the Company had $1,601.9 million in principal amount of senior notes outstanding with maturities ranging from October 1, 2022 to March 1, 2026, and coupons ranging from 5.25% to 5.625%. The senior notes pay interest semi-annually, are unsecured senior obligations and rank equally with all of QEP's other existing and future senior unsecured indebtedness. QEP may redeem some or all of its senior notes at any time before their maturity at a redemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption. The indentures governing QEP's senior notes contain customary events of default and covenants that may limit QEP's ability to, among other things, place liens on its property or assets. During the nine months ended September 30, 2020, QEP repurchased, at a discount, $107.1 million in principal amount of its 6.875% Senior Notes due March 1, 2021, $34.9 million in principal amount of its 5.375% Senior Notes due October 1, 2022 and $13.2 million in principal amount of its 5.25% Senior Notes due May 1, 2023, resulting in a $27.1 million gain from early extinguishment of debt. In addition, during the third quarter of 2020, QEP redeemed the remaining $275.3 million in principal amount of its 6.875% Senior Notes due March 1, 2021, resulting in a loss on early extinguishment of debt of $7.4 million. In total, during the nine months ended September 30, 2020, the Company recorded a $19.7 million net gain in "Gain (loss) from early extinguishment of debt" on the statements of operations related to the repurchase and redemption of senior notes.
Note 11 – Commitments and Contingencies
The Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. In each reporting period, the Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its 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 and the ongoing discovery and/or development of information important to the matter.
Mandan, Hidatsa and Arikara Nation ("MHA Nation") Title Dispute – In June 2018, the MHA Nation notified QEP of its position that QEP has no valid lease covering certain minerals underlying the Missouri and Little Missouri Riverbeds on the Fort Berthold Reservation in North Dakota. The MHA Nation also passed a resolution purporting to rescind those portions of QEP's IMDA lease covering the disputed minerals underlying the Missouri River. In May 2020, the Office of the Solicitor of the United States Department of the Interior issued an opinion finding that the State of North Dakota, not the MHA Nation, is the legal owner of the minerals underlying the Missouri River. QEP holds leases granted by the State of North Dakota covering the majority of QEP’s producing tracts underlying the Missouri River. The MHA Nation has filed actions in two federal courts seeking to overturn the May 2020 opinion.
Overriding Royalty Interest Litigation – In July 2019, owners of small overriding royalty interests in certain wells in the South Antelope oil and gas field in North Dakota filed suit against QEP, alleging QEP has improperly taken deductions for post-production expenses.
In many cases, the Company is unable to make an estimate of the range of reasonably possible loss related to its contingencies. To the extent that the Company can reasonably estimate losses for contingencies where the risk of material loss (in excess of accruals, if any) is reasonably possible, the Company estimates such losses to be in a range of zero to approximately $10.0 million, in the aggregate.
Note 12 – Share-Based and Long-Term Incentive Compensation
In 2018, QEP's Board and QEP's shareholders approved the QEP Resources, Inc. 2018 Long-Term Incentive Plan (LTIP), which replaced the 2010 Long-Term Stock Incentive Plan (LTSIP) and provides for the issuance of up to 10.0 million shares such that the Board may grant long-term incentive compensation. QEP issues restricted share awards, restricted cash awards and restricted share units under its LTSIP or LTIP and awards performance share units under its Cash Incentive Plan (CIP) to certain officers, employees and non-employee directors. Grants issued prior to May 15, 2018 were under the LTSIP and grants issued on or after May 15, 2018 are under the LTIP. QEP recognizes the expense over the vesting periods for stock options, restricted share awards, restricted cash awards, restricted share units and performance share units. There were 3.6 million shares available for future grants under the LTIP at September 30, 2020.
Share-based compensation expense is generally recognized within "General and administrative" expense on the statements of operations and is summarized in the table below.
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
September 30,
|
|
September 30,
|
|
|
2020(1)
|
|
2019(2)
|
|
2020(1)
|
|
2019(2)
|
|
|
(in millions)
|
|
Non-cash share-based compensation
|
|
|
|
|
|
|
|
|
Stock options
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.3
|
|
|
Restricted share awards
|
2.9
|
|
|
5.0
|
|
|
9.3
|
|
|
15.9
|
|
|
Total non-cash share-based compensation
|
2.9
|
|
|
5.0
|
|
|
9.3
|
|
|
16.2
|
|
|
Cash share-based compensation
|
|
|
|
|
|
|
|
|
Restricted cash awards
|
0.5
|
|
|
—
|
|
|
1.2
|
|
|
—
|
|
|
Performance share units
|
0.5
|
|
|
(0.9)
|
|
|
0.5
|
|
|
4.6
|
|
|
Restricted share units
|
—
|
|
|
—
|
|
|
—
|
|
|
0.2
|
|
|
Total cash share-based compensation
|
1.0
|
|
|
(0.9)
|
|
|
1.7
|
|
|
4.8
|
|
|
Total share-based compensation expense
|
$
|
3.9
|
|
|
$
|
4.1
|
|
|
$
|
11.0
|
|
|
$
|
21.0
|
|
________________________
(1)During the three months ended September 30, 2020, the Company did not incur any costs related to accelerated vesting. During the nine months ended September 30, 2020 the Company incurred $0.5 million of share-based compensation expense related to the acceleration of vesting that occurred as part of the restructuring program and is included in the table above. Refer to Note 9 – Restructuring for additional information.
(2)During the three and nine months ended September 30, 2019, the Company recorded $1.6 million and $11.3 million, respectively, of share-based compensation expense related to the acceleration of vesting that occurred as part of the restructuring program. Of the $11.3 million recorded during the nine months ended September 30, 2019, $1.5 million was recorded in "Net gain (loss) from asset sales, inclusive of restructuring costs" on the statement of operations and the remaining $9.8 million is included in the table above. Refer to Note 9 – Restructuring for additional information.
Stock Options
During the nine months ended September 30, 2020, QEP did not issue stock options to its employees. In periods when QEP granted stock options, the Company historically used the Black-Scholes-Merton mathematical model to estimate the fair value of stock option awards at the date of grant. Fair value calculations rely upon subjective assumptions used in the mathematical model and may not be representative of future results. The Black-Scholes-Merton model is intended for calculating the value of options not traded on an exchange. The Company utilized the "simplified" method to estimate the expected term of the stock options granted as there was limited historical exercise data available in estimating the expected term of the stock options. QEP used a historical volatility method to estimate the fair value of stock option awards, and the risk-free interest rate was based on the yield on U.S. Treasury strips with maturities similar to those of the expected term of the stock options. The stock options typically vest in equal installments over three years from the grant date and are exercisable immediately upon vesting through the seventh anniversary of the grant date. To fulfill options exercised, QEP either reissues treasury stock or issues new shares. The Company recognizes forfeitures of stock options as they occur.
Stock option transactions under the terms of the LTSIP are summarized below:
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding
|
|
Weighted-Average Exercise Price
|
|
Weighted-Average Remaining Contractual Term
|
|
Aggregate Intrinsic Value
|
|
|
|
|
(per share)
|
|
(in years)
|
|
(in millions)
|
|
Outstanding at December 31, 2019
|
1,802,387
|
|
|
$
|
20.87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forfeited
|
(311,203)
|
|
|
30.08
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at September 30, 2020
|
1,491,184
|
|
|
$
|
18.94
|
|
|
2.02
|
|
$
|
—
|
|
|
Options Exercisable at September 30, 2020
|
1,491,184
|
|
|
$
|
18.94
|
|
|
2.02
|
|
$
|
—
|
|
|
Unvested Options at September 30, 2020
|
—
|
|
|
$
|
—
|
|
|
0
|
|
$
|
—
|
|
During the nine months ended September 30, 2020 there were no exercises of stock options. The Company recognized $1.1 million and $1.0 million of income tax expense during the nine months ended September 30, 2020 and 2019, respectively, for the cancellation of options during the period. As of September 30, 2020, there was no unrecognized compensation expense related to stock options granted under the LTSIP. Refer to Note 9 – Restructuring for additional information.
Restricted Share Awards
Restricted share award grants typically vest in equal installments over three years from the grant date. The grant date fair value is determined based on the closing bid price of the Company's common stock on the grant date. The Company recognizes restricted share forfeitures as they occur. The total fair value of restricted share awards that vested during the nine months ended September 30, 2020 and 2019 was $2.5 million and $29.6 million, respectively. The Company recognized $2.3 million and $2.1 million of income tax expense during the nine months ended September 30, 2020 and 2019, respectively, for shares that were either vested or forfeited during the period. The weighted-average grant date fair value of restricted share awards was $2.10 per share and $7.79 per share for the nine months ended September 30, 2020 and 2019, respectively. As of September 30, 2020, $10.1 million of unrecognized compensation expense related to restricted share awards granted under the LTSIP and LTIP is expected to be recognized over a weighted-average vesting period of 2.12 years.
Transactions involving restricted share awards under the terms of the LTSIP and LTIP are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted Share Awards Outstanding
|
|
Weighted-Average Grant Date Fair Value
|
|
|
|
|
(per share)
|
|
Unvested balance at December 31, 2019
|
2,845,033
|
|
|
$
|
8.67
|
|
|
Granted
|
5,080,589
|
|
|
2.10
|
|
|
Vested
|
(1,383,618)
|
|
|
9.26
|
|
|
Forfeited
|
(97,718)
|
|
|
4.91
|
|
|
Unvested balance at September 30, 2020
|
6,444,286
|
|
|
$
|
3.42
|
|
Restricted Cash Awards
Beginning in March 2020, QEP issued restricted cash awards under its LTIP to certain employees. Restricted cash award grants vest in equal installments over three years from the grant date. The Company recognizes restricted cash forfeitures as they occur. There were no restricted cash awards granted or outstanding during the nine months ended September 30, 2019. As of September 30, 2020, $2.1 million of unrecognized compensation expense related to restricted cash awards granted under the LTIP is expected to be recognized over a weighted-average vesting period of 2.50 years.
Transactions involving restricted cash awards under the terms of the LTIP are summarized below:
|
|
|
|
|
|
|
|
|
|
|
Restricted Cash Awards Outstanding
|
|
|
|
|
|
|
|
|
Unvested balance at December 31, 2019
|
$
|
—
|
|
|
|
|
Granted
|
3,249,925
|
|
|
|
|
Vested
|
(7,000)
|
|
|
|
|
Forfeited
|
(64,750)
|
|
|
|
|
Unvested balance at September 30, 2020
|
$
|
3,178,175
|
|
|
|
Performance Share Units
The payouts associated with performance share units under the CIP are dependent upon the Company's total shareholder return compared to a group of its peers over three years. The awards are denominated in share units and have historically been paid in cash. The Company has the option to settle earned awards in cash or shares of common stock under the Company's LTIP; however, as of September 30, 2020, the Company expects to settle all awards under the CIP in cash. These awards are classified as liabilities and are included within "Other long-term liabilities" on the balance sheets. Because 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 Company paid $0.3 million and $12.1 million, respectively, for vested performance share units during the nine months ended September 30, 2020 and 2019. The weighted-average grant date fair value of the performance share units granted during the nine months ended September 30, 2020 and 2019 was $2.17 and $7.93 per share, respectively. As of September 30, 2020, $2.1 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of performance shares granted, is expected to be recognized over a weighted-average vesting period of 2.11 years. Refer to Note 9 – Restructuring for additional information.
Transactions involving performance share units under the terms of the CIP are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance Share Units Outstanding
|
|
Weighted-Average Grant Date Fair Value
|
|
|
|
|
(per share)
|
|
Unvested balance at December 31, 2019
|
625,922
|
|
|
$
|
9.04
|
|
|
Granted
|
1,926,026
|
|
|
2.17
|
|
|
Vested and paid
|
(96,734)
|
|
|
13.06
|
|
|
Unvested balance at September 30, 2020
|
2,455,214
|
|
|
$
|
3.56
|
|
Restricted Share Units
Employees may elect to defer their grants of restricted share awards and these deferred awards are designated as restricted share units. Restricted share units vest over three years and are deferred into the Company's Wrap Plan at the time of grant. These awards are ultimately paid in cash when distributed from the deferred compensation plan. They are classified as liabilities in "Other long-term liabilities" on the 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 $2.08 and $7.90 per share for the nine months ended September 30, 2020 and 2019, respectively. As of September 30, 2020, there was less than $0.1 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of restricted share units granted. Refer to Note 9 – Restructuring for additional information.
