Item 1. Consolidated Financial Statements.
BILL BARRETT CORPORATION
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2017
|
|
December 31, 2016
|
|
|
(in thousands, except share data)
|
|
Assets:
|
|
|
|
|
Current assets:
|
|
|
|
|
Cash and cash equivalents
|
$
|
155,885
|
|
|
$
|
275,841
|
|
|
Accounts receivable, net of allowance for doubtful accounts
|
42,089
|
|
|
32,837
|
|
|
Derivative assets
|
5,782
|
|
|
8,398
|
|
|
Assets held for sale, net of depreciation, depletion, amortization and impairment
|
145,553
|
|
|
—
|
|
|
Prepayments and other current assets
|
2,209
|
|
|
1,376
|
|
|
Total current assets
|
351,518
|
|
|
318,452
|
|
|
Property and equipment - at cost, successful efforts method for oil and gas properties:
|
|
|
|
|
Proved oil and gas properties
|
1,292,786
|
|
|
1,539,373
|
|
|
Unproved oil and gas properties, excluded from amortization
|
70,535
|
|
|
58,830
|
|
|
Furniture, equipment and other
|
17,217
|
|
|
23,636
|
|
|
|
1,380,538
|
|
|
1,621,839
|
|
|
Accumulated depreciation, depletion, amortization and impairment
|
(404,693
|
)
|
|
(559,690
|
)
|
|
Total property and equipment, net
|
975,845
|
|
|
1,062,149
|
|
|
Deferred income tax asset
|
—
|
|
|
1,587
|
|
|
Deferred financing costs and other noncurrent assets
|
3,143
|
|
|
3,153
|
|
|
Total
|
$
|
1,330,506
|
|
|
$
|
1,385,341
|
|
|
Liabilities and Stockholders' Equity:
|
|
|
|
|
Current liabilities:
|
|
|
|
|
Accounts payable and accrued liabilities
|
$
|
85,678
|
|
|
$
|
49,447
|
|
|
Amounts payable to oil and gas property owners
|
12,563
|
|
|
6,192
|
|
|
Production taxes payable
|
22,805
|
|
|
22,992
|
|
|
Derivative liabilities
|
—
|
|
|
4,346
|
|
|
Deferred income taxes
|
—
|
|
|
1,587
|
|
|
Current portion of long-term debt
|
465
|
|
|
454
|
|
|
Liabilities associated with assets held for sale
|
4,856
|
|
|
—
|
|
|
Total current liabilities
|
126,367
|
|
|
85,018
|
|
|
Long-term debt, net of debt issuance costs
|
668,744
|
|
|
711,808
|
|
|
Asset retirement obligations
|
15,771
|
|
|
10,703
|
|
|
Derivatives and other noncurrent liabilities
|
4,610
|
|
|
6,269
|
|
|
Stockholders' equity:
|
|
|
|
|
Common stock, $0.001 par value; authorized 300,000,000 and 150,000,000 shares at September 30, 2017 and December 31, 2016, respectively; 76,284,992 and 75,721,360 shares issued and outstanding at September 30, 2017 and December 31, 2016, respectively, with 1,391,256 and 1,325,714 shares subject to restrictions, respectively
|
75
|
|
|
74
|
|
|
Additional paid-in capital
|
1,118,180
|
|
|
1,113,797
|
|
|
Retained earnings (accumulated deficit)
|
(603,241
|
)
|
|
(542,328
|
)
|
|
Treasury stock, at cost: zero shares at September 30, 2017 and December 31, 2016
|
—
|
|
|
—
|
|
|
Total stockholders' equity
|
515,014
|
|
|
571,543
|
|
|
Total
|
$
|
1,330,506
|
|
|
$
|
1,385,341
|
|
See notes to Unaudited Consolidated Financial Statements.
