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Share Name | Share Symbol | Market | Type |
---|---|---|---|
Qep Resources Inc | NYSE:QEP | NYSE | Common Stock |
Price Change | % Change | Share Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
---|---|---|---|---|---|---|---|---|
0.00 | 0.00% | 4.08 | 0 | 01:00:00 |
ý
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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STATE OF DELAWARE
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87-0287750
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(State or other jurisdiction of
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(I.R.S. Employer
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incorporation or organization)
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Identification No.)
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Large accelerated filer
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ý
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Accelerated filer
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o
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Non-accelerated filer
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o
(Do not check if a smaller reporting company)
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Smaller reporting company
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o
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Emerging growth company
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o
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Page
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ITEM 1.
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ITEM 2.
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ITEM 3.
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ITEM 4.
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ITEM 1.
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ITEM 1A.
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ITEM 2.
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ITEM 3.
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ITEM 4.
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ITEM 5.
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ITEM 6.
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Three Months Ended
|
||||||
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March 31,
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||||||
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2018
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|
2017
|
||||
REVENUES
|
(in millions, except per share amounts)
|
||||||
Oil and condensate, gas and NGL sales
|
$
|
409.8
|
|
|
$
|
385.2
|
|
Other revenue
|
5.0
|
|
|
4.0
|
|
||
Purchased oil and gas sales
|
14.1
|
|
|
30.9
|
|
||
Total Revenues
|
428.9
|
|
|
420.1
|
|
||
OPERATING EXPENSES
|
|
|
|
||||
Purchased oil and gas expense
|
15.5
|
|
|
29.4
|
|
||
Lease operating expense
|
72.5
|
|
|
69.2
|
|
||
Transportation and processing costs
|
34.0
|
|
|
70.2
|
|
||
Gathering and other expense
|
2.8
|
|
|
1.5
|
|
||
General and administrative
|
60.1
|
|
|
33.6
|
|
||
Production and property taxes
|
28.9
|
|
|
29.1
|
|
||
Depreciation, depletion and amortization
|
196.5
|
|
|
191.8
|
|
||
Exploration expenses
|
—
|
|
|
0.4
|
|
||
Impairment
|
0.7
|
|
|
0.1
|
|
||
Total Operating Expenses
|
411.0
|
|
|
425.3
|
|
||
Net gain (loss) from asset sales
|
3.5
|
|
|
—
|
|
||
OPERATING INCOME (LOSS)
|
21.4
|
|
|
(5.2
|
)
|
||
Realized and unrealized gains (losses) on derivative contracts (Note 7)
|
(53.2
|
)
|
|
160.9
|
|
||
Interest and other income (expense)
|
(0.7
|
)
|
|
0.6
|
|
||
Interest expense
|
(35.0
|
)
|
|
(33.8
|
)
|
||
INCOME (LOSS) BEFORE INCOME TAXES
|
(67.5
|
)
|
|
122.5
|
|
||
Income tax (provision) benefit
|
13.9
|
|
|
(45.6
|
)
|
||
NET INCOME (LOSS)
|
$
|
(53.6
|
)
|
|
$
|
76.9
|
|
|
|
|
|
||||
Earnings (loss) per common share
|
|
|
|
||||
Basic
|
$
|
(0.22
|
)
|
|
$
|
0.32
|
|
Diluted
|
$
|
(0.22
|
)
|
|
$
|
0.32
|
|
|
|
|
|
||||
Weighted-average common shares outstanding
|
|
|
|
||||
Used in basic calculation
|
240.9
|
|
|
240.2
|
|
||
Used in diluted calculation
|
240.9
|
|
|
240.3
|
|
||
Dividends per common share
|
$
|
—
|
|
|
$
|
—
|
|
|
Three Months Ended
|
||||||
|
March 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in millions)
|
||||||
Net income (loss)
|
$
|
(53.6
|
)
|
|
$
|
76.9
|
|
Other comprehensive income, net of tax:
|
|
|
|
||||
Postretirement medical plan change
(1)
|
—
|
|
|
1.6
|
|
||
Fair value of plan assets adjustment
(2)
|
0.3
|
|
|
—
|
|
||
Pension and other postretirement plans adjustments:
|
|
|
|
||||
Amortization of prior service costs
(3)
|
0.1
|
|
|
0.1
|
|
||
Amortization of actuarial losses
(4)
|
0.2
|
|
|
0.2
|
|
||
Other comprehensive income
|
0.6
|
|
|
1.9
|
|
||
Comprehensive income (loss)
|
$
|
(53.0
|
)
|
|
$
|
78.8
|
|
(1)
|
Presented net of income tax
expense
of
$1.0 million
for the
three months ended
March 31, 2017
.
|
(2)
|
Adjustment recorded during the
three months ended
March 31, 2018
related to a change in the fair value of plan assets as of
December 31, 2017
.
|
(3)
|
Presented net of income tax
expense
of
$0.1 million
for the
three months ended
March 31, 2017
.
|
(4)
|
Presented net of income tax
expense
of
$0.1 million
for the
three months ended
March 31, 2018
and
2017
, respectively.
|
|
March 31,
2018 |
|
December 31,
2017 |
||||
ASSETS
|
(in millions)
|
||||||
Current Assets
|
|
|
|
||||
Cash and cash equivalents
|
$
|
—
|
|
|
$
|
—
|
|
Accounts receivable, net
|
130.2
|
|
|
142.1
|
|
||
Income tax receivable
|
4.7
|
|
|
4.9
|
|
||
Fair value of derivative contracts
|
3.2
|
|
|
3.4
|
|
||
Hydrocarbon inventories, at lower of average cost or net realizable value
|
2.1
|
|
|
3.6
|
|
||
Prepaid expenses
|
9.4
|
|
|
10.7
|
|
||
Other current assets
|
0.2
|
|
|
0.7
|
|
||
Total Current Assets
|
149.8
|
|
|
165.4
|
|
||
Property, Plant and Equipment (successful efforts method for oil and gas properties)
|
|
|
|
||||
Proved properties
|
12,676.1
|
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|
12,470.9
|
|
||
Unproved properties
|
1,073.7
|
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|
1,095.8
|
|
||
Gathering and other
|
383.4
|
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|
319.7
|
|
||