Transactions involving restricted share units under the terms of the LTSIP and LTIP are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted Share Units Outstanding
|
|
Weighted-Average Grant Date Fair Value
|
|
|
|
|
(per share)
|
|
Unvested balance at December 31, 2019
|
34,393
|
|
|
$
|
8.16
|
|
|
Granted
|
76,083
|
|
|
2.08
|
|
|
Vested and paid
|
(26,770)
|
|
|
8.20
|
|
|
Unvested balance at September 30, 2020
|
83,706
|
|
|
$
|
2.62
|
|
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 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, 2019 (2019 Form 10-K) and analyzes the changes in the results of operations between the three and nine months ended September 30, 2020 and 2019. 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 2019 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 the Northern Region (primarily in North Dakota). Unless otherwise specified or the context otherwise requires, all references to "QEP" or the "Company" are to QEP Resources, Inc. and its 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".
As a result of the reduction of the Company's operational footprint in 2019 following the Board's comprehensive review of strategic alternatives and determination to move forward as an independent company, QEP reassessed its organizational needs and significantly reduced its general and administrative expense to ensure its cost structure is competitive with industry peers.
As a part of the strategic initiatives and reduction in general and administrative expense, QEP has incurred costs associated with contractual termination benefits, including severance, accelerated vesting of share-based compensation and other expenses. Refer to Note 3 – Acquisitions and Divestitures and Note 9 – Restructuring in Part 1, Item I of this Quarterly Report on Form 10-Q for more information.
The Company continues to focus on reducing its operating costs, per well drilling costs, general and administrative costs and managing its liquidity. We believe our plan to generate Free Cash Flow (FCF) (a non-GAAP financial measure defined and reconciled below) on an annual basis will allow us to further strengthen our balance sheet and continue returning capital to shareholders.
Financial and Operating Highlights
During the three months ended September 30, 2020, QEP:
•Generated a net loss of $49.2 million, or $0.20 per diluted share;
•Reported Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of $160.4 million;
•Reduced general and administrative expenses by 29% compared to the third quarter of 2019;
•Received $170.7 million in Alternative Minimum Tax (AMT) credit refunds due to changes enacted by the Coronavirus Aid, Relief, and Economic Security Act (CARES Act), inclusive of $5.6 million in interest income;
•Redeemed the remaining $275.3 million in principal amount of the 2021 Senior Notes; and
•Recorded an additional income tax receivable of $81.0 million for AMT credit refunds related to net operating loss (NOL) carrybacks due to changes enacted by the CARES Act.
During the nine months ended September 30, 2020, QEP:
•Generated net income of $133.8 million, or $0.55 per diluted share;
•Reported Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of $491.6 million;
•Reported cash provided by operating activities of $554.0 million;
•Reported Free Cash Flow (a non-GAAP measure defined and reconciled below) of $162.0 million;
•Lowered lease operating expense by $31.0 million, or 23%, compared to the first three quarters of 2019;
•Reduced general and administrative expenses by 49% compared to the first three quarters of 2019; and
•Reduced principal amount of outstanding debt by $430.5 million.
Outlook
The novel coronavirus disease (COVID-19) has created unprecedented challenges for our industry, customers and employees. Throughout the global pandemic, the Company has continued to take actions suggested by the Centers for Disease Control and Prevention as well as state and local governments in the areas in which the Company operates to protect the core of its business and to ensure the health and safety of its employees, business partners and communities. Starting in March 2020, the Company instituted various measures, including remote working and business travel restrictions, and we remain engaged with our business and community partners on how we can assist them during this time. The Company continues to evaluate safeguards and has implemented procedures and policies to help protect the health and safety of the portion of the workforce whose jobs
cannot be completed remotely, including those who run our field operations. We continue to monitor the guidelines and recommendations provided by the relevant authorities, and we will continue to ensure we are implementing the suggested protocols to help reduce the spread of the virus.
As a result of lower demand caused by the COVID-19 pandemic and resulting oversupply of crude oil, the future prices of crude oil continue to be at low levels. In light of market conditions, during the first three quarters of 2020 the Company took significant steps to proactively manage its cash flow and preserve liquidity by suspending completion operations in the Permian Basin until the fourth quarter of 2020. In the Williston Basin, we have completed all operated development activity for the year. While these decisions will result in lower 2020 oil production, the Company believes that it will be able to maintain positive cash flow and protect its balance sheet, with the ultimate goal of protecting shareholder returns over the long term. Although the Company has already significantly reduced activity, we are prepared to reduce activity further for an extended period if necessary. The Company has utilized the slowdown to improve on its peer leading operations and will continue to reduce expenses and per well costs to the lowest and most efficient cost structure possible.
Due to the Company’s derivative positions, temporary suspension of completion operations and the continued initiative in reducing drilling and completion costs, the Company expects to generate FCF in 2020 despite the current market conditions. In addition to generating FCF, changes enacted under the CARES Act have created significant income tax refunds for the Company. During the nine months ended September 30, 2020, the Company received $170.7 million in AMT credit refunds, inclusive of $5.6 million in interest income, and at September 30, 2020, the Company recorded an additional $81.0 million income tax receivable for AMT credit refunds, of which, $50.1 million is expected to be received in the next 12 months. The Company expects that the generation of FCF, cash on hand, the AMT credit refund and, as needed, borrowings made under its revolving credit facility, will be sufficient to meet its liquidity needs for the next 12 months.
The Company believes that the overall reduction of global spending on new development projects, especially in the U.S., will cause a reduction in the global oil supply, and that the eventual recovery from the COVID-19 pandemic will cause demand to be more in line with previously anticipated levels and, consequently, cause oil prices to recover. As a result of the actions taken, and continuing to be taken, and the expected stabilization of the global economy, the Company expects to emerge in a stronger position.
Based on current commodity prices, we expect to be able to fund our planned capital program for 2020 with cash on hand and cash flow from operating activities. The mid-point of our total capital expenditures (excluding property acquisitions) for 2020 is expected to be approximately $340.0 million, a decrease of over 40% from both our 2019 capital expenditures and our original 2020 guidance. We continuously evaluate our level of drilling and completion activity in light of commodity prices, drilling results and changes in our operating and development costs and will adjust our capital investment program based on such evaluations. See "Cash Flow from Investing Activities" for further discussion of our capital expenditures.
Factors Affecting Results of Operations
Supply, Demand, Market Risk and their Impact on Oil Prices
In the third quarter of 2020, the average price of WTI crude oil dropped 26% from the third quarter of 2019. Crude oil prices were negatively impacted by a variety of factors affecting current and expected supply and demand dynamics, including: the COVID-19 pandemic and related shut-down of various sectors of the global economy, which has resulted in a significant reduction in global demand for crude oil; continued U.S. supply growth driven by advances in drilling and completion technologies; and the delay of an agreement in early 2020 on production levels by members of the Organization of Petroleum Exporting Countries (OPEC) and other oil producing countries, resulting in increased supply in the global market. Other factors impacting the supply and demand of our products include weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials, export capacity, strength of the U.S. dollar as well as other factors, the majority of which are outside of our control. While OPEC and other oil producing countries have reduced production levels, and U.S. production has declined, a significant crude oil price recovery is not expected until global supply matches current lower levels of demand caused by the factors mentioned above, including the COVID-19 pandemic. The Company cannot predict if or when commodity prices will stabilize or at what levels.
Changes in the market prices for oil 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, its 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. The decline in the price of crude oil negatively impacted our oil revenue during the third quarter of 2020 but the value of our realized oil derivatives portfolio increased significantly, helping to offset the negative impact. Additionally, the volatility in commodity prices has impacted the Company’s stock price and the fair value of the Company's debt securities, all of which impact our financial and operating results. Due to the changes in our drilling plans,
we expect that our 2020 PUD conversion rate will be lower than originally anticipated. Our future drilling plans, including our level of expenditures for the development of our oil reserves, total PUD reserves, operations and financial condition may be materially and adversely affected by declines in future oil prices.
QEP's producing properties are primarily located in the Permian and Williston basins. As a result of our lack of diversification
in asset type and limited geographic diversification, any delays or interruptions of production caused by factors such as
governmental regulation, transportation capacity constraints, curtailment of production or interruption of transportation, price
fluctuations, natural disasters or shutdowns of the pipelines connecting our production to refineries, including the potential shutdown of the Dakota Access Pipeline, would have a significantly greater impact on our results of operations than if we possessed more diverse assets and locations.
Global Geopolitical and Macroeconomic Factors
QEP continues to monitor the global economy, including global economic issues impacted by COVID-19; political and civil unrest; oil producing countries' oil production and policies regarding production quotas; 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; the impact of regulations and public and financial market sentiment regarding environmental, social and governance matters; 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 have had, and could continue to have, a significant impact on short-term and long-term oil and condensate, gas and NGL supply, demand and prices and the Company's ability to continue its planned drilling programs which could materially impact the Company's financial position, results of operations and cash flow from operations. 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. Gains on settled derivatives offset a large portion of the impact of the recent decline in oil prices on our oil revenues. There can be no assurances that we will be able to add derivative positions to cover the balance of our forecasted production for 2021 at favorable prices. 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. When an indicator of impairment is identified, the Company uses a cash flow model to assess its proved oil and gas properties and operating lease right-of-use assets for impairment. The cash flow model includes numerous assumptions, including estimates of future oil and condensate, 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 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 drilling 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. The signing of a purchase and sale agreement could also cause the Company to recognize an impairment of proved properties. For assets subject to a purchase and sale agreement, the terms of the purchase and sale agreement are used as an indicator of fair value.
During the nine months ended September 30, 2020, the Company recorded no impairment charges. During the nine months ended September 30, 2019, QEP recorded impairment charges of $5.0 million related to an office building lease.
We could be at risk for proved and unproved property and operating lease right-of-use asset impairments if current market conditions persist for an extended period of time, we experience negative changes in estimated reserve quantities or the
forward oil and gas prices decline from September 30, 2020 levels. The actual amount of impairment incurred, if any, for oil and gas 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 our properties, weighted-average cost of capital, operating cost estimates and future capital expenditure estimates.
Income Tax
The tax legislation enacted in December 2017 reduced our federal corporate tax rate from 35% to 21% and eliminated the corporate AMT, allowing the Company to claim AMT refunds for AMT credits carried forward from prior tax years. The CARES Act enacted in March 2020 permitted the Company to carry back its NOL generated in 2018 and 2019, creating additional AMT credits, and accelerate all of its AMT refunds. The Company received $170.7 million of AMT credit refunds, inclusive of $5.6 million in interest income, during the three months ended September 30, 2020 and $73.9 million of AMT credit refunds in 2019. As of September 30, 2020, the Company expects to receive an additional $81.0 million in AMT credit refunds due to additional NOL carrybacks relating to the 2018 and 2019 tax years. The NOLs that were generated are primarily due to the issuance of final regulations by the U.S Department of Treasury in July 2020 that relate to the deductibility of interest expense. Of the $81.0 million in AMT credit refunds to be received, $50.1 million is included in "Income taxes receivable" and $30.9 million is included in "Other noncurrent assets" on the balance sheets as of September 30, 2020.
Acquisitions and Divestitures
QEP's strategy is to generate FCF, and it believes its inventory of identified drilling locations provides a solid base to achieve this strategy, but it will continue to evaluate and potentially acquire properties in its operating areas to add additional development opportunities and facilitate the drilling of long lateral wells.
Acquisitions
During the nine months ended September 30, 2020 and 2019, QEP acquired various oil and gas properties, which primarily included proved acreage in the Permian Basin for an aggregate purchase price of $4.1 million and $3.6 million, respectively, subject to post-closing purchase price adjustments.
Divestitures
During the nine months ended September 30, 2020, QEP received net cash proceeds of $13.4 million and recorded a net pre-tax gain on sale of $3.7 million, primarily related to the divestiture of properties outside its main operating areas.