BILL BARRETT CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
(in thousands, except share and per share data)
|
|
Operating Revenues:
|
|
|
|
|
|
|
|
|
Oil, gas and NGL production
|
$
|
67,175
|
|
|
$
|
50,133
|
|
|
$
|
168,541
|
|
|
$
|
126,279
|
|
|
Other operating revenues
|
690
|
|
|
348
|
|
|
926
|
|
|
920
|
|
|
Total operating revenues
|
67,865
|
|
|
50,481
|
|
|
169,467
|
|
|
127,199
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
Lease operating expense
|
5,919
|
|
|
4,795
|
|
|
17,287
|
|
|
22,101
|
|
|
Gathering, transportation and processing expense
|
620
|
|
|
472
|
|
|
1,644
|
|
|
1,871
|
|
|
Production tax expense
|
5,384
|
|
|
3,832
|
|
|
9,140
|
|
|
7,037
|
|
|
Exploration expense
|
18
|
|
|
16
|
|
|
48
|
|
|
64
|
|
|
Impairment, dry hole costs and abandonment expense
|
261
|
|
|
974
|
|
|
8,336
|
|
|
1,766
|
|
|
(Gain) loss on sale of properties
|
—
|
|
|
1,914
|
|
|
(92
|
)
|
|
1,206
|
|
|
Depreciation, depletion and amortization
|
41,732
|
|
|
43,083
|
|
|
119,409
|
|
|
125,491
|
|
|
Unused commitments
|
4,557
|
|
|
4,567
|
|
|
13,687
|
|
|
13,703
|
|
|
General and administrative expense
|
12,496
|
|
|
9,178
|
|
|
30,788
|
|
|
31,535
|
|
|
Other operating expenses, net
|
(282
|
)
|
|
—
|
|
|
(1,610
|
)
|
|
—
|
|
|
Total operating expenses
|
70,705
|
|
|
68,831
|
|
|
198,637
|
|
|
204,774
|
|
|
Operating Income (Loss)
|
(2,840
|
)
|
|
(18,350
|
)
|
|
(29,170
|
)
|
|
(77,575
|
)
|
|
Other Income and Expense:
|
|
|
|
|
|
|
|
|
Interest and other income
|
332
|
|
|
72
|
|
|
1,030
|
|
|
166
|
|
|
Interest expense
|
(13,926
|
)
|
|
(13,991
|
)
|
|
(44,014
|
)
|
|
(45,160
|
)
|
|
Commodity derivative gain (loss)
|
(12,408
|
)
|
|
6,054
|
|
|
19,654
|
|
|
(7,258
|
)
|
|
Gain (loss) on extinguishment of debt
|
—
|
|
|
29
|
|
|
(7,904
|
)
|
|
8,726
|
|
|
Total other income and expense
|
(26,002
|
)
|
|
(7,836
|
)
|
|
(31,234
|
)
|
|
(43,526
|
)
|
|
Income (Loss) before Income Taxes
|
(28,842
|
)
|
|
(26,186
|
)
|
|
(60,404
|
)
|
|
(121,101
|
)
|
|
(Provision for) Benefit from Income Taxes
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Net Income (Loss)
|
$
|
(28,842
|
)
|
|
$
|
(26,186
|
)
|
|
$
|
(60,404
|
)
|
|
$
|
(121,101
|
)
|
|
Net Income (Loss) Per Common Share, Basic
|
$
|
(0.39
|
)
|
|
$
|
(0.44
|
)
|
|
$
|
(0.81
|
)
|
|
$
|
(2.28
|
)
|
|
Net Income (Loss) Per Common Share, Diluted
|
$
|
(0.39
|
)
|
|
$
|
(0.44
|
)
|
|
$
|
(0.81
|
)
|
|
$
|
(2.28
|
)
|
|
Weighted Average Common Shares Outstanding, Basic
|
74,886,107
|
|
|
58,851,598
|
|
|
74,742,699
|
|
|
53,081,809
|
|
|
Weighted Average Common Shares Outstanding, Diluted
|
74,886,107
|
|
|
58,851,598
|
|
|
74,742,699
|
|
|
53,081,809
|
|
See notes to Unaudited Consolidated Financial Statements.
BILL BARRETT CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
(in thousands)
|
|
Net Income (Loss)
|
$
|
(28,842
|
)
|
|
$
|
(26,186
|
)
|
|
$
|
(60,404
|
)
|
|
$
|
(121,101
|
)
|
|
Other comprehensive income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Comprehensive Income (Loss)
|
$
|
(28,842
|
)
|
|
$
|
(26,186
|
)
|
|
$
|
(60,404
|
)
|
|
$
|
(121,101
|
)
|
See notes to Unaudited Consolidated Financial Statements.