Materials and supplies
|
38.4
|
|
|
37.8
|
|
||
Total Property, Plant and Equipment
|
14,171.6
|
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|
13,924.2
|
|
||
Less Accumulated Depreciation, Depletion and Amortization
|
|
|
|
||||
Exploration and production
|
6,660.8
|
|
|
6,642.9
|
|
||
Gathering and other
|
130.6
|
|
|
124.3
|
|
||
Total Accumulated Depreciation, Depletion and Amortization
|
6,791.4
|
|
|
6,767.2
|
|
||
Net Property, Plant and Equipment
|
7,380.2
|
|
|
7,157.0
|
|
||
Fair value of derivative contracts
|
4.5
|
|
|
0.1
|
|
||
Other noncurrent assets
|
74.1
|
|
|
72.3
|
|
||
TOTAL ASSETS
|
$
|
7,608.6
|
|
|
$
|
7,394.8
|
|
LIABILITIES AND EQUITY
|
|
|
|
|
|||
Current Liabilities
|
|
|
|
||||
Checks outstanding in excess of cash balances
|
$
|
19.8
|
|
|
$
|
44.0
|
|
Accounts payable and accrued expenses
|
400.9
|
|
|
364.6
|
|
||
Production and property taxes
|
31.9
|
|
|
31.6
|
|
||
Interest payable
|
33.4
|
|
|
26.0
|
|
||
Fair value of derivative contracts
|
116.9
|
|
|
103.6
|
|
||
Asset retirement obligations
|
10.1
|
|
|
7.5
|
|
||
Total Current Liabilities
|
613.0
|
|
|
577.3
|
|
||
Long-term debt
|
2,458.1
|
|
|
2,160.8
|
|
||
Deferred income taxes
|
504.0
|
|
|
518.0
|
|
||
Asset retirement obligations
|
200.4
|
|
|
206.6
|
|
||
Fair value of derivative contracts
|
32.8
|
|
|
31.8
|
|
||
Other long-term liabilities
|
103.6
|
|
|
102.4
|
|
||
Commitments and contingencies (Note 10)
|
|
|
|
|
|
||
EQUITY
|
|
|
|
||||
Common stock – par value $0.01 per share; 500.0 million shares authorized; 240.3 million and 243.0 million shares issued, respectively
|
2.4
|
|
|
2.4
|
|
||
Treasury stock – 2.6 million and 2.0 million shares, respectively
|
(39.5
|
)
|
|
(34.2
|
)
|
||
Additional paid-in capital
|
1,408.0
|
|
|
1,398.2
|
|
||
Retained earnings
|
2,336.3
|
|
|
2,442.6
|
|
||
Accumulated other comprehensive income (loss)
|
(10.5
|
)
|
|
(11.1
|
)
|
||
Total Common Shareholders' Equity
|
3,696.7
|
|
|
3,797.9
|
|
||
TOTAL LIABILITIES AND EQUITY
|
$
|
7,608.6
|
|
|
$
|
7,394.8
|
|
|
Common Stock
|
|
Treasury Stock
|
|
Additional Paid-in Capital
|
|
Retained Earnings
|
|
Accumulated Other Comprehensive Income(Loss)
|
|
Total
|
||||||||||||||||||
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
|
|
|
||||||||||||||||||
|
(in millions)
|
||||||||||||||||||||||||||||
Balance at December 31, 2017
|
243.0
|
|
|
$
|
2.4
|
|
|
(2.0
|
)
|
|
$
|
(34.2
|
)
|
|
$
|
1,398.2
|
|
|
$
|
2,442.6
|
|
|
$
|
(11.1
|
)
|
|
$
|
3,797.9
|
|
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(53.6
|
)
|
|
—
|
|
|
(53.6
|
)
|
||||||
Common stock repurchased and retired
|
(5.6
|
)
|
|
(0.1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(52.7
|
)
|
|
—
|
|
|
(52.8
|
)
|
||||||
Share-based compensation
|
2.9
|
|
|
0.1
|
|
|
(0.6
|
)
|
|
(5.3
|
)
|
|
9.8
|
|
|
—
|
|
|
—
|
|
|
4.6
|
|
||||||
Change in pension and postretirement liability, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.6
|
|
|
0.6
|
|
||||||
Balance at March 31, 2018
|
240.3
|
|
|
$
|
2.4
|
|
|
(2.6
|
)
|
|
$
|
(39.5
|
)
|
|
$
|
1,408.0
|
|
|
$
|
2,336.3
|
|
|
$
|
(10.5
|
)
|
|
$
|
3,696.7
|
|
(1)
|
Refer to New Accounting Pronouncements in
Note 1 – Basis of Presentation
.
|
|
March 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in millions)
|
||||||
Cash and cash equivalents
|
$
|
—
|
|
|
$
|
338.4
|
|
Restricted cash
(1)
|
24.5
|
|
|
22.1
|
|
||
Total cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows
|
$
|
24.5
|
|
|
$
|
360.5
|
|
(1)
|
As of
March 31, 2018
, the restricted cash balance consisted of
$24.5 million
included within "Other noncurrent assets" on the Condensed Consolidated Balance Sheet. As of
March 31, 2017
, the restricted cash balance consisted of
$20.9 million
included within "Other noncurrent assets" and
$1.2 million
included within "Prepaid expenses" on the Condensed Consolidated Balance Sheet provided within the Quarterly Report on Form 10-Q. QEP's restricted cash is primarily cash deposited into an escrow account related to a title dispute between third parties in the Williston Basin.
|
|
Three Months Ended
|
||||||||||
|
March 31, 2018
|
||||||||||
|
As Reported
|
|
ASC 606 Adjustments
|
|
As Adjusted
(1)
|
||||||
REVENUES
|
(in millions, except per share amounts)
|
||||||||||
Oil and condensate, gas and NGL sales
|
$
|
409.8
|
|
|
$
|
12.7
|
|
|
$
|
422.5
|
|
Other revenue
|
5.0
|
|
|
—
|
|
|
5.0
|
|
|||
Purchased oil and gas sales
|
14.1
|
|
|
—
|
|
|
14.1
|
|
|||
Total Revenues
|
428.9
|
|
|
12.7
|
|
|
441.6
|
|
|||
OPERATING EXPENSES
|
|
|
|
|
|
||||||
Purchased oil and gas expense
|
15.5
|
|
|
—
|
|
|
15.5
|
|
|||
Lease operating expense
|
72.5
|
|
|
—
|
|
|
72.5
|
|
|||
Transportation and processing costs
|
34.0
|
|
|
12.7
|
|
|
46.7
|
|
|||
Gathering and other expense
|
2.8
|
|
|
—
|
|
|
2.8
|
|
|||
General and administrative
|
60.1
|
|
|
—
|
|
|
60.1
|
|
|||
Production and property taxes
|
28.9
|
|
|
—
|
|
|
28.9
|
|
|||
Depreciation, depletion and amortization
|
196.5
|
|
|
—
|
|
|
196.5
|
|
|||
Exploration expenses
|
—
|
|
|
—
|
|
|
—
|
|
|||
Impairment
|
0.7
|
|
|
—
|
|
|
0.7
|
|
|||
Total Operating Expenses
|
411.0
|
|
|
12.7
|
|
|
423.7
|
|
|||
Net gain (loss) from asset sales
|
3.5
|
|
|
—
|
|
|
3.5
|
|
|||
OPERATING INCOME (LOSS)
|
21.4
|
|
|
—
|
|
|
21.4
|
|
|||
Realized and unrealized gains (losses) on derivative contracts (Note 7)
|
(53.2
|
)
|
|
—
|
|
|
(53.2
|
)
|
|||
Interest and other income (expense)
|
(0.7
|
)
|
|
—
|
|
|
(0.7
|
)
|
|||
Interest expense
|
(35.0
|
)
|
|
—
|
|
|
(35.0
|
)
|
|||
INCOME (LOSS) BEFORE INCOME TAXES
|
(67.5
|
)
|
|
—
|
|
|
(67.5
|
)
|
|||
Income tax (provision) benefit
|
13.9
|
|
|
—
|
|
|
13.9
|
|
|||
NET INCOME (LOSS)
|
$
|
(53.6
|
)
|
|
$
|
—
|
|
|
$
|
(53.6
|
)
|
|
|
|
|
|
|
||||||
Earnings (loss) per common share
|
|
|
|
|
|
||||||
Basic
|
$
|
(0.22
|
)
|
|
$
|
—
|
|
|
$
|
(0.22
|
)
|
Diluted
|
$
|
(0.22
|
)
|
|
$
|
—
|
|
|
$
|
(0.22
|
)
|
|
|
|
|
|
|
||||||
Weighted-average common shares outstanding
|
|
|
|
|
|
||||||
Used in basic calculation
|
240.9
|
|
|
—
|
|
|
240.9
|
|
|||
Used in diluted calculation
|
240.9
|
|
|
—
|
|
|
240.9
|
|
|||
Dividends per common share
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(1)
|
This column excludes the impact of adopting ASC Topic 606 and is consistent with the presentation prior to January 1, 2018.