In January 2019, QEP sold its Haynesville/Cotton Valley assets (Haynesville Divestiture) and during the year ended December 31, 2019, reached final settlement on asserted environmental and title defects and received aggregate net cash proceeds of $633.9 million. QEP recorded a total net pre-tax loss, including restructuring costs, of $4.0 million. During the three and nine months ended September 30, 2019, QEP recorded $0.3 million and $1.0 million of pre-tax loss on sale, respectively, within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the statements of operations. Refer to Note 3 – Acquisitions and Divestitures in Part 1, Item I of this Quarterly Report on Form 10-Q for more information.
In addition to the Haynesville Divestiture, during the nine months ended September 30, 2019, QEP recorded net cash proceeds of $42.6 million and recorded a net pre-tax gain on sale of $3.5 million related to the divestiture of properties outside our main operating areas.
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. We believe this approach maximizes the economic recovery of oil and condensate through the simultaneous development of multiple subsurface targets, while improving capital efficiency though shared surface facilities, which we believe will reduce per-unit operating costs and result in expanded operating margins and improve our returns on invested capital. Because 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, multi-well pad drilling delays the completion of wells, the commencement of production from new wells, and may negatively affect production from existing offset wells. 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 the timing of planned conversions 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 capital expenditures for a particular reporting period, including, but not limited to those described in Note 11 – 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 2019 Form 10-K. The Company's financial statements are prepared in accordance with GAAP. The preparation of the Company's 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, impairment of long-lived assets and income taxes, among others, may involve a high degree of complexity and judgment on the part of management. Further, these estimates and other factors, including those outside of the Company’s control, such as the impact of sustained lower commodity prices, could have a significant adverse impact to the Company’s financial condition, results of operations and cash flows.
Drilling, Completion and Production Activities
The following table presents operated and non-operated wells in the process of being drilled or waiting on completion as of September 30, 2020:
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Operated
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|
Non-operated
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Drilling
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|
Drilling
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|
Waiting on completion
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|
Drilling
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|
Waiting on completion
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Rigs
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Gross
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Net
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Gross
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Net
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Gross
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Net
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Gross
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Net
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Northern Region
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Williston Basin
|
—
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|
|
—
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|
|
—
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|
|
4
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|
|
2.9
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|
|
—
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—
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|
16
|
|
|
2.4
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Southern Region
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Permian Basin(1)
|
2
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|
|
11
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9.6
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|
46
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|
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41.8
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—
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—
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1
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|
0.1
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____________________________
(1)Six of the eleven gross operated wells that were being drilled in the Permian Basin represented wells for which intermediate casing had been set as of September 30, 2020. Three of the eleven gross operated wells that were being drilled in the Permian Basin represented wells for which surface casing had been set as of September 30, 2020.
Delays in completion of wells could impact planned conversions of PUD reserves to proved developed reserves and volatility in QEP's quarterly operating results. QEP had 50 gross operated wells waiting on completion as of September 30, 2020.
The following table presents the number of operated wells in the process of being drilled or waiting on completion at September 30, 2020 and operated wells completed and turned to sales (put on production) for the nine months ended September 30, 2020:
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Permian Basin
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Williston Basin
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|
|
As of September 30, 2020
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Gross
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Net
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Gross
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Net
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Well Progress
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|
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|
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Drilling
|
11
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|
|
9.6
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|
|
—
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|
|
—
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|
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|
|
|
|
|
|
|
|
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|
|
|
|
|
|
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Waiting on completion
|
46
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|
|
41.8
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|
4
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|
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2.9
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Put on production
|
36
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|
|
34.4
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|
|
2
|
|
|
1.5
|
|
The following table presents the number of operated and non-operated wells completed and turned to sales (put on production) for the three and nine months ended September 30, 2020:
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|
Operated Put on Production
|
|
Non-operated Put on Production
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
September 30, 2020
|
|
September 30, 2020
|
|
September 30, 2020
|
|
September 30, 2020
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
2
|
|
|
1.5
|
|
|
2
|
|
|
1.5
|
|
|
5
|
|
|
1.0
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|
|
10
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|
|
1.0
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|
Southern Region
|
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|
|
|
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|
|
|
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|
|
|
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|
Permian Basin
|
—
|
|
|
—
|
|
|
36
|
|
|
34.4
|
|
|
3
|
|
|
0.3
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|
3
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|
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0.3
|
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RESULTS OF OPERATIONS
Net Income
QEP generated a net loss during the third quarter of 2020 of $49.2 million, or $0.20 per diluted share, compared to net income of $81.0 million, or $0.34 per diluted share, in the third quarter of 2019. The $130.2 million decrease in net income in the third quarter of 2020 compared to 2019 was primarily due to a $196.1 million increase in unrealized derivative losses, partially offset by a $81.8 million increase in income tax benefits.
During the first three quarters of 2020, QEP generated net income of $133.8 million, or $0.55 per diluted share, compared to net income of $13.1 million or $0.06 per diluted share, in the first three quarters of 2019. The $120.7 million increase in net income in the first three quarters of 2020 compared to 2019 was primarily due to a $113.4 million increase in unrealized derivative gains.
See below for additional discussion regarding the components of net income (loss) for each of the periods presented.
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, gains or losses from early extinguishment of debt 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 could 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) (the most comparable 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.
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|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
|
|
(in millions)
|
|
Net income (loss)
|
$
|
(49.2)
|
|
|
$
|
81.0
|
|
|
$
|
133.8
|
|
|
$
|
13.1
|
|
|
Interest expense
|
28.4
|
|
|
32.8
|
|
|
89.8
|
|
|
100.0
|
|
|
Interest and other (income) expense
|
(7.7)
|
|
|
(0.9)
|
|
|
(7.7)
|
|
|
(4.6)
|
|
|
Income tax provision (benefit)
|
(55.2)
|
|
|
26.6
|
|
|
(42.5)
|
|
|
(55.7)
|
|
|
Depreciation, depletion and amortization
|
133.0
|
|
|
144.2
|
|
|
424.6
|
|
|
395.5
|
|
|
Unrealized (gains) losses on derivative contracts
|
103.8
|
|
|
(92.3)
|
|
|
(84.4)
|
|
|
29.0
|
|
|
(Gain)/loss from early extinguishment of debt
|
7.4
|
|
|
—
|
|
|
(18.2)
|
|
|
—
|
|
|
Net (gain) loss from asset sales, inclusive of restructuring costs
|
(0.1)
|
|
|
2.1
|
|
|
(3.8)
|
|
|
(2.5)
|
|
|
Impairment
|
—
|
|
|
—
|
|
|
—
|
|
|
5.0
|
|
|
Adjusted EBITDA
|
$
|
160.4
|
|
|
$
|
193.5
|
|
|
$
|
491.6
|
|
|
$
|
479.8
|
|
In the third quarter of 2020, Adjusted EBITDA decreased to $160.4 million compared to $193.5 million in the third quarter of 2019, primarily due to a $129.8 million decrease in oil, gas, and NGL sales, which was due to a 29% decrease in average field-level equivalent prices and a 16% decrease in total oil equivalent production volumes, partially offset by a $74.5 million increase in realized derivative gains, a $8.7 million reduction in general and administrative expenses, a $6.0 million decrease in production and property taxes and a $5.6 million reduction in transportation and processing costs.
In the first three quarters of 2020, Adjusted EBITDA increased to $491.6 million compared to $479.8 million in the first three quarters of 2019, primarily due to a $259.4 million increase in realized derivative gains, a $61.3 million decrease in general and administrative expenses, a $31.0 million decrease in lease operating costs and a $25.3 million reduction in production and property taxes, partially offset by a $359.9 million decrease in oil, gas and NGL sales, primarily due to a 37% decrease in average field-level prices.
Free Cash Flow (Non-GAAP)
Management defines Free Cash Flow as Adjusted EBITDA plus certain non-cash items that are included in Net Cash Provided by (Used in) Operating Activities but excluded from Adjusted EBITDA less interest expense, excluding amortization of debt issuance costs and discounts, and accrued property, plant and equipment capital expenditures. Management believes that this measure is useful to management and investors for analysis of the Company's ability to repay debt, fund acquisitions or repurchase stock.
Below is a reconciliation of Net Cash Provided by (Used in) Operating Activities (the most comparable GAAP measure) to Free Cash Flow. 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.
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|
|
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|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
|
2020
|
|
2019
|
|
|
|
(in millions)
|
|
Cash Flow Information:
|
|
|
|
|
|
Net Cash Provided by (Used in) Operating Activities
|
|
$
|
554.0
|
|
|
$
|
342.0
|
|
|
Net Cash Provided by (Used in) Investing Activities
|
|
(275.2)
|
|
|
207.7
|
|
|
Net Cash Provided by (Used in) Financing Activities
|
|
(434.7)
|
|
|
(455.7)
|
|
|
|
|
|
|
|
|
Free Cash Flow
|
|
|
|
|
|
Net Cash Provided by (Used in) Operating Activities
|
|
$
|
554.0
|
|
|
$
|
342.0
|
|
|
Amortization of debt issuance costs and discounts
|
|
(3.7)
|
|
|
(4.0)
|
|
|
Interest expense
|
|
89.8
|
|
|
100.0
|
|
|
Unrealized (gains) losses on marketable securities
|
|
1.1
|
|
|
2.8
|
|
|
Interest and other income (expense)
|
|
(7.7)
|
|
|
(4.6)
|
|
|
Deferred income taxes (benefit)
|
|
(165.3)
|
|
|
61.2
|
|
|
Income tax provision (benefit)
|
|
(42.5)
|
|
|
(55.7)
|
|
|
Non-cash share-based compensation
|
|
(9.3)
|
|
|
(16.2)
|
|
|
Non-cash gain (loss) from warehouse inventory
|
|
(0.7)
|
|
|
—
|
|
|
Changes in operating assets and liabilities
|
|
75.9
|
|
|
54.3
|
|
|
Adjusted EBITDA
|
|
$
|
491.6
|
|
|
$
|
479.8
|
|
|
Non-cash share-based compensation
|
|
9.3
|
|
|
16.2
|
|
|
Non-cash (gain) loss from warehouse inventory
|
|
0.7
|
|
|
—
|
|
|
Interest expense, excluding amortization of debt issuance costs and discounts
|
|
(86.1)
|
|
|
(96.0)
|
|
|
Accrued property, plant and equipment capital expenditures
|
|
(253.5)
|
|
|
(466.0)
|
|
|
Free Cash Flow
|
|
$
|
162.0
|
|
|
$
|
(66.0)
|
|
In the first three quarters of 2020, the Company generated FCF of $162.0 million compared to an outspend of $66.0 million in the first three quarters of 2019, primarily due to a $212.5 million decrease in accrued property, plant and equipment capital expenditures, primarily driven by suspending completion activity until the fourth quarter of 2020 and by peer leading drilling and completion costs in the Permian Basin, an $11.8 million increase in Adjusted EBITDA, and a $9.9 million decrease in interest expense, excluding amortization of debt issuance costs and discounts.
Revenue
The following table presents our revenues disaggregated by revenue source.
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
September 30,
|
|
September 30,
|
|
|
2020
|
|
2019
|
|
Change
|
|
2020
|
|
2019
|
|
Change
|
|
|
(in millions)
|
|
Oil and condensate, gas and NGL sales, as presented
|
$
|
175.8
|
|
|
$
|
305.6
|
|
|
$
|
(129.8)
|
|
|
$
|
515.9
|
|
|
$
|
875.8
|
|
|
$
|
(359.9)
|
|
|
Transportation and processing costs included in revenue(1)
|
16.0
|
|
|
14.2
|
|
|
1.8
|
|
|
45.6
|
|
|
40.7
|
|
|
4.9
|
|
|
Oil and condensate, gas and NGL sales, as adjusted(2)
|
$
|
191.8
|
|
|
$
|
319.8
|
|
|
$
|
(128.0)
|
|
|
$
|
561.5
|
|
|
$
|
916.5
|
|
|
$
|
(355.0)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate sales
|
$
|
169.3
|
|
|
$
|
298.8
|
|
|
$
|
(129.5)
|
|
|
$
|
507.8
|
|
|
$
|
834.0
|
|
|
$
|
(326.2)
|
|
|
Gas sales
|
9.3
|
|
|
9.1
|
|
|
0.2
|
|
|
24.6
|
|
|
39.4
|
|
|
(14.8)
|
|
|
NGL sales
|
13.2
|
|
|
11.9
|
|
|
1.3
|
|
|
29.1
|
|
|
43.1
|
|
|
(14.0)
|
|
|
Oil and condensate, gas and NGL sales, as adjusted(2)
|
$
|
191.8
|
|
|
$
|
319.8
|
|
|
$
|
(128.0)
|
|
|
$
|
561.5
|
|
|
$
|
916.5
|
|
|
$
|
(355.0)
|
|
____________________________
(1)Depending on the terms of the contract, a portion of the total transportation and processing costs incurred by the Company are deducted from revenue. Refer to the Operating Expenses section below for a reconciliation of total transportation and processing costs.