BILL BARRETT CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
2017
|
|
2016
|
|
|
(in thousands)
|
|
Operating Activities:
|
|
|
|
|
Net Income (Loss)
|
$
|
(60,404
|
)
|
|
$
|
(121,101
|
)
|
|
Adjustments to reconcile to net cash provided by operations:
|
|
|
|
|
Depreciation, depletion and amortization
|
119,409
|
|
|
125,491
|
|
|
Impairment, dry hole costs and abandonment expense
|
8,336
|
|
|
1,766
|
|
|
Commodity derivative (gain) loss
|
(19,654
|
)
|
|
7,258
|
|
|
Settlements of commodity derivatives
|
17,062
|
|
|
78,417
|
|
|
Stock compensation and other non-cash charges
|
5,134
|
|
|
7,208
|
|
|
Amortization of deferred financing costs
|
1,665
|
|
|
2,075
|
|
|
(Gain) loss on extinguishment of debt
|
7,904
|
|
|
(8,726
|
)
|
|
(Gain) loss on sale of properties
|
(92
|
)
|
|
1,206
|
|
|
Change in operating assets and liabilities:
|
|
|
|
|
Accounts receivable
|
(9,252
|
)
|
|
13,552
|
|
|
Prepayments and other assets
|
(980
|
)
|
|
(968
|
)
|
|
Accounts payable, accrued and other liabilities
|
20,071
|
|
|
18,903
|
|
|
Amounts payable to oil and gas property owners
|
6,371
|
|
|
(2,894
|
)
|
|
Production taxes payable
|
(187
|
)
|
|
(5,980
|
)
|
|
Net cash provided by (used in) operating activities
|
95,383
|
|
|
116,207
|
|
|
Investing Activities:
|
|
|
|
|
Additions to oil and gas properties, including acquisitions
|
(160,788
|
)
|
|
(93,704
|
)
|
|
Additions of furniture, equipment and other
|
(268
|
)
|
|
(1,184
|
)
|
|
Proceeds from sale of properties and other investing activities
|
(712
|
)
|
|
25,571
|
|
|
Net cash provided by (used in) investing activities
|
(161,768
|
)
|
|
(69,317
|
)
|
|
Financing Activities:
|
|
|
|
|
Proceeds from debt
|
275,000
|
|
|
—
|
|
|
Principal payments on debt
|
(322,228
|
)
|
|
(329
|
)
|
|
Proceeds from sale of common stock, net of offering costs
|
(298
|
)
|
|
—
|
|
|
Deferred financing costs and other
|
(6,045
|
)
|
|
(1,134
|
)
|
|
Net cash provided by (used in) financing activities
|
(53,571
|
)
|
|
(1,463
|
)
|
|
Increase (Decrease) in Cash and Cash Equivalents
|
(119,956
|
)
|
|
45,427
|
|
|
Beginning Cash and Cash Equivalents
|
275,841
|
|
|
128,836
|
|
|
Ending Cash and Cash Equivalents
|
$
|
155,885
|
|
|
$
|
174,263
|
|
See notes to Unaudited Consolidated Financial Statements.