|
|
Oil and condensate sales
|
|
Gas sales
|
|
NGL sales
|
|
Transportation and processing costs included in revenue
|
|
Oil and condensate, gas and NGL sales, as presented
|
||||||||||
|
(in millions)
|
||||||||||||||||||
|
Three Months Ended March 31, 2018
|
||||||||||||||||||
Northern Region
|
|
|
|
|
|
|
|
|
|
||||||||||
Williston Basin
|
$
|
160.5
|
|
|
$
|
9.8
|
|
|
$
|
11.8
|
|
|
$
|
(9.9
|
)
|
|
$
|
172.2
|
|
Uinta Basin
|
8.4
|
|
|
10.1
|
|
|
1.7
|
|
|
—
|
|
|
20.2
|
|
|||||
Other Northern
|
1.9
|
|
|
1.0
|
|
|
(0.2
|
)
|
|
—
|
|
|
2.7
|
|
|||||
Southern Region
|
|
|
|
|
|
|
|
|
|
||||||||||
Permian Basin
|
129.8
|
|
|
4.6
|
|
|
6.5
|
|
|
(2.8
|
)
|
|
138.1
|
|
|||||
Haynesville/Cotton Valley
|
0.4
|
|
|
76.4
|
|
|
—
|
|
|
—
|
|
|
76.8
|
|
|||||
Other Southern
|
(0.3
|
)
|
|
0.1
|
|
|
—
|
|
|
—
|
|
|
(0.2
|
)
|
|||||
Total oil and condensate, gas and NGL sales
|
$
|
300.7
|
|
|
$
|
102.0
|
|
|
$
|
19.8
|
|
|
$
|
(12.7
|
)
|
|
$
|
409.8
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Three Months Ended March 31, 2017
(1)
|
||||||||||||||||||
Northern Region
|
|
||||||||||||||||||
Williston Basin
|
$
|
155.4
|
|
|
$
|
12.0
|
|
|
$
|
12.5
|
|
|
$
|
—
|
|
|
$
|
179.9
|
|
Pinedale
|
6.8
|
|
|
60.6
|
|
|
11.6
|
|
|
—
|
|
|
79.0
|
|
|||||
Uinta Basin
|
7.4
|
|
|
14.6
|
|
|
1.6
|
|
|
—
|
|
|
23.6
|
|
|||||
Other Northern
|
1.4
|
|
|
5.9
|
|
|
0.1
|
|
|
—
|
|
|
7.4
|
|
|||||
Southern Region
|
|
|
|
|
|
|
|
|
|
||||||||||
Permian Basin
|
50.2
|
|
|
3.2
|
|
|
3.1
|
|
|
—
|
|
|
56.5
|
|
|||||
Haynesville/Cotton Valley
|
0.4
|
|
|
38.2
|
|
|
0.1
|
|
|
—
|
|
|
38.7
|
|
|||||
Other Southern
|
0.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.1
|
|
|||||
Total oil and condensate, gas and NGL sales
|
$
|
221.7
|
|
|
$
|
134.5
|
|
|
$
|
29.0
|
|
|
$
|
—
|
|
|
$
|
385.2
|
|
(1)
|
Prior period amounts have not been adjusted under the modified retrospective method.
|
|
Three Months Ended
|
||||
|
March 31,
|
||||
|
2018
|
|
2017
|
||
|
(in millions)
|
||||
Weighted-average basic common shares outstanding
|
240.9
|
|
|
240.2
|
|
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan
|
—
|
|
|
0.1
|
|
Average diluted common shares outstanding
|
240.9
|
|
|
240.3
|
|
|
Asset Retirement Obligations
|
||
|
2018
|
||
|
(in millions)
|
||
ARO liability at January 1,
|
$
|
214.1
|
|
Accretion
|
1.7
|
|
|
Additions
|
1.5
|
|
|
Revisions
|
(3.4
|
)
|
|
Liabilities related to assets sold
|
(3.4
|
)
|
|
ARO liability at March 31,
|
$
|
210.5
|
|
|
Fair Value Measurements
|
||||||||||||||||||
|
Gross Amounts of Assets and Liabilities
|
|
Netting Adjustments
(1)
|
|
Net Amounts Presented on the Condensed Consolidated Balance Sheets
|
||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
||||||||||||
|
March 31, 2018
|
||||||||||||||||||
Financial Assets
|
(in millions)
|
||||||||||||||||||
Fair value of derivative contracts – short-term
|
$
|
—
|
|
|
$
|
16.3
|
|
|
$
|
—
|
|
|
$
|
(13.1
|
)
|
|
$
|
3.2
|
|
Fair value of derivative contracts – long-term
|
—
|
|
|
8.1
|
|
|
—
|
|
|
(3.6
|
)
|
|
4.5
|
|
|||||
Total financial assets
|
$
|
—
|
|
|
$
|
24.4
|
|
|
$
|
—
|
|
|
$
|
(16.7
|
)
|
|
$
|
7.7
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
||||||||||
Fair value of derivative contracts – short-term
|
$
|
—
|
|
|
$
|
130.0
|
|
|
$
|
—
|
|
|
$
|
(13.1
|
)
|
|
$
|
116.9
|
|
Fair value of derivative contracts – long-term
|
—
|
|
|
36.4
|
|
|
—
|
|
|
(3.6
|
)
|
|
32.8
|
|
|||||
Total financial liabilities
|
$
|
—
|
|
|
$
|
166.4
|
|
|
$
|
—
|
|
|
$
|
(16.7
|
)
|
|
$
|
149.7
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
December 31, 2017
|
||||||||||||||||||
Financial Assets
|
|
|
|
|
|
|
|
|
|
||||||||||
Fair value of derivative contracts – short-term
|
$
|
—
|
|
|
$
|
20.6
|
|
|
$
|
—
|
|
|
$
|
(17.2
|
)
|
|
$
|
3.4
|
|
Fair value of derivative contracts – long-term
|
—
|
|
|
2.3
|
|
|
—
|
|
|
(2.2
|
)
|
|
0.1
|
|
|||||
Total financial assets
|
$
|
—
|
|
|
$
|
22.9
|
|
|
$
|
—
|
|
|
$
|
(19.4
|
)
|
|
$
|
3.5
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
||||||||||
Fair value of derivative contracts – short-term
|
$
|
—
|
|
|
$
|
120.8
|
|
|
$
|
—
|
|
|
$
|
(17.2
|
)
|
|
$
|
103.6
|
|
Fair value of derivative contracts – long-term
|
—
|
|
|
34.0
|
|
|
—
|
|
|
(2.2
|
)
|
|
31.8
|
|
|||||
Total financial liabilities
|
$
|
—
|
|
|
$
|
154.8
|
|
|
$
|
—
|
|
|
$
|
(19.4
|
)
|
|
$
|
135.4
|
|
(1)
|
The Company nets its derivative contract assets and liabilities outstanding with the same counterparty on the Condensed Consolidated Balance Sheets, for the contracts that contain netting provisions. Refer to
Note 7 – Derivative Contracts
for additional information regarding the Company's derivative contracts.