(2)Oil and condensate, gas and NGL sales (the most comparable GAAP measure) as presented on the statements of operations is reconciled to oil and condensate, gas and NGL sales, as adjusted (a non-GAAP measure). Management excludes costs deducted from revenue to reflect total revenue associated with its production prior to deducting any expenses. Management believes that this non-GAAP measure is useful supplemental information for investors as it is reflective of the total revenue generated from its wells for the period. This non-GAAP measure should be considered by the reader in addition to, but not instead of, the financial measure prepared in accordance with GAAP. Refer to Note 2 – Revenue in Part 1, Item I of this Quarterly Report on Form 10-Q.
Revenue, Volume and Price Variance Analysis
The following table shows volume and price related changes for each of QEP's adjusted production-related revenue categories for the three and nine months ended September 30, 2020, compared to the three and nine months ended September 30, 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate
|
|
Gas
|
|
NGL
|
|
Total
|
|
|
(in millions)
|
|
Oil and condensate, gas and NGL sales, as adjusted
|
|
|
|
|
|
|
|
|
Three months ended September 30, 2019
|
$
|
298.8
|
|
|
$
|
9.1
|
|
|
$
|
11.9
|
|
|
$
|
319.8
|
|
|
Changes associated with volumes(1)
|
(64.4)
|
|
|
(0.1)
|
|
|
(0.8)
|
|
|
(65.3)
|
|
|
Changes associated with prices(2)
|
(65.1)
|
|
|
0.3
|
|
|
2.1
|
|
|
(62.7)
|
|
|
Three months ended September 30, 2020
|
$
|
169.3
|
|
|
$
|
9.3
|
|
|
$
|
13.2
|
|
|
$
|
191.8
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate, gas and NGL sales, as adjusted
|
|
|
|
|
|
|
|
|
Nine months ended September 30, 2019
|
$
|
834.0
|
|
|
$
|
39.4
|
|
|
$
|
43.1
|
|
|
$
|
916.5
|
|
|
Changes associated with volumes(1)
|
(40.9)
|
|
|
(0.6)
|
|
|
0.8
|
|
|
(40.7)
|
|
|
Changes associated with prices(2)
|
(285.3)
|
|
|
(14.2)
|
|
|
(14.8)
|
|
|
(314.3)
|
|
|
Nine months ended September 30, 2020
|
$
|
507.8
|
|
|
$
|
24.6
|
|
|
$
|
29.1
|
|
|
$
|
561.5
|
|
____________________________
(1)The revenue variance attributed to the change in volume is calculated by multiplying the change in volume from the three and nine months ended September 30, 2020, as compared to the three and nine months ended September 30, 2019, by the average field-level price for the three and nine months ended September 30, 2019.
(2)The revenue variance attributed to the change in price is calculated by multiplying the change in average field-level price from the three and nine months ended September 30, 2020, as compared to the three and nine months ended September 30, 2019, by the respective volumes for the three and nine months ended September 30, 2020. Pricing changes are driven by changes in commodity average field-level prices, excluding the impact from commodity derivatives.
Production and Pricing
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2020
|
|
2019
|
|
Change
|
|
2020
|
|
2019
|
|
Change
|
|
Total production volumes (Mboe)
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
2,680.6
|
|
|
2,722.5
|
|
|
(41.9)
|
|
|
8,173.7
|
|
|
9,061.9
|
|
|
(888.2)
|
|
|
Other Northern
|
0.1
|
|
|
19.4
|
|
|
(19.3)
|
|
|
7.1
|
|
|
65.1
|
|
|
(58.0)
|
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
4,376.2
|
|
|
5,658.5
|
|
|
(1,282.3)
|
|
|
14,776.1
|
|
|
14,293.2
|
|
|
482.9
|
|
|
Haynesville/Cotton Valley
|
—
|
|
|
(0.4)
|
|
|
0.4
|
|
|
—
|
|
|
310.5
|
|
|
(310.5)
|
|
|
Other Southern
|
0.1
|
|
|
4.0
|
|
|
(3.9)
|
|
|
3.9
|
|
|
14.3
|
|
|
(10.4)
|
|
|
Total production
|
7,057.0
|
|
|
8,404.0
|
|
|
(1,347.0)
|
|
|
22,960.8
|
|
|
23,745.0
|
|
|
(784.2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total equivalent prices (per Boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
Average field-level equivalent price
|
$
|
27.17
|
|
|
$
|
38.06
|
|
|
$
|
(10.89)
|
|
|
$
|
24.46
|
|
|
$
|
38.60
|
|
|
$
|
(14.14)
|
|
|
Commodity derivative impact
|
9.86
|
|
|
(0.59)
|
|
|
10.45
|
|
|
10.13
|
|
|
(1.13)
|
|
|
11.26
|
|
|
Net realized equivalent price
|
$
|
37.03
|
|
|
$
|
37.47
|
|
|
$
|
(0.44)
|
|
|
$
|
34.59
|
|
|
$
|
37.47
|
|
|
$
|
(2.88)
|
|
Oil and Condensate Volumes and Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2020
|
|
2019
|
|
Change
|
|
2020
|
|
2019
|
|
Change
|
|
Oil and condensate production volumes (Mbbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
1,643.2
|
|
|
1,700.3
|
|
|
(57.1)
|
|
|
5,149.5
|
|
|
5,719.7
|
|
|
(570.2)
|
|
|
Other Northern
|
0.4
|
|
|
12.1
|
|
|
(11.7)
|
|
|
(1.7)
|
|
|
36.1
|
|
|
(37.8)
|
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
2,803.7
|
|
|
3,956.5
|
|
|
(1,152.8)
|
|
|
9,976.8
|
|
|
10,144.9
|
|
|
(168.1)
|
|
|
Other Southern
|
—
|
|
|
1.6
|
|
|
(1.6)
|
|
|
0.3
|
|
|
3.7
|
|
|
(3.4)
|
|
|
Total production
|
4,447.3
|
|
|
5,670.5
|
|
|
(1,223.2)
|
|
|
15,124.9
|
|
|
15,904.4
|
|
|
(779.5)
|
|
|
Average field-level oil prices (per bbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
$
|
35.63
|
|
|
$
|
51.92
|
|
|
$
|
(16.29)
|
|
|
$
|
33.67
|
|
|
$
|
53.38
|
|
|
$
|
(19.71)
|
|
|
Southern Region
|
$
|
39.49
|
|
|
$
|
53.03
|
|
|
$
|
(13.54)
|
|
|
$
|
33.53
|
|
|
$
|
51.91
|
|
|
$
|
(18.38)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average field-level price
|
$
|
38.07
|
|
|
$
|
52.70
|
|
|
$
|
(14.63)
|
|
|
$
|
33.58
|
|
|
$
|
52.44
|
|
|
$
|
(18.86)
|
|
|
Commodity derivative impact
|
15.82
|
|
|
(0.87)
|
|
|
16.69
|
|
|
15.41
|
|
|
(1.50)
|
|
|
16.91
|
|
|
Net realized price
|
$
|
53.89
|
|
|
$
|
51.83
|
|
|
$
|
2.06
|
|
|
$
|
48.99
|
|
|
$
|
50.94
|
|
|
$
|
(1.95)
|
|
Oil and condensate revenues decreased $129.5 million, or 43%, in the third quarter of 2020 compared to the third quarter of 2019, due to lower average field-level prices and lower aggregate oil and condensate production volumes. Average field-level oil prices decreased 28% in the third quarter of 2020 compared to the third quarter of 2019, primarily driven by a decrease in average NYMEX-WTI oil prices, partially offset by a $0.81 per bbl, or 22%, decrease in the basis differential relative to the average NYMEX-WTI oil price for the comparable periods. The net realized price for the third quarter of 2020 was $53.89 per barrel, which included a $15.82 per barrel positive impact from our settled derivative contracts. The net realized price was 4% higher than the $51.83 per barrel net realized price in the third quarter of 2019 primarily due to the increase in settled derivative contracts, offset by the significant decline in the average field-level price. The 22% decrease in production volumes was primarily driven by a decrease in production in the Permian and Williston basins due to reduced drilling and the suspension of completion activity in 2020 in response to market conditions.
Oil and condensate revenues decreased $326.2 million, or 39%, in the first three quarters of 2020 compared to the first three quarters of 2019, due to lower average field-level prices and lower aggregate oil and condensate production volumes. Average field-level oil prices decreased 36% in the first three quarters of 2020 compared to the first three quarters of 2019, primarily driven by a decrease in average NYMEX-WTI oil prices, partially offset by a $0.13 per bbl, or 3%, decrease in the basis differential relative to the average NYMEX-WTI oil price for the comparable periods. The net realized price for the first three quarters of 2020 was $48.99 per barrel, which included a $15.41 per barrel positive impact from our settled derivative contracts. The net realized price was 4% lower than the $50.94 net realized price per barrel in the first three quarters of 2019 due to the significant decline in the average field-level price, partially offset by the impact from our settled derivative contracts. The 5% decrease in production volumes was primarily driven by a decrease in production in the Williston and Permian basins due reduced drilling and the suspension of completion activity in 2020 in response to market conditions.
Gas Volumes and Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2020
|
|
2019
|
|
Change
|
|
2020
|
|
2019
|
|
Change
|
|
Gas production volumes (Bcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
2.8
|
|
|
3.3
|
|
|
(0.5)
|
|
|
8.5
|
|
|
10.6
|
|
|
(2.1)
|
|
|
Other Northern
|
—
|
|
|
—
|
|
|
—
|
|
|
0.1
|
|
|
0.1
|
|
|
—
|
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
5.0
|
|
|
4.8
|
|
|
0.2
|
|
|
15.4
|
|
|
11.9
|
|
|
3.5
|
|
|
Haynesville/Cotton Valley
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1.9
|
|
|
(1.9)
|
|
|
Other Southern
|
—
|
|
|
0.1
|
|
|
(0.1)
|
|
|
—
|
|
|
0.1
|
|
|
(0.1)
|
|
|
Total production
|
7.8
|
|
|
8.2
|
|
|
(0.4)
|
|
|
24.0
|
|
|
24.6
|
|
|
(0.6)
|
|
|
Average field-level gas prices (per Mcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
$
|
1.13
|
|
|
$
|
1.72
|
|
|
$
|
(0.59)
|
|
|
$
|
1.39
|
|
|
$
|
2.41
|
|
|
$
|
(1.02)
|
|
|
Southern Region
|
$
|
1.19
|
|
|
$
|
0.71
|
|
|
$
|
0.48
|
|
|
$
|
0.81
|
|
|
$
|
0.98
|
|
|
$
|
(0.17)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average field-level price
|
$
|
1.17
|
|
|
$
|
1.13
|
|
|
$
|
0.04
|
|
|
$
|
1.02
|
|
|
$
|
1.61
|
|
|
$
|
(0.59)
|
|
|
Commodity derivative impact
|
(0.10)
|
|
|
—
|
|
|
(0.10)
|
|
|
(0.02)
|
|
|
(0.12)
|
|
|
0.10
|
|
|
Net realized price
|
$
|
1.07
|
|
|
$
|
1.13
|
|
|
$
|
(0.06)
|
|
|
$
|
1.00
|
|
|
$
|
1.49
|
|
|
$
|
(0.49)
|
|
Gas revenues increased $0.2 million, or 2%, in the third quarter of 2020 compared to the third quarter of 2019, due to higher average field-level prices, partially offset by lower gas production volumes. Average field-level gas prices increased 4% in the third quarter of 2020 compared to the third quarter of 2019, primarily driven by a $0.42 per Mcf, or 34%, decrease in regional basis differentials, partially offset by a decrease in average NYMEX-HH gas spot prices in comparable periods. Production volumes decreased 5% in the third quarter of 2020 compared to the third quarter of 2019, primarily due to a decrease in production in the Williston Basin due to the suspension of completion activity in 2020 in response to market conditions, partially offset by increased production in the Permian Basin.