BILL BARRETT CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(UNAUDITED)
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock
|
|
Additional
Paid-In
Capital
|
|
Retained
Earnings (Accumulated Deficit)
|
|
Treasury
Stock
|
|
Total
Stockholders'
Equity
|
|
Balance at December 31, 2015
|
$
|
48
|
|
|
$
|
921,318
|
|
|
$
|
(371,950
|
)
|
|
$
|
—
|
|
|
$
|
549,416
|
|
|
Exercise of options, restricted stock activity and shares exchanged for exercise and tax withholding
|
1
|
|
|
—
|
|
|
—
|
|
|
(1,114
|
)
|
|
(1,113
|
)
|
|
Stock-based compensation
|
—
|
|
|
9,455
|
|
|
—
|
|
|
—
|
|
|
9,455
|
|
|
Retirement of treasury stock
|
—
|
|
|
(1,114
|
)
|
|
—
|
|
|
1,114
|
|
|
—
|
|
|
Exchange of senior notes for shares of common stock
|
10
|
|
|
74,390
|
|
|
—
|
|
|
—
|
|
|
74,400
|
|
|
Issuance of common stock, net of offering costs
|
15
|
|
|
109,748
|
|
|
—
|
|
|
—
|
|
|
109,763
|
|
|
Net income (loss)
|
—
|
|
|
—
|
|
|
(170,378
|
)
|
|
—
|
|
|
(170,378
|
)
|
|
Balance at December 31, 2016
|
74
|
|
|
1,113,797
|
|
|
(542,328
|
)
|
|
—
|
|
|
571,543
|
|
|
Cumulative effect of accounting change
(1)
|
—
|
|
|
180
|
|
|
(509
|
)
|
|
—
|
|
|
(329
|
)
|
|
Exercise of options, restricted stock activity and shares exchanged for exercise and tax withholding
|
1
|
|
|
—
|
|
|
—
|
|
|
(1,246
|
)
|
|
(1,245
|
)
|
|
Stock-based compensation
|
—
|
|
|
5,510
|
|
|
—
|
|
|
—
|
|
|
5,510
|
|
|
Retirement of treasury stock
|
—
|
|
|
(1,246
|
)
|
|
—
|
|
|
1,246
|
|
|
—
|
|
|
Issuance of common stock, net of offering costs
|
—
|
|
|
(61
|
)
|
|
—
|
|
|
—
|
|
|
(61
|
)
|
|
Net income (loss)
|
—
|
|
|
—
|
|
|
(60,404
|
)
|
|
—
|
|
|
(60,404
|
)
|
|
Balance at September 30, 2017
|
$
|
75
|
|
|
$
|
1,118,180
|
|
|
$
|
(603,241
|
)
|
|
$
|
—
|
|
|
$
|
515,014
|
|
See notes to Unaudited Consolidated Financial Statements.
|
|
|
|
(1)
|
Cumulative effect of accounting change relates to the adoption of Accounting Standards Update 2016-09. See Note 2 of the Consolidated Financial Statements for further detail on the adoption of this accounting standard.
|
BILL BARRETT CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
September 30, 2017
1. Organization
Bill Barrett Corporation, a Delaware corporation, together with its wholly-owned subsidiaries (collectively, the "Company"), is an independent oil and gas company engaged in the exploration, development and production of oil, natural gas and natural gas liquids ("NGLs"). Since its inception in January 2002, the Company has conducted its activities principally in the Rocky Mountain region of the United States.
2
. Summary of Significant Accounting Policies
Basis of Presentation.
The accompanying Unaudited Consolidated Financial Statements include the accounts of the Company. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All intercompany accounts and transactions have been eliminated in consolidation. In the opinion of management, the accompanying consolidated financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company's interim results. However, operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year. The Company's
2016
Annual Report on Form 10-K includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Quarterly Report on Form 10-Q. Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in the Company's
2016
Annual Report on Form 10-K.
Use of Estimates.
In the course of preparing the Company's consolidated financial statements in accordance with GAAP, management makes various assumptions, judgments and estimates to determine the reported amount of assets, liabilities, revenues and expenses and in the disclosure of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established.
Areas requiring the use of assumptions, judgments and estimates include volumes of oil, natural gas and NGL reserves used in calculating depreciation, depletion and amortization ("DD&A"), the amount of expected future net cash flows used in determining possible impairments of proved oil and gas properties and the amount of future capital costs used in these calculations. Assumptions, judgments and estimates also are required in determining asset retirement obligations, the timing of dry hole costs, impairments of unproved oil and gas properties, valuing deferred tax assets and estimating fair values of derivative instruments and stock-based payment awards.
Accounts Receivable.
Accounts receivable is comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
As of September 30, 2017
|
|
As of December 31, 2016
|
|
|
(in thousands)
|
|
Accrued oil, gas and NGL sales
|
$
|
33,170
|
|
|
$
|
26,542
|
|
|
Due from joint interest owners
|
9,164
|
|
|
4,366
|
|
|
Other
|
14
|
|
|
1,952
|
|
|
Allowance for doubtful accounts
|
(259
|
)
|
|
(23
|
)
|
|
Total accounts receivable
|
$
|
42,089
|
|
|
$
|
32,837
|
|
Oil and Gas Properties.