|
|
Carrying Amount
|
|
Level 1 Fair Value
|
|
Carrying Amount
|
|
Level 1 Fair Value
|
||||||||
|
March 31, 2018
|
|
December 31, 2017
|
||||||||||||
Financial Assets
|
(in millions)
|
||||||||||||||
Cash and cash equivalents
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Financial Liabilities
|
|
|
|
|
|
|
|
||||||||
Checks outstanding in excess of cash balances
|
$
|
19.8
|
|
|
$
|
19.8
|
|
|
$
|
44.0
|
|
|
$
|
44.0
|
|
Long-term debt
|
$
|
2,458.1
|
|
|
$
|
2,456.7
|
|
|
$
|
2,160.8
|
|
|
$
|
2,256.2
|
|
Year
|
|
Index
|
|
Total Volumes
|
|
Average Swap Price per Unit
|
|||
|
|
|
|
(in millions)
|
|
|
|||
Oil sales
|
|
|
|
(bbls)
|
|
|
($/bbl)
|
|
|
2018 (April through December)
|
|
NYMEX WTI
|
|
12.7
|
|
|
$
|
52.48
|
|
2019
|
|
NYMEX WTI
|
|
9.5
|
|
|
$
|
52.66
|
|
Gas sales
|
|
|
|
(MMBtu)
|
|
|
($/MMBtu)
|
|
|
2018 (April through December)
|
|
NYMEX HH
|
|
82.5
|
|
|
$
|
2.99
|
|
2018 (July through December)
|
|
NYMEX HH
|
|
1.8
|
|
|
$
|
3.01
|
|
2019
|
|
NYMEX HH
|
|
43.8
|
|
|
$
|
2.86
|
|
Year
|
|
Index Less Differential
|
|
Index
|
|
Total Volumes
|
|
Weighted-Average Differential
|
|||
|
|
|
|
|
|
(in millions)
|
|
|
|||
Oil sales
|
|
|
|
|
|
(bbls)
|
|
|
($/bbl)
|
|
|
2018 (April through December)
|
|
NYMEX WTI
|
|
Argus WTI Midland
|
|
5.5
|
|
|
$
|
(1.06
|
)
|
2018 (July through December)
|
|
NYMEX WTI
|
|
Argus WTI Midland
|
|
0.9
|
|
|
$
|
(0.71
|
)
|
2019
|
|
NYMEX WTI
|
|
Argus WTI Midland
|
|
4.7
|
|
|
$
|
(0.77
|
)
|
Gas sales
|
|
|
|
|
|
(MMBtu)
|
|
|
($/MMBtu)
|
|
|
2018 (April through December)
|
|
NYMEX HH
|
|
IFNPCR
|
|
5.5
|
|
|
$
|
(0.16
|
)
|
|
Three Months Ended
|
||||||
Derivative contracts not designated as cash flow hedges
|
March 31,
|
||||||
2018
|
|
2017
|
|||||
Realized gains (losses) on commodity derivative contracts
|
(in millions)
|
||||||
Production
|
|
|
|
||||
Oil derivative contracts
|
$
|
(44.3
|
)
|
|
$
|
(2.0
|
)
|
Gas derivative contracts
|
0.9
|
|
|
(14.2
|
)
|
||
Gas Storage
|
|
|
|
||||
Gas derivative contracts
|
0.2
|
|
|
(0.2
|
)
|
||
Realized gains (losses) on commodity derivative contracts
|
(43.2
|
)
|
|
(16.4
|
)
|
||
Unrealized gains (losses) on commodity derivative contracts
|
|
|
|
||||
Production
|
|
|
|
||||
Oil derivative contracts
|
(6.9
|
)
|
|
104.3
|
|
||
Gas derivative contracts
|
(2.8
|
)
|
|
71.1
|
|
||
Gas Storage
|
|
|
|
||||
Gas derivative contracts
|
(0.3
|
)
|
|
1.9
|
|
||
Unrealized gains (losses) on commodity derivative contracts
|
(10.0
|
)
|
|
177.3
|
|
||
Total realized and unrealized gains (losses) on commodity derivative contracts
|
$
|
(53.2
|
)
|
|
$
|
160.9
|
|
|
March 31,
2018 |
|
December 31,
2017 |
||||
|
(in millions)
|
||||||
Revolving Credit Facility due 2022
|
$
|
385.0
|
|
|
$
|
89.0
|
|
6.80% Senior Notes due 2020
|
51.7
|
|
|
51.7
|
|
||
6.875% Senior Notes due 2021
|
397.6
|
|
|
397.6
|
|
||
5.375% Senior Notes due 2022
|
500.0
|
|
|
500.0
|
|
||
5.25% Senior Notes due 2023
|
650.0
|
|
|
650.0
|
|
||
5.625% Senior Notes due 2026
|
500.0
|
|
|
500.0
|
|
||
Less: unamortized discount and unamortized debt issuance costs
|
(26.2
|
)
|
|
(27.5
|
)
|
||
Total long-term debt outstanding
|
$
|
2,458.1
|
|
|
$
|
2,160.8
|
|
|
Three Months Ended
|
||||||
|
March 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in millions)
|
||||||
Stock options
|
$
|
0.5
|
|
|
$
|
0.6
|
|
Restricted share awards
|
8.8
|
|
|
7.3
|
|
||
Performance share units
|
1.9
|
|
|
(1.9
|
)
|
||
Restricted share units
|
—
|
|
|
—
|
|
||
Total share-based compensation expense
|
$
|
11.2
|
|
|
$
|
6.0
|
|
|
Options Outstanding
|
|
Weighted-Average Exercise Price
|
|
Weighted-Average Remaining Contractual Term
|
|
Aggregate Intrinsic Value
|
|||||
|
|
|
(per share)
|
|
(in years)
|
|
(in millions)
|
|||||
Outstanding at December 31, 2017
|
2,354,277
|
|
|
$
|
23.62
|
|
|
|
|
|
||
Canceled
|
(202,235
|
)
|
|
39.07
|
|
|
|
|
|
|||
Outstanding at March 31, 2018
|
2,152,042
|
|
|
$
|
22.17
|
|
|
3.56
|
|
$
|
—
|
|
Options Exercisable at March 31, 2018
|
1,743,963
|
|
|
$
|
23.96
|
|
|
3.10
|
|
$
|
—
|
|
Unvested Options at March 31, 2018
|
408,079
|
|
|
$
|
14.51
|
|
|
5.56
|
|
$
|
—
|
|
|
Restricted Share Awards Outstanding
|
|
Weighted-Average Grant Date Fair Value
|
|||
|
|
|
(per share)
|
|||
Unvested balance at December 31, 2017
|
3,721,334
|
|
|
$
|
13.23
|
|
Granted
|
2,929,369
|
|
|
9.55
|
|
|
Vested
|
(1,414,155
|
)
|
|
14.83
|
|
|
Forfeited
|
(86,386
|
)
|
|
11.31
|
|
|
Unvested balance at March 31, 2018
|
5,150,162
|
|
|
$
|
10.73
|
|
|
Performance Share Units Outstanding
|
|
Weighted-Average Grant Date Fair Value
|
|||
|
|
|
(per share)
|
|||
Unvested balance at December 31, 2017
|
1,199,336
|
|
|
$
|
14.59
|
|
Granted
|
724,095
|
|
|
9.55
|
|
|
Vested and Paid
|
(229,620
|
)
|
|
21.69
|
|
|
Unvested balance at March 31, 2018
|
1,693,811
|
|
|
$
|
11.47
|
|
|
Restricted Share Units Outstanding
|
|
Weighted-Average Grant Date Fair Value
|
|||
|
|
|
(per share)
|
|||
Unvested balance at December 31, 2017
|
21,946
|
|
|
$
|
13.22
|
|
Granted
|
31,835
|
|
|
9.55
|
|
|
Vested
|
(9,320
|
)
|
|
12.56
|
|
|
Unvested balance at March 31, 2018
|
44,461
|
|
|
$
|
10.73
|
|
|
Three Months Ended
|
||||||
|
March 31,
|
||||||
|
2018
|
|
2017
|
||||
Pension Plan and SERP benefits
|
(in millions)
|
||||||
Service cost
|
$
|
0.2
|
|
|
$
|
0.3
|
|
Interest cost
|
1.1
|
|
|
1.2
|
|
||
Expected return on plan assets
|
(1.4
|
)
|
|
(1.3
|
)
|
||
Amortization of prior service costs
(1)
|
0.2
|
|
|
0.3
|
|
||
Amortization of actuarial losses
(1)
|
0.3
|
|
|
0.3
|
|
||
Periodic expense
|
$
|
0.4
|
|
|
$
|
0.8
|
|
|
|
|
|
||||
Medical Plan benefits
|
|
|
|
||||
Amortization of prior service costs
(1)
|
(0.1
|
)
|
|
(0.1
|
)
|
||
Periodic expense
|
$
|
(0.1
|
)
|
|
$
|
(0.1
|
)
|
(1)
|
Amortization of prior service costs and actuarial losses out of accumulated other comprehensive income are recognized on the Condensed Consolidated Statements of Operations within "Interest and other income (expense)".