Gas revenues decreased $14.8 million, or 38%, in the first three quarters of 2020 compared to the first three quarters of 2019, due to lower average field-level prices and lower gas production volumes. Average field-level gas prices decreased 37% in the first three quarters of 2020 compared to the first three quarters of 2019, primarily driven by a decrease in average NYMEX-HH gas spot prices, partially offset by a $0.17 per Mcf, or 16%, decrease in regional basis differentials relative to the average NYMEX-HH gas price in comparable periods. Production volumes decreased 2% in the first three quarters of 2020 compared to the first three quarters of 2019, primarily due to the suspension of completion activity in the Williston Basin in response to market conditions and the Haynesville Divestiture. These production decreases were partially offset by increased production in the Permian Basin.
NGL Volumes and Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2020
|
|
2019
|
|
Change
|
|
2020
|
|
2019
|
|
Change
|
|
NGL production volumes (Mbbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
|
550.3
|
|
|
472.1
|
|
|
78.2
|
|
|
1,585.4
|
|
|
1,577.5
|
|
|
7.9
|
|
|
Other Northern
|
0.1
|
|
|
0.7
|
|
|
(0.6)
|
|
|
0.6
|
|
|
1.1
|
|
|
(0.5)
|
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
736.8
|
|
|
909.9
|
|
|
(173.1)
|
|
|
2,234.5
|
|
|
2,168.4
|
|
|
66.1
|
|
|
Other Southern
|
(0.1)
|
|
|
0.3
|
|
|
(0.4)
|
|
|
0.3
|
|
|
0.8
|
|
|
(0.5)
|
|
|
Total production
|
1,287.1
|
|
|
1,383.0
|
|
|
(95.9)
|
|
|
3,820.8
|
|
|
3,747.8
|
|
|
73.0
|
|
|
Average field-level NGL prices (per bbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Region
|
$
|
7.51
|
|
|
$
|
5.26
|
|
|
$
|
2.25
|
|
|
$
|
5.11
|
|
|
$
|
9.92
|
|
|
$
|
(4.81)
|
|
|
Southern Region
|
$
|
12.26
|
|
|
$
|
10.38
|
|
|
$
|
1.88
|
|
|
$
|
9.40
|
|
|
$
|
12.65
|
|
|
$
|
(3.25)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average field-level price
|
$
|
10.23
|
|
|
$
|
8.63
|
|
|
$
|
1.60
|
|
|
$
|
7.62
|
|
|
$
|
11.50
|
|
|
$
|
(3.88)
|
|
|
Commodity derivative impact
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Net realized price
|
$
|
10.23
|
|
|
$
|
8.63
|
|
|
$
|
1.60
|
|
|
$
|
7.62
|
|
|
$
|
11.50
|
|
|
$
|
(3.88)
|
|
NGL revenues increased $1.3 million, or 11%, during the third quarter of 2020 compared to the third quarter of 2019, due to higher average field-level prices, partially offset by lower NGL production volumes. The 19% increase in NGL prices during the third quarter of 2020 compared to the third quarter of 2019 was primarily driven by an increase in propane, ethane and other NGL component prices. The 7% decrease in NGL production volumes was primarily due to reduced drilling and the suspension of completion activity in 2020 in response to market conditions, and a decreased amount of the ethane recovered as NGL in the Permian Basin, partially offset by increased ethane recovered as NGL in the Williston Basin.
NGL revenues decreased $14.0 million, or 32%, during the first three quarters of 2020 compared to the first three quarters of 2019, due to lower average field-level prices, partially offset by higher NGL production volumes. The 34% decrease in NGL prices during the first three quarters of 2020 compared to the first three quarters of 2019 was primarily driven by a decrease in propane, ethane and other NGL component prices. The 2% increase in NGL production volumes was primarily driven by increased NGL recoveries in the Permian Basin.
Operating Expenses
The following table presents QEP production costs and production costs on a per unit of production basis:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2020
|
|
2019
|
|
Change
|
|
2020
|
|
2019
|
|
Change
|
|
|
(in millions)
|
|
Lease operating expense
|
$
|
35.5
|
|
|
$
|
38.3
|
|
|
$
|
(2.8)
|
|
|
$
|
104.5
|
|
|
$
|
135.5
|
|
|
$
|
(31.0)
|
|
|
Adjusted transportation and processing costs(1)
|
28.4
|
|
|
32.2
|
|
|
(3.8)
|
|
|
83.8
|
|
|
79.5
|
|
|
4.3
|
|
|
Production and property taxes
|
14.0
|
|
|
20.0
|
|
|
(6.0)
|
|
|
42.3
|
|
|
67.6
|
|
|
(25.3)
|
|
|
Total production costs
|
$
|
77.9
|
|
|
$
|
90.5
|
|
|
$
|
(12.6)
|
|
|
$
|
230.6
|
|
|
$
|
282.6
|
|
|
$
|
(52.0)
|
|
|
|
(per Boe)
|
|
Lease operating expense
|
$
|
5.03
|
|
|
$
|
4.56
|
|
|
$
|
0.47
|
|
|
$
|
4.55
|
|
|
$
|
5.71
|
|
|
$
|
(1.16)
|
|
|
Adjusted transportation and processing costs(1)
|
4.04
|
|
|
3.83
|
|
|
0.21
|
|
|
3.65
|
|
|
3.34
|
|
|
0.31
|
|
|
Production and property taxes
|
1.98
|
|
|
2.38
|
|
|
(0.40)
|
|
|
1.84
|
|
|
2.85
|
|
|
(1.01)
|
|
|
Total production costs
|
$
|
11.05
|
|
|
$
|
10.77
|
|
|
$
|
0.28
|
|
|
$
|
10.04
|
|
|
$
|
11.90
|
|
|
$
|
(1.86)
|
|
____________________________
(1)Below are reconciliations of transportation and processing costs (the most comparable GAAP measure) as presented on the statements of operations and on a unit of production basis to adjusted transportation and processing costs. Adjusted transportation and processing costs includes transportation and processing costs that are reflected as part of "Oil and condensate, gas and NGL sales" on the statements of operations. Management adds these costs together to reflect the total operating costs associated with its production. Management believes that this non-GAAP measure is useful supplemental information for investors as it is reflective of the total production costs required to operate the wells for the period. This non-GAAP measure should be considered by the reader in addition to, but not instead of, the financial measure prepared in accordance with GAAP. Refer to Note 2 – Revenue in Part 1, Item I of this Quarterly Report on Form 10-Q.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2020
|
|
2019
|
|
Change
|
|
2020
|
|
2019
|
|
Change
|
|
|
(in millions)
|
|
Transportation and processing costs, as presented
|
$
|
12.4
|
|
|
$
|
18.0
|
|
|
$
|
(5.6)
|
|
|
$
|
38.2
|
|
|
$
|
38.8
|
|
|
$
|
(0.6)
|
|
|
Transportation and processing costs deducted from oil and condensate, gas and NGL sales
|
16.0
|
|
|
14.2
|
|
|
1.8
|
|
|
45.6
|
|
|
40.7
|
|
|
4.9
|
|
|
Adjusted transportation and processing costs
|
$
|
28.4
|
|
|
$
|
32.2
|
|
|
$
|
(3.8)
|
|
|
$
|
83.8
|
|
|
$
|
79.5
|
|
|
$
|
4.3
|
|
|
|
(per Boe)
|
|
Transportation and processing costs, as presented
|
$
|
1.77
|
|
|
$
|
2.14
|
|
|
$
|
(0.37)
|
|
|
$
|
1.66
|
|
|
$
|
1.63
|
|
|
$
|
0.03
|
|
|
Transportation and processing costs deducted from oil and condensate, gas and NGL sales
|
2.27
|
|
|
1.69
|
|
|
0.58
|
|
|
1.99
|
|
|
1.71
|
|
|
0.28
|
|
|
Adjusted transportation and processing costs
|
$
|
4.04
|
|
|
$
|
3.83
|
|
|
$
|
0.21
|
|
|
$
|
3.65
|
|
|
$
|
3.34
|
|
|
$
|
0.31
|
|
Lease operating expense (LOE). QEP's LOE decreased $2.8 million, or 7%, in the third quarter of 2020 compared to the third quarter of 2019, primarily due to a decrease in workover activity in the Williston Basin, a decrease in water disposal costs in the Williston and Permian basins and continuing efforts to reduce operating expenses, partially offset by an increase in workover activity in the Permian Basin.
During the third quarter of 2020, LOE increased $0.47 per Boe, or 10%, compared to the third quarter of 2019, primarily due to decreased production in the Permian and Williston basins, partially offset by continuing efforts to reduce operating expenses.
QEP's LOE decreased $31.0 million, or 23%, in the first three quarters of 2020 compared to the first three quarters of 2019, primarily due to a decrease in workover activity in the Williston Basin and a decrease in maintenance and repair expenses, water disposal costs, power and fuel expenses and chemical expenses in the Williston and Permian basins as a result of continuing efforts to reduce operating expenses.
During the first three quarters of 2020, LOE decreased $1.16 per Boe, or 20%, compared to the first three quarters of 2019, primarily due to continuing efforts to reduce operating expenses, despite decreased production in the Permian and Williston basins.
Adjusted transportation and processing costs (non-GAAP). Adjusted transportation and processing costs decreased $3.8 million, or 12%, in the third quarter of 2020 compared to the third quarter of 2019. The decrease in expense was primarily due to the recognition of $7.7 million of firm transportation expense in the third quarter of 2019 related to future obligations in an area in which the Company no longer has production operations as well as decreased production in the Permian and Williston basins, partially offset by an increase in gathering and processing rates in the Permian and Williston basins.
During the third quarter of 2020, adjusted transportation and processing costs increased $0.21 per Boe, or 5%, compared to the third quarter of 2019. The increase was primarily due to increased gathering and processing rates in the Williston and Permian basins, partially offset by the recognition of $7.7 million of firm transportation expense in the third quarter of 2019 related to future obligations in an area in which the Company no longer has production operations.
Adjusted transportation and processing costs increased $4.3 million, or 5%, in the first three quarters of 2020 compared to the first three quarters of 2019. The increase in expense was primarily due to increased production in the Permian Basin and increased gathering and processing rates in the Williston Basin, partially offset by the recognition of $7.7 million of firm transportation expense in the first three quarters of 2019 related to future obligations in an area in which the Company no longer has production operations, the Haynesville Divestiture and decreased production in the Williston Basin.
During the first three quarters of 2020, adjusted transportation and processing costs increased $0.31 per Boe, or 9%, compared to the first three quarters of 2019. The increase was primarily due to increased gathering and processing rates in the Williston Basin, partially offset by the recognition of $7.7 million of firm transportation expense in the first three quarters of 2019 related to future obligations in an area in which the Company no longer has production operations.
Production and property taxes. Production and property taxes decreased $6.0 million, or 30%, in the third quarter of 2020 compared to the third quarter of 2019, primarily due to decreased revenues in the Williston and Permian basins and the related production taxes, partially offset by increased property tax expense.
During the third quarter of 2020, production and property taxes decreased $0.40 per Boe, or 17%, compared to the third quarter of 2019, primarily due to a decrease in revenues and the associated production taxes in the Williston and Permian basins.
Production and property taxes decreased $25.3 million, or 37%, in the first three quarters of 2020 compared to the first three quarters of 2019, primarily due to decreased revenues in the Williston and Permian basins and the related production taxes and decreased property tax expense.
During the first three quarters of 2020, production and property taxes decreased $1.01 per Boe, or 35%, compared to the first three quarters of 2019, primarily due to a decrease in revenues and the associated production taxes in the Williston and Permian basins and lower property tax expense in the Permian Basin.
Depreciation, depletion and amortization (DD&A). DD&A expense decreased $11.2 million in the third quarter of 2020 compared to the third quarter of 2019, primarily due to decreased production in the Permian and Williston basins, partially offset by higher DD&A rates in the Permian and Williston basins.