The Company's oil, gas and NGL exploration and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and remain within cash flows from investing activities in the Unaudited Consolidated Statements of Cash Flows. If an exploratory well does find proved reserves, the costs remain capitalized and are included within additions to oil and gas properties and remain within cash flows from investing activities in the Unaudited Consolidated Statements of Cash Flows. The costs of development wells are capitalized whether
proved reserves are added or not. Oil and gas lease acquisition costs are also capitalized. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized.
Other exploration costs, including certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts.
Unproved oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive or are assigned proved reserves. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain until all costs are recovered. Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, future plans to develop acreage, recent sales prices of comparable properties and other relevant matters.
Materials and supplies consist primarily of tubular goods and well equipment to be used in future drilling operations or repair operations and are carried at the lower of cost or market.
The following table sets forth the net capitalized costs and associated accumulated DD&A and non-cash impairments relating to the Company's oil, natural gas and NGL producing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
As of September 30, 2017
|
|
As of December 31, 2016
|
|
|
(in thousands)
|
|
Proved properties
|
$
|
218,746
|
|
|
$
|
306,075
|
|
|
Wells and related equipment and facilities
|
1,035,764
|
|
|
1,164,354
|
|
|
Support equipment and facilities
|
34,317
|
|
|
63,238
|
|
|
Materials and supplies
|
3,959
|
|
|
5,706
|
|
|
Total proved oil and gas properties
(1)
|
$
|
1,292,786
|
|
|
$
|
1,539,373
|
|
|
Unproved properties
|
33,713
|
|
|
27,790
|
|
|
Wells and facilities in progress
|
36,822
|
|
|
31,040
|
|
|
Total unproved oil and gas properties, excluded from amortization
(1)
|
$
|
70,535
|
|
|
$
|
58,830
|
|
|
Accumulated depreciation, depletion, amortization and impairment
(1)
|
(393,340
|
)
|
|
(543,154
|
)
|
|
Total oil and gas properties, net
(1)
|
$
|
969,981
|
|
|
$
|
1,055,049
|
|
|
|
|
|
(1)
|
Excludes oil and gas properties held for sale of
$145.1 million
, comprised of
$410.7 million
of proved oil and gas properties and
$0.4 million
of unproved oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment of
$266.0 million
. Held for sale balances are included in current assets as assets held for sale, net of amortization and impairment, in the Unaudited Consolidated Balance Sheet as of
September 30, 2017
. See Note
4
for additional information on assets held for sale.
|
The Company reviews oil and natural gas properties for impairment on a quarterly basis or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future net cash flows of its oil and gas properties using proved and risked probable and possible reserves based on the Company's development plans and best estimate of future production, commodity pricing, reserve risking, gathering and transportation deductions, production tax rates, lease operating expenses and future development costs. The Company compares such undiscounted future net cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the undiscounted future net cash flows exceed the carrying amount of the oil and gas properties, no impairment is taken. If the carrying amount of a property exceeds the undiscounted future net cash flows, the Company will impair the carrying value to fair value based on an analysis of quantitative and qualitative factors existing as of the balance sheet date. The Company does not believe that the undiscounted future net cash flows of its oil and gas properties represent the applicable market value. The factors used to determine fair value may include, but are not limited to, recent sales prices of comparable properties, indications from marketing activities, the present value of future revenues, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the projected cash flows.
In addition, oil and gas properties are assessed for impairment once they meet the criteria to be classified as held for sale. Assets held for sale are carried at the lower of carrying cost or fair value less costs to sell. The fair value of the assets is determined using a market approach, based on an estimated selling price, as evidenced by current marketing activities, if possible. If an estimated selling price is not available, the Company utilizes the income valuation technique, which involves calculating the present value of future net cash flows as discussed above. If the carrying amount of the assets exceeds the fair value less costs to sell, an impairment will result to reduce the value of the properties down to fair value less costs to sell.