|
•
|
Delivered oil and condensate production of
5.0
MMbbls, including a record
2.2
MMbbls in the Permian Basin;
|
•
|
Increased gas production in Haynesville/Cotton Valley to
25.7
Bcf, a
111%
increase
over
2017
volumes, primarily due to a successful refracturing program and initiation of a drilling program;
|
•
|
Reported realized oil prices of
$51.54
per bbl, a
10%
increase
over
2017
, realized gas prices of
$2.94
per Mcf, a
4%
increase
over
2017
and realized NGL prices of
$21.99
per bbl, a
3%
increase
over
2017
;
|
•
|
Repurchased and retired
5.6 million
shares of the Company's outstanding shares of common stock for
$52.8 million
;
|
•
|
Generated a net
loss
of
$53.6 million
, or
$0.22
per diluted share; and
|
•
|
Reported Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of
$171.9 million
, a
1%
increase
over
2017
.
|
|
|
|
Operated
|
|
Non-operated
|
|||||||||||||||||||||
|
Drilling
|
|
Drilling
|
|
Waiting on completion
|
|
Drilling
|
|
Waiting on completion
|
|||||||||||||||||
|
Rigs
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|||||||||
Northern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Williston Basin
|
1
|
|
|
1
|
|
|
0.5
|
|
|
10
|
|
|
9.6
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|
0.1
|
|
Uinta Basin
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Other Northern
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Southern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Permian Basin
(1)
|
6
|
|
|
20
|
|
|
19.6
|
|
|
38
|
|
|
37.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Haynesville/Cotton Valley
|
1
|
|
|
2
|
|
|
2.0
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
0.2
|
|
|
12
|
|
|
0.4
|
|
Other Southern
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
(1)
|
The gross operated drilling well count in the Permian Basin includes nine wells for which surface casing has been set, but as of
March 31, 2018
, did not have a rig drilling.
|
|
Operated Put on Production
|
|
Non-operated Put on Production
|
||||||||
|
Three Months Ended
|
|
Three Months Ended
|
||||||||
|
March 31, 2018
|
|
March 31, 2018
|
||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||
Northern Region
|
|
|
|
|
|
|
|
||||
Williston Basin
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Uinta Basin
|
2
|
|
|
2.0
|
|
|
—
|
|
|
—
|
|
Other Northern
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Southern Region
|
|
|
|
|
|
|
|
||||
Permian Basin
|
31
|
|
|
31.0
|
|
|
—
|
|
|
—
|
|
Haynesville/Cotton Valley
|
2
|
|
|
2.0
|
|
|
6
|
|
|
0.6
|
|
Other Southern
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Permian Basin
|
|
Williston Basin
|
|
Haynesville/Cotton Valley
|
|
Uinta Basin
|
||||||||||||||||
|
As of March 31, 2018
|
||||||||||||||||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||||
Well Progress
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Drilling
|
20
|
|
|
19.6
|
|
|
1
|
|
|
0.5
|
|
|
2
|
|
|
2.0
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
At total depth - under drilling rig
|
8
|
|
|
7.7
|
|
|
5
|
|
|
5.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Waiting to be completed
|
15
|
|
|
14.4
|
|
|
2
|
|
|
2.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Undergoing completion
|
6
|
|
|
6.0
|
|
|
2
|
|
|
2.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Completed, awaiting production
|
9
|
|
|
9.0
|
|
|
1
|
|
|
1.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Waiting on completion
|
38
|
|
|
37.1
|
|
|
10
|
|
|
10.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Put on production
|
31
|
|
|
31.0
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
2.0
|
|
|
2
|
|
|
2.0
|
|
|
Three Months Ended March 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in millions)
|
||||||
Net income (loss)
|
$
|
(53.6
|
)
|
|
$
|
76.9
|
|
Interest expense
|
35.0
|
|
|
33.8
|
|
||
Interest and other (income) expense
|
0.7
|
|
|
(0.6
|
)
|
||
Income tax provision (benefit)
|
(13.9
|
)
|
|
45.6
|
|
||
Depreciation, depletion and amortization
|
196.5
|
|
|
191.8
|
|
||
Unrealized (gains) losses on derivative contracts
|
10.0
|
|
|
(177.3
|
)
|
||
Exploration expenses
|
—
|
|
|
0.4
|
|
||
Net (gain) loss from asset sales
|
(3.5
|
)
|
|
—
|
|
||
Impairment
|
0.7
|
|
|
0.1
|
|
||
Adjusted EBITDA
|
$
|
171.9
|
|
|
$
|
170.7
|
|
|
Three Months Ended
|
||||||||||
|
March 31,
|
||||||||||
|
2018
|
|
2017
(1)
|
|
Change
|
||||||
|
(in millions)
|
||||||||||
Oil and condensate sales
|
$
|
300.7
|
|
|
$
|
221.7
|
|
|
$
|
79.0
|
|
Gas sales
|
102.0
|
|
|
134.5
|
|
|
(32.5
|
)
|
|||
NGL sales
|
19.8
|
|
|
29.0
|
|
|
(9.2
|
)
|
|||
Oil and condensate, gas and NGL sales, as adjusted
(2)
|
422.5
|
|
|
385.2
|
|
|
37.3
|
|
|||
Transportation and processing costs included in revenue
(3)
|
(12.7
|
)
|
|
—
|
|
|
(12.7
|
)
|
|||
Oil and condensate, gas and NGL sales, as presented
|
$
|
409.8
|
|
|
$
|
385.2
|
|
|
$
|
24.6
|
|
(1)
|
Prior period amounts have not been adjusted under the modified retrospective method for the new revenue recognition rule, refer to
Note 2 – Revenue
in Part 1, Item I of this Quarterly Report on Form 10-Q.
|
(2)
|
Above is a reconciliation of Oil and condensate, gas and NGL sales (a GAAP measure) as presented on the Condensed Consolidated Statements of Operations to Oil and condensate, gas and NGL sales, as adjusted. Oil and condensate, gas and NGL sales, as adjusted excludes transportation and processing costs that are included as part of "Oil and condensate, gas and NGL sales" on the Condensed Consolidated Statements of Operations. Management removes these costs from "Oil and condensate, gas and NGL sales" included on the Condensed Consolidated Statements of Operations 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 and is a more comparable measure to reported revenue of its peers. This non-GAAP measure should be considered by the reader in addition to but not instead of, the financial statements prepared in accordance with GAAP. Refer to
Note 2 – Revenue
in Part 1, Item I of this Quarterly Report on Form 10-Q.
|
(3)
|
Transportation and processing costs in the table above is not representative of total transportation and processing costs incurred. Refer to the Operating Expenses section below for a reconciliation of total transportation and processing costs.