DD&A expense increased $29.1 million in the first three quarters of 2020 compared to the first three quarters of 2019, primarily due to higher DD&A rates in the Permian and Williston basins and increased production in the Permian Basin. The increases in DD&A expense were partially offset by a decrease in production in the Williston Basin.
Impairment expense. During the third quarter of 2020 and 2019, there were no impairment charges.
During the first three quarters of 2020, there were no impairment charges. During the first three quarters of 2019, QEP recorded impairment charges of $5.0 million, which related to impairment of an office building lease.
General and administrative (G&A) expense.
The following table presents detail about QEP's share-based compensation and deferred compensation components of QEP's total general and administrative expense, including the cash and non-cash components, for the three and nine months ended September 30, 2020 and 2019.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2020
|
|
2019
|
|
Change
|
|
2020
|
|
2019
|
|
Change
|
|
|
(in millions)
|
|
General and administrative (excluding share-based and deferred compensation)
|
$
|
16.5
|
|
|
$
|
28.6
|
|
|
$
|
(12.1)
|
|
|
$
|
54.8
|
|
|
$
|
102.8
|
|
|
$
|
(48.0)
|
|
|
General and administrative (share-based and deferred compensation):
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash share-based compensation (1)
|
1.0
|
|
|
(0.9)
|
|
|
1.9
|
|
|
1.7
|
|
|
4.8
|
|
|
(3.1)
|
|
|
Non-cash share-based compensation (1)
|
2.9
|
|
|
5.0
|
|
|
(2.1)
|
|
|
9.3
|
|
|
16.2
|
|
|
(6.9)
|
|
|
Deferred compensation mark-to-market adjustments (2)
|
0.5
|
|
|
(3.1)
|
|
|
3.6
|
|
|
(2.7)
|
|
|
0.6
|
|
|
(3.3)
|
|
|
Total General and administrative
|
$
|
20.9
|
|
|
$
|
29.6
|
|
|
$
|
(8.7)
|
|
|
$
|
63.1
|
|
|
$
|
124.4
|
|
|
$
|
(61.3)
|
|
|
|
(per Boe)
|
|
General and administrative (excluding share-based and deferred compensation)
|
$
|
2.34
|
|
|
$
|
3.40
|
|
|
$
|
(1.06)
|
|
|
$
|
2.39
|
|
|
$
|
4.33
|
|
|
$
|
(1.94)
|
|
|
General and administrative (share-based and deferred compensation):
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash share-based compensation (1)
|
0.14
|
|
|
(0.11)
|
|
|
0.25
|
|
|
0.07
|
|
|
0.20
|
|
|
(0.13)
|
|
|
Non-cash share-based compensation (1)
|
0.41
|
|
|
0.59
|
|
|
(0.18)
|
|
|
0.41
|
|
|
0.68
|
|
|
(0.27)
|
|
|
Deferred compensation mark-to-market adjustments (2)
|
0.07
|
|
|
(0.37)
|
|
|
0.44
|
|
|
(0.12)
|
|
|
0.03
|
|
|
(0.15)
|
|
|
Total General and administrative
|
$
|
2.96
|
|
|
$
|
3.51
|
|
|
$
|
(0.55)
|
|
|
$
|
2.75
|
|
|
$
|
5.24
|
|
|
$
|
(2.49)
|
|
____________________________
(1)Cash share-based compensation represents restricted cash awards, performance share units and restricted share units recorded under the Company's Long-Term Incentive Plan and Cash Incentive Plan. Non-cash share-based compensation represents stock options and restricted share awards recorded under the Company's Long-Term Incentive Plan. Refer to Note 12 – Share-Based and Long-Term Incentive Compensation, in Item I of Part I of this Quarterly Report on Form 10-Q for more information on share-based compensation.
(2)Deferred compensation mark-to-market adjustments represents mark-to-market adjustments of the Company’s nonqualified, unfunded deferred compensation wrap plan (Wrap Plan). Refer to Note 1 – Basis of Presentation, in Item I of Part I of this Quarterly Report on Form 10-Q for more information on the Wrap Plan.
During the third quarter of 2020, G&A expense decreased $8.7 million, or 29%, compared to the third quarter of 2019. During the third quarter of 2020 and 2019, QEP incurred less than $0.1 million and $10.0 million, respectively, in costs associated with the implementation of our strategic initiatives. Of the $10.0 million incurred in the third quarter of 2019, $10.4 million related to restructuring costs (refer to Note 9 – Restructuring, in Item I of Part I of this Quarterly Report on Form 10-Q). Excluding costs associated with the implementation of our strategic initiatives, G&A expense increased by $1.4 million, or 7%, primarily due to a $5.4 million increase in expense related to the increase in market value on the Wrap Plan and performance share units, partially offset by $3.3 million lower labor, benefits and other associated costs as a result of the reduction in our workforce.
During the first three quarters of 2020, G&A expense decreased $61.3 million, or 49%, compared to the first three quarters of 2019. During the first three quarters of 2020 and 2019, QEP incurred $2.0 million and $43.2 million, respectively, in costs associated with the implementation of our strategic initiatives, of which $1.9 million and $36.7 million, respectively, related to restructuring costs (refer to Note 9 – Restructuring, in Item I of Part I of this Quarterly Report on Form 10-Q). Excluding costs associated with the implementation of our strategic initiatives, G&A expense decreased by $20.1 million, or 25%, primarily due to $15.4 million lower labor, benefits and other associated costs as a result of the reduction in our workforce and a $3.3 million decrease in expense related to the decrease in market value on the Wrap Plan.
Net gain (loss) from asset sales, inclusive of restructuring costs. During the third quarter of 2020, QEP recognized a gain on the sale of assets of $0.1 million, primarily related to divestitures of properties outside our main operating areas. During the third quarter of 2019, QEP recognized a loss on the sale of assets of $2.1 million, primarily related to a $2.7 million loss on the sale of the corporate aircraft, partially offset by a $0.9 million gain related to the divestiture of properties outside our main operating areas.
During the first three quarters of 2020, QEP recognized a gain on the sale of assets of $3.8 million, primarily related to divestitures of properties outside our main operating areas. During the first three quarters of 2019, QEP recognized a gain on the sale of assets of $2.5 million, primarily related to the $3.5 million gain from the divestiture of other properties, partially offset by the loss on the sale of the corporate aircraft and a net pre-tax loss on sale of $1.0 million related to our Haynesville Divestiture, which included $1.4 million of restructuring costs (refer to Note 9 – Restructuring, in Item I of Part I of this Quarterly Report on Form 10-Q for more information).
Non-operating Expenses
Realized and unrealized gains (losses) on derivative contracts. Gains and losses on derivative contracts are comprised of both realized and unrealized gains and losses on QEP's commodity derivative contracts, which are marked-to-market each quarter. During the third quarter of 2020, losses on commodity derivative contracts were $34.2 million, of which $103.8 million were unrealized losses and $69.6 million were realized gains on settled derivative contracts. During the third quarter of 2019, gains on commodity derivative contracts were $87.4 million, of which $92.3 million were unrealized gains and $4.9 million were realized losses on settled derivative contracts.
During the first three quarters of 2020, gains on commodity derivative contracts were $317.0 million, of which $84.4 million were unrealized gains and $232.6 million were realized gains on settled derivative contracts. During the first three quarters of 2019, losses on commodity derivative contracts were $55.8 million, of which $30.8 million were unrealized losses, $26.8 million were realized losses on settled derivative contracts and $1.8 million were unrealized gains related to the Haynesville Divestiture (refer to Note 7 – Derivative Contracts, in Item I of Part I of the Quarterly Report on Form 10-Q for more information).
Gain (loss) on early extinguishment of debt. Loss on early extinguishment of debt increased by $7.4 million during the third quarter of 2020 compared to the third quarter of 2019. The increase during the third quarter of 2020 was due to a $7.4 million loss as a result of redeeming $275.3 million in principal amount of our 2021 Senior Notes (Refer to Note 10 – Debt, in Item 1 of Part I of this Quarterly Report on Form 10-Q for more information).
Gain on early extinguishment of debt increased by $18.2 million during the first three quarters of 2020 compared to the first three quarters of 2019. The increase during the first three quarters of 2020 was primarily due to a $27.1 million gain as a result of senior note repurchases, partially offset by a $7.4 million loss as a result of the redemption of the 2021 Senior Notes and a $1.5 million loss associated with the write-off of non-cash deferred financing costs as part of amending the credit facility (Refer to Note 10 – Debt, in Item 1 of Part I of this Quarterly Report on Form 10-Q for more information).
Interest and other income (expense). Interest and other income (expense) increased by $6.8 million, or 756%, during the third quarter of 2020 compared to the third quarter of 2019. The increase in income was primarily related to the receipt of $5.6 million of interest income associated with the receipt of the AMT credit refunds and a $1.0 million gain on the marketable securities associated with the Company's nonqualified, unfunded deferred compensation plan.
Interest and other income (expense) increased by $3.1 million, or 67%, during the first three quarters of 2020 compared to the first three quarters of 2019. The increase in income was primarily related to the receipt of $5.6 million of interest income associated with the receipt of the AMT credit refunds, partially offset by a $1.7 million loss on the marketable securities associated with the Company's nonqualified, unfunded deferred compensation plan.
Interest expense. Interest expense decreased $4.4 million, or 13%, during the third quarter of 2020 compared to the third quarter of 2019. The decrease was primarily related to decreased interest expense on senior notes due to debt repurchases.
Interest expense decreased $10.2 million, or 10%, during the first three quarters of 2020 compared to the first three quarters of 2019. The decrease was primarily related to decreased interest expense on senior notes due to debt repurchases, a reduction of accrued interest on the Company's uncertain tax position that expired in the fourth quarter of 2019 and decreased borrowings under the credit facility.
Income tax (provision) benefit. Income tax expense decreased $81.8 million to a benefit during the third quarter of 2020 compared to tax expense during the third quarter of 2019. The decrease in expense to a benefit was primarily the result of having a pre-tax loss during the third quarter of 2020 compared to pre-tax income in 2019. QEP’s effective federal and state income tax rate was 52.9% during the third quarter of 2020 compared to a rate of 24.7% during the third quarter of 2019. The increase in the federal and state income tax rate was primarily driven by the impact of discrete items (unusual or infrequent items impacting the tax provision) and permanent differences recognized during the third quarter of 2020 and 2019. During the third quarter of 2020 the effective rate was above the statutory rate due to discrete items recognized in the third quarter of 2020, including the remeasurement of deferred taxes due to NOL carrybacks under the CARES Act to a year with a higher federal tax rate, partially offset by a state tax payment. During the third quarter of 2019 the rate was driven higher than the statutory rate by the recognition of a discrete item related to share-based compensation and a permanent difference related to the change in the estimated amount of non-deductible executive compensation.
Income tax benefit decreased $13.2 million during the first three quarters of 2020 compared to the first three quarters of 2019. QEP’s effective federal and state income tax rate was negative 46.5% during the first three quarters of 2020 compared to a rate of 130.8% during the first three quarters of 2019. The decrease in the federal and state income tax rate was primarily driven by the impact of discrete items and permanent differences recognized during the first three quarters of 2020 and 2019. During the first three quarters of 2020 the primary discrete items lowering the effective tax rate was the remeasurement of deferred taxes due to NOL carrybacks under the CARES Act to a year with a higher federal tax rate. The primary discrete items recognized during the nine months ended September 30, 2019 related to the remeasurement of deferred taxes associated with the Haynesville Divestiture, share-based compensation and a permanent difference related to the estimated amount of non-deductible executive compensation.
LIQUIDITY AND CAPITAL RESOURCES
QEP strives to maintain sufficient liquidity to ensure financial flexibility, withstand commodity price volatility and fund its development projects, operations and capital expenditures and return capital to shareholders. The Company utilizes derivative contracts to reduce the financial impact of commodity price volatility and provide a level of certainty to the Company's cash flows. QEP generally funds its operations and planned capital expenditures with cash flow from its operating activities, cash on hand and borrowings under its revolving credit facility. QEP also periodically accesses debt and equity markets and sells properties to enhance its liquidity. In an effort to preserve our liquidity, in March 2020, the Board indefinitely suspended the payment of quarterly dividends. The Company expects that the annual generation of Free Cash Flow, cash on hand, AMT credit refunds and, as needed, borrowings made under its revolving credit facility, will be sufficient to fund its operations, capital expenditures, interest expense and debt maturities during the next 12 months. To the extent that the Company sells additional assets, the Company plans to use the proceeds to fund on-going operations, reduce debt and for general corporate purposes.