The Company recognized non-cash impairment, dry hole costs and abandonment expense in the Unaudited Consolidated Statements of Operations as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
(in thousands)
|
|
Impairment of unproved oil and gas properties
(1)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
8,010
|
|
|
$
|
183
|
|
|
Dry hole costs
|
—
|
|
|
1
|
|
|
—
|
|
|
71
|
|
|
Abandonment expense and lease expirations
|
261
|
|
|
973
|
|
|
326
|
|
|
1,512
|
|
|
Total impairment, dry hole costs and abandonment expense
|
$
|
261
|
|
|
$
|
974
|
|
|
$
|
8,336
|
|
|
$
|
1,766
|
|
|
|
|
|
(1)
|
The Company recognized a non-cash impairment charge associated with unproved oil and gas properties in the Cottonwood Gulch area of the Piceance Basin during the
nine
months ended
September 30, 2017
. The Company has no current plan to develop this acreage.
|
The provision for DD&A of oil and gas properties is calculated on a field-by-field basis using the unit-of-production method. Natural gas and NGLs are converted to an oil equivalent, Boe, at the standard rate of six Mcf to one Boe and forty-two gallons to one Boe, respectively. Estimated future dismantlement, restoration and abandonment costs are taken into consideration by this calculation.
Accounts Payable and Accrued Liabilities.
Accounts payable and accrued liabilities are comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
As of September 30, 2017
|
|
As of December 31, 2016
|
|
|
(in thousands)
|
|
Accrued drilling, completion and facility costs
|
$
|
33,325
|
|
|
$
|
15,594
|
|
|
Accrued lease operating, gathering, transportation and processing expenses
|
4,589
|
|
|
4,261
|
|
|
Accrued general and administrative expenses
|
8,653
|
|
|
6,375
|
|
|
Accrued interest payable
|
23,500
|
|
|
12,264
|
|
|
Prepayments from partners
|
11,249
|
|
|
332
|
|
|
Trade payables
|
2,323
|
|
|
7,900
|
|
|
Other
|
2,039
|
|
|
2,721
|
|
|
Total accounts payable and accrued liabilities
|
$
|
85,678
|
|
|
$
|
49,447
|
|
Environmental Liabilities.
Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Environmental liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. Recent case law in Wyoming has exposed the Company to potential obligations for plugging and abandoning wells, and associated reclamation, for assets that were sold to other industry parties in prior years. If such third parties become unable to fulfill their contractual obligations to the Company as provided for in the applicable purchase and sale agreements, regulatory agencies and landowners may demand that the Company perform such activities. The Company recognized
$0.8 million
associated with these obligations in other operating expenses in the Consolidated Statement of Operations for the
nine
months ended
September 30, 2017
.
Revenue Recognition.
Oil, gas and NGL revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured.
The Company uses the sales method to account for gas and NGL imbalances. Under this method, revenues are recorded on the basis of gas and NGLs actually sold by the Company. In addition, the Company records revenues for its share of gas and NGLs sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company also reduces revenues for other owners' volumetric share of gas and NGLs sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company's remaining over- and under-produced gas and NGLs balancing positions are taken into account in determining the Company's proved oil, gas and NGL reserves. Imbalances at
September 30, 2017
and
2016
were not material.
Derivative Instruments and Hedging Activities.
The Company periodically uses derivative financial instruments to achieve a more predictable cash flow from its oil, natural gas and NGL sales by reducing its exposure to price fluctuations. Derivative instruments are recorded at fair market value and are included in the Unaudited Consolidated Balance Sheets as assets or liabilities and in the Unaudited Consolidated Statements of Operations as commodity derivative gain (loss).
Income Taxes.
Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or liabilities are settled. Deferred income taxes also include tax credits and net operating losses that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates. Deferred tax assets are regularly reviewed, considering all positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, taxable strategies and results of recent operations. The assumptions about future taxable income require significant judgment to determine whether it is more likely than not that the deferred tax asset will be realized. If it is determined that the deferred tax asset will not be realized, then a valuation allowance will be recorded against the deferred tax asset. The Company began recording a full valuation allowance against the deferred tax asset during the period ending September 30, 2015 and continues to do so as of
September 30, 2017
.