|
|
Oil and condensate
|
|
Gas
|
|
NGL
|
|
Total
|
||||||||
|
(in millions)
|
||||||||||||||
Oil and condensate, gas and NGL sales, as adjusted
|
|
|
|
|
|
|
|
||||||||
Three months ended March 31, 2017
|
$
|
221.7
|
|
|
$
|
134.5
|
|
|
$
|
29.0
|
|
|
$
|
385.2
|
|
Changes associated with volumes
(1)
|
13.8
|
|
|
(22.9
|
)
|
|
(9.7
|
)
|
|
(18.8
|
)
|
||||
Changes associated with prices
(2)
|
65.2
|
|
|
(9.6
|
)
|
|
0.5
|
|
|
56.1
|
|
||||
Three months ended March 31, 2018
|
$
|
300.7
|
|
|
$
|
102.0
|
|
|
$
|
19.8
|
|
|
$
|
422.5
|
|
(1)
|
The revenue variance attributed to the change in volume is calculated by multiplying the change in volume from the
three months ended
March 31, 2018
, as compared to the
three months ended
March 31, 2017
, by the average field-level price for the
three months ended
March 31, 2017
.
|
(2)
|
The revenue variance attributed to the change in price is calculated by multiplying the change in average field-level price from the
three months ended
March 31, 2018
, as compared to the
three months ended
March 31, 2017
, by the respective volumes for the
three months ended
March 31, 2018
. Pricing changes are driven by changes in commodity average field-level prices, excluding the impact from commodity derivatives.
|
|
Three Months Ended March 31,
|
||||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Total production volumes (Mboe)
|
|
|
|
|
|
||||||
Northern Region
|
|
|
|
|
|
||||||
Williston Basin
|
3,729.7
|
|
|
4,834.0
|
|
|
(1,104.3
|
)
|
|||
Pinedale
|
0.1
|
|
|
3,514.9
|
|
|
(3,514.8
|
)
|
|||
Uinta Basin
|
804.5
|
|
|
968.3
|
|
|
(163.8
|
)
|
|||
Other Northern
|
105.4
|
|
|
330.4
|
|
|
(225.0
|
)
|
|||
Southern Region
|
|
|
|
|
|
|
|||||
Permian Basin
|
2,782.9
|
|
|
1,389.5
|
|
|
1,393.4
|
|
|||
Haynesville/Cotton Valley
|
4,290.5
|
|
|
2,046.7
|
|
|
2,243.8
|
|
|||
Other Southern
|
11.5
|
|
|
6.5
|
|
|
5.0
|
|
|||
Total production
|
11,724.6
|
|
|
13,090.3
|
|
|
(1,365.7
|
)
|
|||
|
|
|
|
|
|
||||||
Total equivalent prices (per Boe)
|
|
|
|
|
|
||||||
Average field-level equivalent price
|
$
|
36.04
|
|
|
$
|
29.43
|
|
|
$
|
6.61
|
|
Commodity derivative impact
|
(3.70
|
)
|
|
(1.24
|
)
|
|
(2.46
|
)
|
|||
Net realized equivalent price
|
$
|
32.34
|
|
|
$
|
28.19
|
|
|
$
|
4.15
|
|
|
Three Months Ended March 31,
|
||||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Oil and condensate production volumes (Mbbl)
|
|
|
|
|
|
||||||
Northern Region
|
|
|
|
|
|
||||||
Williston Basin
|
2,612.2
|
|
|
3,336.7
|
|
|
(724.5
|
)
|
|||
Pinedale
|
—
|
|
|
143.0
|
|
|
(143.0
|
)
|
|||
Uinta Basin
|
151.7
|
|
|
166.1
|
|
|
(14.4
|
)
|
|||
Other Northern
|
37.8
|
|
|
26.9
|
|
|
10.9
|
|
|||
Southern Region
|
|
|
|
|
|
||||||
Permian Basin
|
2,159.1
|
|
|
1,001.7
|
|
|
1,157.4
|
|
|||
Haynesville/Cotton Valley
|
5.8
|
|
|
7.2
|
|
|
(1.4
|
)
|
|||
Other Southern
|
7.4
|
|
|
1.1
|
|
|
6.3
|
|
|||
Total production
|
4,974.0
|
|
|
4,682.7
|
|
|
291.3
|
|
|||
Average field-level oil prices (per bbl)
|
|
|
|
|
|
||||||
Northern Region
|
$
|
60.93
|
|
|
$
|
46.58
|
|
|
$
|
14.35
|
|
Southern Region
|
$
|
59.82
|
|
|
$
|
50.14
|
|
|
$
|
9.68
|
|
|
|
|
|
|
|
||||||
Average field-level price
|
$
|
60.45
|
|
|
$
|
47.35
|
|
|
$
|
13.10
|
|
Commodity derivative impact
|
(8.91
|
)
|
|
(0.43
|
)
|
|
(8.48
|
)
|
|||
Net realized price
|
$
|
51.54
|
|
|
$
|
46.92
|
|
|
$
|
4.62
|
|
|
Three Months Ended March 31,
|
||||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Gas production volumes (Bcf)
|
|
|
|
|
|
||||||
Northern Region
|
|
|
|
|
|
||||||
Williston Basin
|
3.4
|
|
|
4.0
|
|
|
(0.6
|
)
|
|||
Pinedale
|
—
|
|
|
18.5
|
|
|
(18.5
|
)
|
|||
Uinta Basin
|
3.7
|
|
|
4.6
|
|
|
(0.9
|
)
|
|||
Other Northern
|
0.4
|
|
|
1.8
|
|
|
(1.4
|
)
|
|||
Southern Region
|
|
|
|
|
|
|
|||||
Permian Basin
|
1.9
|
|
|
1.2
|
|
|
0.7
|
|
|||
Haynesville/Cotton Valley
|
25.7
|
|
|
12.2
|
|
|
13.5
|
|
|||
Other Southern
|
—
|
|
|
—
|
|
|
—
|
|
|||
Total production
|
35.1
|
|
|
42.3
|
|
|
(7.2
|
)
|
|||
Average field-level gas prices (per Mcf)
|
|
|
|
|
|
||||||
Northern Region
|
$
|
2.79
|
|
|
$
|
3.22
|
|
|
$
|
(0.43
|
)
|
Southern Region
|
$
|
2.94
|
|
|
$
|
3.09
|
|
|
$
|
(0.15
|
)
|
|
|
|
|
|
|
||||||
Average field-level price
|
$
|
2.91
|
|
|
$
|
3.18
|
|
|
$
|
(0.27
|
)
|
Commodity derivative impact
|
0.03
|
|
|
(0.34
|
)
|
|
0.37
|
|
|||
Net realized price
|
$
|
2.94
|
|
|
$
|
2.84
|
|
|
$
|
0.10
|
|
|
Three Months Ended March 31,
|
||||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
NGL production volumes (Mbbl)
|
|
|
|
|
|
||||||
Northern Region
|
|
|
|
|
|
||||||
Williston Basin
|
551.4
|
|
|
823.2
|
|
|
(271.8
|
)
|
|||
Pinedale
|
—
|
|
|
292.5
|
|
|
(292.5
|
)
|
|||
Uinta Basin
|
36.3
|
|
|
41.4
|
|
|
(5.1
|
)
|
|||
Other Northern
|
3.3
|
|
|
4.3
|
|
|
(1.0
|
)
|
|||
Southern Region
|
|
|
|
|
|
|
|||||
Permian Basin
|
312.9
|
|
|
187.8
|
|
|
125.1
|
|
|||
Haynesville/Cotton Valley
|
0.1
|
|
|
6.0
|
|
|
(5.9
|
)
|
|||
Other Southern
|
0.4
|
|
|
0.2
|