During the nine months ended September 30, 2020, QEP generated $162.0 million of FCF, received cash proceeds of $170.7 million from the AMT credit refunds and received $13.4 million from the disposition of assets. The Company used the proceeds, as well as cash on hand, to repay $430.5 million in principal amount of outstanding debt and for general corporate purposes.
As of September 30, 2020, the Company had $9.5 million in cash and cash equivalents, no borrowings under its revolving credit facility and $11.9 million in letters of credit outstanding. The Company estimates that as of September 30, 2020, it could borrow up to $747.6 million under its credit facility and incur up to $500.0 million of junior guaranteed indebtedness and remain in compliance with its financial covenants (as defined in the credit agreement). To the extent actual operating results, realized commodity prices, or uses of cash differ from the Company's assumptions, QEP's liquidity could be adversely affected. Further, we may from time to time seek to retire, amend or restructure some or all of our outstanding debt or debt agreements through cash purchases, exchanges, open market purchases, privately negotiated transactions, tender offers or otherwise. Such transactions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
Credit Facility
In June 2020, QEP entered into the Eighth Amendment to its credit agreement, which, among other things, reduced the aggregate principal amount of commitments to $850.0 million, requires the Company’s material subsidiaries to guarantee the obligations under the credit agreement as well as certain swap obligations and modified the leverage ratio and present value financial covenants, such that they only pertain to net priority guaranteed debt (primarily consisting of borrowings under the credit facility and letters of credit). The amended credit agreement also provides the ability to use up to $500.0 million of loan proceeds to repurchase outstanding senior notes, provides the ability to issue subsidiary guarantees of up to $500.0 million of unsecured debt, with such guarantees being subordinated to the obligations under the credit agreement, and may limit the Company’s ability to make certain restricted payments, including dividends. The amended credit agreement, which matures on September 1, 2022, provides for borrowings at short-term interest rates and contains customary covenants and restrictions and 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 minimum liquidity amount of at least $100.0 million (ii) a net priority guaranteed leverage ratio under which net priority guaranteed debt may not exceed 2.50 times consolidated EBITDAX (as defined in the credit agreement), and (iii) a present value coverage ratio under which the present value of the Company's proved reserves must exceed net priority guaranteed debt by at least 1.50 times. At September 30, 2020 and December 31, 2019, QEP was in compliance with the covenants under its credit agreement. The Company recorded a $1.5 million loss associated with the write-off of non-cash deferred financing costs as part of amending the credit facility and recorded the loss within "Gain (loss) from early extinguishment of debt" on the statements of operations.
During the nine months ended September 30, 2020, QEP's weighted average interest rate on borrowings under its credit facility was 2.60%. As of September 30, 2020, QEP had no borrowings outstanding and $11.9 million in letters of credit outstanding under the credit facility. As of October 21, 2020, QEP had no borrowings outstanding and had $13.1 million in letters of credit outstanding under the credit facility and was in compliance with the covenants under the credit agreement.
Senior Notes
The Company's senior notes outstanding as of September 30, 2020 totaled a principal amount of $1,601.9 million and are comprised of three issuances as follows:
•$465.1 million 5.375% Senior Notes due October 2022;
•$636.8 million 5.25% Senior Notes due May 2023; and
•$500.0 million 5.625% Senior Notes due March 2026.
During the nine months ended September 30, 2020, QEP repurchased, at a discount, $107.1 million in principal amount of its 6.875% Senior Notes due March 1, 2021, $34.9 million in principal amount of its 5.375% Senior Notes due October 1, 2022, and $13.2 million in principal amount of its 5.25% Senior Notes due May 1, 2023, resulting in a $27.1 million gain from early extinguishment of debt. In addition, during the third quarter of 2020, QEP redeemed the remaining $275.3 million in principal amount of its 6.875% Senior Notes due March 1, 2021, resulting in a loss on early extinguishment of debt of $7.4 million. In total, during the nine months ended September 30, 2020, the Company recorded a $19.7 million net gain in "Gain (loss) from early extinguishment of debt" on the statements of operations related to the repurchase and redemption of senior notes.
Cash Flow from Operating Activities
Cash flows from operating activities are primarily affected by oil and condensate, gas and NGL production volumes and commodity prices (including the effects of settlements of the Company's derivative contracts) and by changes in working capital. QEP typically enters into commodity derivative transactions covering a substantial, but varying, portion of its anticipated future oil and gas production for the next 12 to 24 months.
Net cash provided by (used in) operating activities is presented below:
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|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
2020
|
|
2019
|
|
Change
|
|
|
(in millions)
|
|
Net income (loss)
|
$
|
133.8
|
|
|
$
|
13.1
|
|
|
$
|
120.7
|
|
|
Non-cash adjustments to net income (loss)
|
496.1
|
|
|
383.2
|
|
|
112.9
|
|
|
Changes in operating assets and liabilities
|
(75.9)
|
|
|
(54.3)
|
|
|
(21.6)
|
|
|
Net cash provided by (used in) operating activities
|
$
|
554.0
|
|
|
$
|
342.0
|
|
|
$
|
212.0
|
|
Net cash provided by operating activities was $554.0 million during the first three quarters of 2020, which included $133.8 million of net income, $496.1 million of non-cash adjustments to net income and $75.9 million in changes in operating assets and liabilities. Non-cash adjustments to net income of $496.1 million primarily included DD&A expense of $424.6 million and deferred income tax of $165.3 million, partially offset by $84.4 million of unrealized gains on derivative contracts and $18.2 million of gains from early extinguishment of debt.
The changes in operating assets and liabilities of $75.9 million primarily resulted from a decrease in accounts payable and accrued expenses of $31.9 million, an increase in other asset balances of $30.2 million, and an increase in income tax receivable of $13.1 million.
Net cash provided by operating activities was $342.0 million during the first three quarters of 2019, which included $13.1 million of net income, $383.2 million of non-cash adjustments to net income and $54.3 million in changes in operating assets and liabilities. Non-cash adjustments to net income of $383.2 million primarily included DD&A expense of $395.5 million, $29.0 million of unrealized losses on derivative contracts, and $16.2 million of non-cash share-based compensation expense, partially offset by $61.2 million of deferred income tax benefit.
The decrease in changes in operating assets and liabilities of $54.3 million primarily resulted from decreases in accounts payable and accrued expenses of $55.2 million, other long-term liabilities of $9.8 million and accrued production and property taxes of $6.3 million, partially offset by a decrease in inventory of $10.6 million, decrease in prepaid expenses and other current assets of $2.7 million and an increase in operating leases of $2.7 million.
Cash Flow from Investing Activities
A comparison of capital expenditures for the first three quarters of 2020 and 2019, are presented in the table below:
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|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
2020
|
|
2019
|
|
Change
|
|
|
(in millions)
|
|
Property acquisitions
|
$
|
4.1
|
|
|
$
|
3.6
|
|
|
$
|
0.5
|
|
|
Property, plant and equipment capital expenditures
|
253.5
|
|
|
466.0
|
|
|
(212.5)
|
|
|
Total accrued capital expenditures
|
257.6
|
|
|
469.6
|
|
|
(212.0)
|
|
|
Change in accruals and other non-cash adjustments
|
$
|
31.0
|
|
|
$
|
(0.8)
|
|
|
$
|
31.8
|
|
|
Total cash capital expenditures
|
$
|
288.6
|
|
|
$
|
468.8
|
|
|
$
|
(180.2)
|
|
In the first three quarters of 2020, on an accrual basis, the Company invested $253.5 million on property, plant and equipment capital expenditures (which excludes property acquisitions), a decrease of $212.5 million compared to the first three quarters of 2019. In the first three quarters of 2020, QEP's primary capital expenditures included $178.5 million in the Permian Basin (including midstream infrastructure of $10.0 million, primarily related to oil and gas gathering and water handling) and $71.3 million in the Williston Basin.
In the first three quarters of 2019, on an accrual basis, the Company invested $466.0 million on property, plant and equipment capital expenditures (which excludes property acquisitions). QEP's significant capital expenditures included $396.5 million in the Permian Basin (including midstream infrastructure of $38.9 million, primarily related to oil and gas gathering and water handling), and $70.3 million in the Williston Basin.
The mid-point of our 2020 forecasted capital expenditures (excluding property acquisitions) is $340.0 million. QEP intends to fund capital expenditures (excluding property acquisitions) with cash on hand, cash flow from operating activities and proceeds from our derivative portfolio. The aggregate levels of capital expenditures for 2020 and the allocation of those expenditures are dependent on a variety of factors, including the continued impact on the market due to the COVID-19 pandemic and OPEC actions, oil, gas and NGL prices, industry conditions, changes in management's business assessments as to where QEP's capital can be most profitably deployed, drilling results, the extent to which properties or working interests are acquired or divested and the availability of capital resources to fund the expenditures. Accordingly, the actual levels of capital expenditures and the allocation of those expenditures may vary materially from QEP's estimates.
Cash Flow from Financing Activities
In the first three quarters of 2020, net cash used in financing activities was $434.7 million compared to $455.7 million in the first three quarters of 2019. During the first three quarters of 2020, QEP used $410.3 million of cash to repurchase and redeem senior notes and pay a quarterly dividend of $4.8 million. QEP also had a decrease in checks outstanding in excess of cash balances of $18.3 million.
During the first three quarters of 2019, QEP made repayments on its credit facility of $486.0 million, had borrowings under its credit facility of $56.0 million and paid a quarterly dividend of $4.8 million. In addition, QEP had treasury stock repurchases of $7.0 million related to the settlement of income tax and related benefit withholding obligations arising from the vesting of restricted share grants. During the first three quarters of 2019, QEP had a decrease in checks outstanding in excess of cash balances of $13.9 million.
As of September 30, 2020, the total amount of long-term debt was $1,590.4 million, of which $1,601.9 million was the principal amount of its senior notes and $11.5 million was net original issue discount and unamortized debt issuance costs.
Off-Balance Sheet Arrangements
QEP may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. At September 30, 2020, the Company's material off-balance sheet arrangements included drilling, gathering, processing and firm transportation arrangements and undrawn letters of credit. There are no other off-balance sheet arrangements that have or are reasonably likely to have a current or future material effect on QEP's financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources. For more information regarding off-balance sheet arrangements, we refer you to "Contractual Cash Obligations and Other Commitments" in our 2019 Annual Report on Form 10-K.
Contractual Cash Obligations and Other Commitments
We have various contractual obligations in the normal course of our operations and financing activities. Other than the repayment of $430.5 million in principal amount of our outstanding debt described above, there have been no material changes to our contractual obligations from those disclosed in our 2019 Annual Report on Form 10-K.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
QEP's primary market risks arise from changes in the market price for oil, gas and NGL and volatility in interest rates. These risks can affect revenues and cash flows from operating, investing and financing activities. Commodity prices have historically been volatile and are subject to wide fluctuations in response to relatively minor changes in supply and demand. If commodity prices fluctuate significantly, revenues and cash flow may significantly decrease or increase. In addition, additional non-cash impairment expense of the Company's oil and gas properties may be required if future oil and gas commodity prices experience a significant decline. Furthermore, the Company's revolving credit facility has a floating interest rate, which exposes QEP to interest rate risk if QEP has borrowings outstanding. To partially manage the Company's exposure to these risks, QEP enters into commodity derivative contracts in the form of fixed-price and basis swaps and collars to manage commodity price risk and periodically enters into interest rate swaps to manage interest rate risk.