The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. Only tax positions that meet the more-likely-than-not recognition threshold are recognized. The Company does not have any uncertain tax positions recorded as of
September 30, 2017
.
Earnings/Loss Per Share.
Basic net income (loss) per common share is calculated by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding during each period. Diluted net income per common share is calculated by dividing net income attributable to common stock by the weighted average number of common shares outstanding and other dilutive securities. Potentially dilutive securities for the diluted net income per common share calculations consist of nonvested equity shares of common stock and in-the-money outstanding stock options to purchase the Company's common stock. No potential common shares are included in the computation of any diluted per share amount when a net loss exists, as was the case for the three and
nine
months ended
September 30, 2017
and
2016
.
The following table sets forth the calculation of basic and diluted income (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
(in thousands, except per share amounts)
|
|
Net income (loss)
|
$
|
(28,842
|
)
|
|
$
|
(26,186
|
)
|
|
$
|
(60,404
|
)
|
|
$
|
(121,101
|
)
|
|
Basic weighted-average common shares outstanding in period
|
74,886
|
|
|
58,852
|
|
|
74,743
|
|
|
53,082
|
|
|
Diluted weighted-average common shares outstanding in period
|
74,886
|
|
|
58,852
|
|
|
74,743
|
|
|
53,082
|
|
|
Basic net income (loss) per common share
|
$
|
(0.39
|
)
|
|
$
|
(0.44
|
)
|
|
$
|
(0.81
|
)
|
|
$
|
(2.28
|
)
|
|
Diluted net income (loss) per common share
|
$
|
(0.39
|
)
|
|
$
|
(0.44
|
)
|
|
$
|
(0.81
|
)
|
|
$
|
(2.28
|
)
|
New Accounting Pronouncements.
In May 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2017-09,
Stock Compensation-Scope of Modification Accounting
. The objective of this update is to provide clarity and reduce both diversity in practice and cost and complexity when applying a change to the terms or conditions of a share-based payment award. ASU 2017-09 is effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. The Company does not expect the standard to have a significant impact on the Company's financial statements or disclosures.
In January 2017, the FASB issued ASU 2017-01,
Business Combinations: Clarifying the definition of a business
. The objective of this update is to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 is effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. The Company does not expect the standard to have a significant impact on the Company's financial statements or disclosures.
In August 2016, the FASB issued ASU 2016-15,
Statement of Cash Flows-Classification of Certain Cash Receipts and Cash Payments
. The objective of this update is to address eight specific cash flow issues in order to reduce the existing diversity in practice. ASU 2016-15 is effective for the annual periods beginning after December 15, 2017, and interim periods within those annual periods. The Company does not expect the standard to have a significant impact on the Company's financial statements or disclosures.
In March 2016, the FASB issued ASU 2016-09,
Improvements to Employee Share-Based Payment Accounting
. The objective of this update is to simplify the current guidance for stock compensation. The areas for simplification involve several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. ASU 2016-09 was effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The standard was adopted effective January 1, 2017 and did not have a significant impact on the Company's disclosures or financial statements. As of January 1, 2017, the Company did not have excess tax benefits associated with its stock compensation and therefore there was no tax impact upon adoption of this standard. In addition, the employee taxes paid on the statement of cash flows when shares were withheld for taxes were already classified as a financing activity; therefore, there was no cash flow statement impact upon adoption of this standard. The Company elected to account for forfeitures as they occur as opposed to estimating the number of awards that are expected to vest. Per ASU 2016-09, the election is considered a change in accounting principle, with the cumulative effect of the change reported as an adjustment to the beginning equity balance. The Company reported an increase to accumulated deficit and additional paid in capital ("APIC") of
$0.2 million
related to equity award compensation and an increase to accumulated deficit and derivative and other noncurrent liabilities of
$0.3 million
related to liability award compensation. The cumulative effect of accounting change is reported in the Consolidated Statement of Stockholders' Equity.
In February 2016, the FASB issued ASU 2016-02,
Leases
. The objective of this update is to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. ASU 2016-02 is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. The Company has performed an initial assessment by compiling and analyzing contracts and leasing arrangements that may be affected. The Company is still evaluating the impact of adopting this standard.