|
|
0.2
|
|
|||
Total production
|
904.4
|
|
|
1,355.4
|
|
|
(451.0
|
)
|
|||
Average field-level NGL prices (per bbl)
|
|
|
|
|
|
||||||
Northern Region
|
$
|
22.58
|
|
|
$
|
22.13
|
|
|
$
|
0.45
|
|
Southern Region
|
$
|
20.89
|
|
|
$
|
16.78
|
|
|
$
|
4.11
|
|
|
|
|
|
|
|
||||||
Average field-level price
|
$
|
21.99
|
|
|
$
|
21.36
|
|
|
$
|
0.63
|
|
Commodity derivative impact
|
—
|
|
|
—
|
|
|
—
|
|
|||
Net realized price
|
$
|
21.99
|
|
|
$
|
21.36
|
|
|
$
|
0.63
|
|
|
Three Months Ended March 31,
|
||||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
|
(in millions)
|
||||||||||
Purchased oil and gas sales
|
$
|
14.1
|
|
|
$
|
30.9
|
|
|
$
|
(16.8
|
)
|
Purchased oil and gas expense
|
(15.5
|
)
|
|
(29.4
|
)
|
|
13.9
|
|
|||
Realized gains (losses) on gas storage derivative contracts
|
0.2
|
|
|
(0.2
|
)
|
|
0.4
|
|
|||
Resale margin
|
$
|
(1.2
|
)
|
|
$
|
1.3
|
|
|
$
|
(2.5
|
)
|
|
Three Months Ended March 31,
|
||||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
|
(in millions)
|
||||||||||
Lease operating expense
|
$
|
72.5
|
|
|
$
|
69.2
|
|
|
$
|
3.3
|
|
Adjusted transportation and processing costs
(1)
|
46.7
|
|
|
70.2
|
|
|
(23.5
|
)
|
|||
Production and property taxes
|
28.9
|
|
|
29.1
|
|
|
(0.2
|
)
|
|||
Total production costs
|
$
|
148.1
|
|
|
$
|
168.5
|
|
|
$
|
(20.4
|
)
|
|
(per Boe)
|
||||||||||
Lease operating expense
|
$
|
6.18
|
|
|
$
|
5.29
|
|
|
$
|
0.89
|
|
Adjusted transportation and processing costs
(1)
|
3.98
|
|
|
5.36
|
|
|
(1.38
|
)
|
|||
Production and property taxes
|
2.47
|
|
|
2.23
|
|
|
0.24
|
|
|||
Total production costs
|
$
|
12.63
|
|
|
$
|
12.88
|
|
|
$
|
(0.25
|
)
|
(1)
|
Below are reconciliations of transportation and processing costs (a GAAP measure) as presented on the Condensed Consolidated 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 Condensed Consolidated Statements of Operations. Management adds these costs together with transportation and processing costs reflected on the Condensed Consolidated Statements of Operations to reflect the total operating costs associated with its production. Management believes that this non-GAAP measure is useful supplemental information for investors as it is reflective of the total production costs required to operate the wells for the period and is a more comparable measure to the operating costs of its peers. This non-GAAP measure should be considered by the reader in addition to but not instead of, the financial statements prepared in accordance with GAAP. Refer to
Note 2 – Revenue
in Part 1, Item I of this Quarterly Report on Form 10-Q.
|
|
Three Months Ended March 31,
|
||||||||||
|
2018
|
|
2017
(1)
|
|
Change
|
||||||
|
(in millions)
|
||||||||||
Adjusted transportation and processing costs
|
$
|
46.7
|
|
|
$
|
70.2
|
|
|
$
|
(23.5
|
)
|
Transportation and processing costs deducted from oil and condensate, gas and NGL sales
|
(12.7
|
)
|
|
—
|
|
|
(12.7
|
)
|
|||
Transportation and processing costs, as presented
|
$
|
34.0
|
|
|
$
|
70.2
|
|
|
$
|
(36.2
|
)
|
|
(per Boe)
|
||||||||||
Adjusted transportation and processing costs
|
$
|
3.98
|
|
|
$
|
5.36
|
|
|
$
|
(1.38
|
)
|
Transportation and processing costs deducted from oil and condensate, gas and NGL sales
|
(1.08
|
)
|
|
—
|
|
|
(1.08
|
)
|
|||
Transportation and processing costs, as presented
|
$
|
2.90
|
|
|
$
|
5.36
|
|
|
$
|
(2.46
|
)
|
(1)
|
Prior period amounts have not been adjusted under the modified retrospective method for the new revenue recognition rule. Refer to
Note 2 – Revenue
in Part 1, Item 1 of this Quarterly Report on Form 10-Q.
|
•
|
$51.7 million
6.80% Senior Notes due March 2020;
|
•
|
$397.6 million
6.875% Senior Notes due March 2021;
|
•
|
$500.0 million
5.375% Senior Notes due October 2022;
|
•
|
$650.0 million
5.25% Senior Notes due May 2023; and
|
•
|
$500.0 million
5.625% Senior Notes due March 2026.
|
|
Three Months Ended March 31,
|
||||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
|
(in millions)
|
||||||||||
Net income (loss)
|
$
|
(53.6
|
)
|
|
$
|
76.9
|
|
|
$
|
(130.5
|
)
|
Non-cash adjustments to net income (loss)
|
202.2
|
|
|
67.3
|
|
|
134.9
|
|
|||
Changes in operating assets and liabilities
|
11.8
|
|
|
5.7
|
|
|
6.1
|
|
|||
Net cash provided by (used in) operating activities
|
$
|
160.4
|
|
|
$
|
149.9
|
|
|
$
|
10.5
|
|
|
Three Months Ended March 31,
|
||||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
|
(in millions)
|
||||||||||
Property acquisitions
(1)
|
$
|
36.2
|
|
|
$
|
68.2
|
|
|
$
|
(32.0
|
)
|
Property, plant and equipment capital expenditures
|
418.8
|
|
|
214.3
|
|
|
204.5
|
|
|||
Total accrued capital expenditures
|
455.0
|
|
|
282.5
|
|
|
172.5
|
|
|||
Change in accruals and other non-cash adjustments
|
(48.1
|
)
|
|
(37.0
|
)
|
|
(11.1
|
)
|
|||
Total cash capital expenditures
|
$
|
406.9
|
|
|
$
|
245.5
|
|
|
$
|
161.4
|
|
(1)
|
Excludes acquisition deposits held in escrow of
$0.2 million
for the
three months ended
March 31, 2018
.