Commodity Price Risk Management
QEP uses commodity derivative instruments in the normal course of business to reduce the risk of adverse commodity price movements. However, these arrangements typically limit future gains from favorable price movements. The types of commodity derivative instruments currently utilized by the Company are fixed-price and basis swaps and collars. The volume of commodity derivative instruments utilized by the Company may vary from year to year based on QEP's forecasted production. The Company's current derivative instruments do not have margin requirements or collateral provisions that would require payments prior to the scheduled cash settlement dates. As of September 30, 2020, QEP held commodity price derivative contracts, excluding basis swaps, totaling 14.7 million barrels of oil and 33.8 million MMBtu of gas. As of December 31, 2019, QEP held commodity price derivative contracts, excluding basis swaps, totaling 17.5 million barrels of oil and no commodity price gas derivatives.
The following tables present QEP's volumes and average prices for its derivative positions as of October 21, 2020. Refer to Note 7 – Derivative Contracts in Part 1, Item 1 of this Quarterly Report on Form 10-Q for open derivative positions as of September 30, 2020.
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Production Commodity Derivative Swaps
|
|
Year
|
|
Index
|
|
Total Volumes
|
|
Average Swap Price per Unit
|
|
|
|
|
|
(in millions)
|
|
|
|
Oil sales
|
|
|
|
(bbls)
|
|
($/bbl)
|
|
2020
|
|
NYMEX WTI
|
|
3.9
|
|
|
$
|
57.60
|
|
|
2020
|
|
Argus WTI Midland
|
|
0.4
|
|
|
$
|
57.30
|
|
|
2021 (January - June)
|
|
NYMEX WTI
|
|
5.2
|
|
|
$
|
44.70
|
|
|
2021 (July - December)
|
|
NYMEX WTI
|
|
5.2
|
|
|
$
|
42.24
|
|
|
Gas sales
|
|
|
|
(MMbtu)
|
|
($/MMbtu)
|
|
2020
|
|
IF Waha
|
|
3.7
|
|
|
$
|
0.97
|
|
|
2020
|
|
NYMEX HH
|
|
2.8
|
|
|
$
|
2.20
|
|
|
2021
|
|
IF Waha
|
|
18.2
|
|
|
$
|
1.92
|
|
|
2021
|
|
NYMEX HH
|
|
9.1
|
|
|
$
|
2.44
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Commodity Derivative Basis Swaps
|
|
Year
|
|
Index
|
|
Basis
|
|
Total Volumes
|
|
Weighted-Average Differential
|
|
|
|
|
|
|
|
(in millions)
|
|
|
|
Oil sales
|
|
|
|
|
|
(bbls)
|
|
($/bbl)
|
|
2020
|
|
NYMEX WTI
|
|
Argus WTI Midland
|
|
1.8
|
|
|
$
|
0.22
|
|
|
2021
|
|
NYMEX WTI
|
|
Argus WTI Midland
|
|
4.4
|
|
|
$
|
0.99
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Commodity Derivative Oil Costless Collars
|
|
Year
|
|
Index
|
|
Total Volumes
|
|
Average Price Floor
|
|
Average Price Ceiling
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
|
|
|
|
(bbls)
|
|
($/bbl)
|
|
($/bbl)
|
|
2021
|
|
NYMEX WTI
|
|
0.4
|
|
|
$
|
40.00
|
|
|
$
|
49.20
|
|
Changes in the fair value of derivative contracts from December 31, 2019 to September 30, 2020, are presented below:
|
|
|
|
|
|
|
|
|
Commodity derivative contracts
|
|
|
(in millions)
|
|
Net fair value of oil and gas derivative contracts outstanding at December 31, 2019
|
$
|
(17.5)
|
|
|
Contracts settled
|
(232.6)
|
|
|
Change in oil and gas prices on futures markets
|
342.0
|
|
|
Contracts added
|
(25.0)
|
|
|
Net fair value of oil derivative contracts outstanding at September 30, 2020
|
$
|
66.9
|
|
The following table shows the sensitivity of the fair value of oil derivative contracts to changes in the market price of oil and basis differentials:
|
|
|
|
|
|
|
|
|
September 30, 2020
|
|
|
(in millions)
|
|
Net fair value – asset (liability)
|
$
|
66.9
|
|
|
Fair value if market prices of oil and basis differentials decline by 10%
|
$
|
72.9
|
|
|
Fair value if market prices of oil and basis differentials increase by 10%
|
$
|
59.6
|
|
Utilizing the actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these instruments by $7.3 million, while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by $6.0 million as of September 30, 2020. However, a gain or loss eventually would be offset by the actual sales value of the physical production covered by the derivative instruments. For additional information regarding the Company's commodity derivative transactions, refer to Note 7 – Derivative Contracts in Part I, Item 1 of this Quarterly Report on Form 10-Q.
Interest Rate Risk Management
The Company's revolving credit facility has a floating interest rate, which exposes QEP to interest rate risk if QEP has borrowings outstanding. At September 30, 2020, the Company had no borrowings outstanding under its revolving credit facility.
The $1,601.9 million of debt outstanding as of September 30, 2020 relates to senior notes with fixed interest rates; therefore, it is not affected by interest rate movements. For additional information regarding the Company's debt instruments, refer to Note 10 – Debt, in Item I of Part I of this Quarterly Report on Form 10-Q.
Forward-Looking Statements
The quarterly report contains information that includes or is based upon "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements give expectations or forecasts of future events. You can identify these statements by the fact that they do not relate strictly to historical or current facts. We use words such as "anticipate," "estimate," "expect," "project," "intend," "plan," "believe," and other words and terms of similar meaning in connection with a discussion of future operating or financial performance. Forward-looking statements include statements relating to, among other things:
•our strategic objectives;
•expectation to generate free cash flow and focus on reduction of operating costs, drilling costs and general and administrative expenses;
•effect of the COVID-19 pandemic on our business results;
•forecasted 2020 oil production;
•the belief that the Company will be able to maintain positive cash flow and protect its balance sheet, with the ultimate goal of protecting shareholder returns over the long term;
•expectation of proved undeveloped (PUD) reserve conversion rate and total PUD reserves;
•the coverage and amounts of insurance are consistent with industry practice;
•drilling and completion plans and strategies;
•evaluation and potential acquisition of properties in our operating areas to add additional development opportunities and facilitate the drilling of long lateral wells;
•expectations and assumptions regarding oil, gas and NGL prices, and the effects of those prices on our business;
•volatility of oil, gas and NGL prices and factors impacting such prices;
•beliefs about the reduction of global spending on new oil and gas projects and a corresponding reduction in the global oil supply;
•expectations regarding the impact of the agreement among OPEC and other oil producing countries on oil prices;
•factors impacting our ability to transport oil and condensate and gas;
•consequences of QEP’s financial commitments, including limiting QEP's ability to fund future working capital and capital expenditures, to engage in future acquisitions or development activities, to pay dividends, to repurchase shares of its common stock, or to otherwise realize the value of its assets and opportunities fully;
•the adjustments made to GAAP Measures to arrive at non-GAAP measures and the usefulness of non-GAAP financial measures;
•our inventory of drilling locations and the ability of that inventory to provide a solid base for generating free cash flow and capital efficiency;
•our balance sheet and sufficient liquidity providing for the ability to ensure financial flexibility, withstand commodity price volatility and fund our development projects, operations and capital expenditures and return capital to shareholders;
•our ability to fund maturities of senior notes;
•future availability under our revolving credit facility or continued compliance with restrictive financial covenants;
•adjustments to our capital investment program based on a variety of factors, including an evaluation of drilling and completion activities and drilling results;
•amount and allocation of forecasted capital expenditures (excluding property acquisitions) and, plans and sources for funding operations and capital investments;
•impact of lower or higher commodity prices and interest rates;
•potential for asset impairments and factors impacting impairment amounts;
•fair value estimates and related assumptions and assessment of the sensitivity of changes in assumptions, and critical accounting estimates, including estimated asset retirement obligations;
•impact of global geopolitical and macroeconomic events and the monitoring of such events;
•plans regarding derivative contracts, including the volumes utilized, and the anticipated benefits derived there-from;
•outcome and impact of various claims;
•expected cost savings and other efficiencies from multi-well pad drilling, including "tank-style" development;
•delays in completion of wells, well shut-ins and volatility to operating results caused by multi-well pad drilling;
•value of pension plan assets and our plans regarding additional contributions to our Pension Plan, nonqualified retirement plan (SERP) and Medical Plan;
•estimates of the amount of additional indebtedness we may incur under our revolving credit facility;
•off-balance sheet arrangements;
•potential retirement of debt through various options, including exchanges, open market purchases, tender offers and privately negotiated transactions;
•factors impacting our ability to borrow and the interest rates offered;
•assumptions regarding share-based compensation;
•settlement of performance share units and restricted share units in cash;
•plans to restart completion operations in the Permian Basin during the fourth quarter of 2020; and
•plans to use the proceeds from any additional sales of assets to fund on-going operations, reduce debt and for general corporate purposes.
Any or all forward-looking statements may turn out to be incorrect. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. These statements are based on current expectations and the current economic environment. They involve a number of risks and uncertainties that are difficult to predict. These statements are not guarantees of future performance. Actual results could differ materially from those expressed or implied in the forward-looking statements. Factors that could cause actual results to differ materially include, but are not limited to the following:
•the risk factors discussed in Item 1A of Part I of the 2019 Form 10-K and Item 1A of Part II of this Quarterly Report on Form 10-Q;
•changes in oil, gas and NGL prices;
•global geopolitical and macroeconomic factors;
•general economic conditions, including the performance of financial markets and interest rates;
•the length and severity of a pandemic or other health crisis, such as the recent outbreak of COVID-19 and the measures that international, federal, state and local governments, agencies, law enforcement and/or health authorities implement to address it, which may (as with COVID-19) precipitate or exacerbate one or more of the factors herein, reduce the demand for oil, gas and NGLs and significantly disrupt or prevent us from operating our business in the ordinary course for an extended period;
•the risks and liabilities associated with acquired assets;
•asset impairments;
•liquidity constraints, including those resulting from the cost and availability of debt and equity financing;
•drilling and completion strategies, methods and results;
•assumptions around well density/spacing and recoverable reserves per well prove to be inaccurate;
•changes in estimated reserve quantities;
•changes in management's assessments as to where QEP's capital can be most profitably deployed;
•shortages and costs of oilfield equipment, services and personnel;
•changes in development plans;
•lack of available pipeline, processing and refining capacity;
•processing volumes and pipeline throughput;
•risks associated with hydraulic fracturing;
•the outcome of contingencies such as legal proceedings;
•delays in obtaining permits and governmental approvals;
•operating risks such as unexpected drilling conditions and risks inherent in the production of oil and gas;
•weather conditions;
•changes in, adoption of and compliance with laws and regulations, including decisions and policies concerning: the environment, climate change, greenhouse gas or other emissions, renewable energy mandates, natural resources, fish and wildlife, hydraulic fracturing, water use and drilling and completion techniques, as well as the risk of legal proceedings arising from such matters, whether involving public or private claimants or regulatory investigative or enforcement measures;
•derivative activities;
•potential losses or earnings reductions from our commodity price risk management programs;
•volatility in the commodity-futures market;
•failure of internal controls and procedures;
•failure of our information technology infrastructure or applications to prevent a cyberattack;
•the increased exposure to cyber and other operational risks that may result due to many of our employees working remotely for an indefinite time period due to safety concerns related to the COVID-19 pandemic;
•elimination of federal income tax deductions for oil and gas exploration and development costs;
•production, severance and property taxation rates;
•discount rates;
•regulatory approvals and compliance with contractual obligations;
•actions of, or inaction by federal, state, local or tribal governments, foreign countries and the Organization of Petroleum Exporting Countries;
•lack of, or disruptions in, adequate and reliable transportation for our production;
•competitive conditions;
•production and sales volumes;
•actions of operators on properties in which we own an interest but do not operate;
•estimates of oil and gas reserve quantities;
•reservoir performance;
•operating costs;
•inflation;
•capital costs;
•creditworthiness and performance of the Company's counterparties, including financial institutions, operating partners and other parties;
•volatility in the securities, capital and credit markets;
•actions by credit rating agencies and their impact on the Company;
•changes in guidance issued related to tax reform legislation and the CARES Act or application of that guidance; and
•other factors, most of which are beyond the Company's control.
QEP undertakes no obligation to publicly correct or update the forward-looking statements in this Quarterly Report on
Form 10-Q, in other documents, or on the Company's website to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.