|
Production Commodity Derivative Swaps
|
|||||||||
Year
|
|
Index
|
|
Total Volumes
|
|
Average Swap Price per Unit
|
|||
|
|
|
|
(in millions)
|
|
|
|||
Oil sales
|
|
|
|
(bbls)
|
|
|
($/bbl)
|
|
|
2018 (April through December)
|
|
NYMEX WTI
|
|
12.7
|
|
|
$
|
52.48
|
|
2019
|
|
NYMEX WTI
|
|
9.5
|
|
|
$
|
52.66
|
|
Gas sales
|
|
|
|
(MMBtu)
|
|
|
($/MMBtu)
|
|
|
2018 (May through December)
|
|
NYMEX HH
|
|
71.7
|
|
|
$
|
3.00
|
|
2018 (July through December)
|
|
NYMEX HH
|
|
1.8
|
|
|
$
|
3.01
|
|
2019
|
|
NYMEX HH
|
|
43.8
|
|
|
$
|
2.86
|
|
Production Commodity Derivative Basis Swaps
|
|||||||||||
Year
|
|
Index Less Differential
|
|
Index
|
|
Total Volumes
|
|
Weighted-Average Differential
|
|||
|
|
|
|
|
|
(in millions)
|
|
|
|||
Oil sales
|
|
|
|
|
|
(bbls)
|
|
|
($/bbl)
|
|
|
2018 (April through December)
|
|
NYMEX WTI
|
|
Argus WTI Midland
|
|
5.5
|
|
|
$
|
(1.06
|
)
|
2018 (July through December)
|
|
NYMEX WTI
|
|
Argus WTI Midland
|
|
0.9
|
|
|
$
|
(0.71
|
)
|
2019
|
|
NYMEX WTI
|
|
Argus WTI Midland
|
|
4.7
|
|
|
$
|
(0.77
|
)
|
Gas sales
|
|
|
|
|
|
(MMBtu)
|
|
|
($/MMBtu)
|
|
|
2018 (May through December)
|
|
NYMEX HH
|
|
IFNPCR
|
|
4.9
|
|
|
$
|
(0.16
|
)
|
|
Commodity derivative contracts
|
||
|
(in millions)
|
||
Net fair value of oil and gas derivative contracts outstanding at December 31, 2017
|
$
|
(131.9
|
)
|
Contracts settled
|
43.2
|
|
|
Change in oil and gas prices on futures markets
|
50.5
|
|
|
Contracts added
|
(103.8
|
)
|
|
Net fair value of oil and gas derivative contracts outstanding at March 31, 2018
|
$
|
(142.0
|
)
|
|
March 31, 2018
|
||
|
(in millions)
|
||
Net fair value – asset (liability)
|
$
|
(142.0
|
)
|
Fair value if market prices of oil, gas and basis differentials decline by 10%
|
$
|
(127.7
|
)
|
Fair value if market prices of oil, gas and basis differentials increase by 10%
|
$
|
(156.1
|
)
|
•
|
focus on returns-focused growth and superior execution and strategies to achieve these objectives;
|
•
|
our Strategic Initiatives to transition to a pure-play Permian Basin company;
|
•
|
plans to grow oil and condensate production;
|
•
|
drilling and completion plans and strategies;
|
•
|
including anticipated benefits of our tank-style completion methodology;
|
•
|
acquiring acreage in the Permian Basin to add development opportunities and facilitate the drilling of long lateral wells;
|
•
|
estimated future payments to reimburse the buyer in the Pinedale Divestiture for certain deficiency charges related to the gas processing and NGL transportation and fractionation contracts;
|
•
|
expectations and assumptions regarding impact of oil, gas and NGL prices;
|
•
|
future development costs and funding for such costs;
|
•
|
factors affecting our decision to modify our development plans;
|
•
|
volatility of oil, gas and NGL prices and factors impacting such prices;
|
•
|
the conditions impacting the timing and amount of share repurchases under our share repurchase program;
|
•
|
the usefulness of non-GAAP financial measures;
|
•
|
our inventory of drilling locations;
|
•
|
aggregate purchase price and source of funding for, and the timing of the closing of, acquisitions of additional oil and gas interests in the Permian Basin pursuant to offers made in the fourth quarter of 2017;
|
•
|
evaluation of potential acquisitions and divestiture opportunities;
|
•
|
plans to market our assets in the Williston Basin, the Uinta Basin and Haynesville/Cotton Valley;
|
•
|
our balance sheet and liquidity position allowing us to grow oil production, provide financial flexibility, withstand commodity price volatility and fund our development projects, operations, capital expenditures and Strategic Initiatives;
|
•
|
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 for funding operations and capital investments;
|
•
|
impact of lower or higher commodity prices and interest rates;
|
•
|
focus on maintaining a sufficient liquidity position to ensure financial flexibility;
|
•
|
potential for asset impairments and factors impacting impairment amounts;
|
•
|
plans to recover or reject ethane from produced natural gas;
|
•
|
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;
|
•
|
estimated amount of potential impairment of proved and unproved property, primarily in the Williston and Uinta basins;
|
•
|
delays in completion of wells, well shut-ins and volatility to operating results caused by multi-well pad drilling;
|
•
|
predictability and success of our drilling operations;
|
•
|
plans and ability to pursue acquisition opportunities;
|
•
|
oil exports from and imports to the U.S.;
|
•
|
sufficiency of our liquidity position to ensure financial flexibility and fund our operations and capital expenditures;
|
•
|
estimates of the amount of additional indebtedness we may incur under our revolving credit facility;
|
•
|
factors adversely affecting our liquidity;
|
•
|
changes in recorded goodwill;
|
•
|
redemption of senior notes;
|
•
|
factors impacting our ability to borrow and the interest rates offered;
|
•
|
loss contingencies;
|
•
|
implementation and impact of new accounting pronouncements;
|
•
|
assumptions regarding share-based compensation;
|
•
|
settlement of performance share units and restricted share units in cash;
|
•
|
recognition of compensation costs related to share-based compensation grants;
|
•
|
expected contributions to our employee benefit plans;
|
•
|
costs associated with employee retention program and contractual termination benefits, including severance and accelerated vesting of share-based compensations; and
|
•
|
use of proceeds from divestiture of assets.
|
•
|
the risk factors discussed in Item 1A of Part I of the
2017
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 risks and liabilities associated with acquired assets;
|
•
|
asset impairments;
|
•
|
timing of and proceeds from asset divestitures;
|
•
|
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, 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;
|
•
|
elimination of federal income tax deductions for oil and gas exploration and development costs;
|
•
|
production, severance and property taxation rates;
|
•
|
tariffs on products we use in our operations on products we sell;
|
•
|
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;
|
•
|
actions of activist shareholders; and
|
•
|
other factors, most of which are beyond the Company's control.
|
Period
|
|
Total shares purchased
(1)(2)
|
|
Weighted-average price paid per share
|
|
Total shares purchased as part of publicly announced plans or programs
|
|
Remaining dollar amount that may be purchased under the plans or programs
|
||||||
|
|
|
|
|
|
|
|
(in millions)
|
||||||
January 1, 2018 - January 31, 2018
|
|
3,869
|
|
|
$
|
10.38
|
|
|
—
|
|
|
$
|
—
|
|
February 1, 2018 - February 28, 2018
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
March 1, 2018 - March 31, 2018
|
|
6,106,918
|
|
|
$
|
9.40
|
|
|
5,621,540
|
|
|
$
|
1,197.2
|
|
Total
|
|
6,110,787
|
|
|
|
|
5,621,540
|
|
|
|
(1)
|
During the
three months ended
March 31, 2018
, QEP purchased
489,247
shares from employees in connection with the settlement of income tax and related benefit withholding obligations arising from the vesting of restricted share grants.
|
(2)
|
During the
three months ended
March 31, 2018
, QEP repurchased and retired
5,621,540
shares under the February 2018
$1.25 billion
Repurchase Program at a weighted average price of
$9.37
per share, excluding commission of
$0.02
per share, for
$52.8 million
. Shares are as of the settlement date. Subsequent to
March 31, 2018
, the Company settled and retired the purchase of
592,310
shares at a weighted average price of
$9.37
, excluding commission of
$0.02
per share, for
$5.6 million
, associated with trades that had been made prior to the end of the quarter.
|
+
|
Indicates a management contract or compensatory plan or arrangement.
|
*
|
Filed herewith
|
**
|
These interactive data files are furnished and deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Act of 1934, as amended, and otherwise are not subject to liability under those sections.
|
|
QEP RESOURCES, INC.
|
|
(Registrant)
|
|
|
April 25, 2018
|
/s/ Charles B. Stanley
|
|
Charles B. Stanley,
|
|
Chairman, President and Chief Executive Officer
|
|
|
April 25, 2018
|
/s/ Richard J. Doleshek
|
|
Richard J. Doleshek,
|
|
Executive Vice President and Chief Financial Officer
|
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