In November 2015, the FASB issued ASU 2015-17,
Balance Sheet Classification of Deferred Taxes
. The objective of this update is to require deferred tax liabilities and assets to be classified as noncurrent in a classified statement of financial position. ASU 2015-17 was effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The standard was adopted January 1, 2017 on a prospective basis and did not have a significant impact on the Company's disclosures and financial statements. Prior periods were not retrospectively adjusted.
In May 2014, the FASB issued ASU 2014-09,
Revenue from Contracts with Customers.
The objective of this update is to clarify the principles for recognizing revenue and to develop a common revenue standard. The FASB subsequently issued ASU 2015-14, ASU 2016-08, ASU 2016-10, ASU 2016-12 and ASU 2016-20, which provided additional implementation guidance and deferred the effective date of ASU 2014-09. The standard is effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. The standard will be adopted using the modified retrospective transition method, effective January 1, 2018. The Company has performed an assessment of its current existing revenue contracts and is in the process of implementing additional control procedures. The Company does not expect the standard to have a significant impact on the Company's financial statements or disclosures.
3. Supplemental Disclosures of Cash Flow Information
Supplemental cash flow information is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
2017
|
|
2016
|
|
|
(in thousands)
|
|
Cash paid for interest
|
$
|
31,113
|
|
|
$
|
31,736
|
|
|
Cash paid for income taxes
|
—
|
|
|
—
|
|
|
Supplemental disclosures of non-cash investing and financing activities:
|
|
|
|
|
Accrued liabilities - oil and gas properties
|
37,319
|
|
|
8,318
|
|
|
Change in asset retirement obligations, net of disposals
|
10,453
|
|
|
(4,788
|
)
|
|
Retirement of treasury stock
|
(1,246
|
)
|
|
(1,098
|
)
|
|
Properties exchanged in non-cash transactions
|
13,323
|
|
|
—
|
|
|
Fair value of debt exchanged for common stock
(1)
|
—
|
|
|
74,400
|
|
|
|
|
|
(1)
|
See Note
5
for additional information regarding the Debt Exchange.
|
4
. Acquisitions, Exchanges, Divestitures and Assets Held for Sale
During the three months ended September 30, 2017, the Company committed to a plan to sell the Company's remaining assets in the Uinta Basin. Therefore, the related assets and liabilities were classified as held for sale in the Unaudited Consolidated Balance Sheet as of September 30, 2017. Assets held for sale are recorded at the lesser of their respective carrying value or fair value less estimated costs to sell. The fair value of the net assets held for sale was in excess of the net carrying value as of September 30, 2017. The net carrying value was presented as assets held for sale, net of depreciation, depletion, amortization and impairment, of
$145.6 million
and liabilities associated with assets held for sale of
$4.9 million
on the Unaudited Consolidated Balance Sheet as of September 30, 2017.
On February 28, 2017, the Company acquired acreage in the DJ Basin for
$11.6 million
, after final closing adjustments. The transaction was considered an asset acquisition and therefore the properties were recorded based on the fair value of the total consideration transferred on the acquisition date and transaction costs were capitalized as a component of the cost of the assets acquired. The acquisition included
$9.1 million
and
$11.2 million
of proved and unevaluated properties, respectively, and asset retirement obligations of
$8.7 million
.
During the nine months ended September 30, 2017, the Company completed
two
acreage exchange transactions to consolidate certain acreage positions in the DJ Basin. Pursuant to the transactions, the Company exchanged leasehold interests in certain proved undeveloped acreage. The Company’s future cash flows are not expected to significantly change as a result of the exchange transactions, therefore, the non-monetary exchanges were measured based on the carrying values and not on the fair values of the assets exchanged.
On July 14, 2016, the Company sold certain non-core assets in the Uinta Basin. The Company received
$27.8 million
in cash proceeds, after final closing adjustments. In addition to the cash proceeds, the Company recognized non-cash proceeds of
$4.8 million
related to the relief from the Company's asset retirement obligation. Assets sold included
$30.6 million
in proved oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment, and
$2.0 million
in unproved oil and gas properties. Liabilities sold included
$4.8 million
of asset retirement obligations. The transaction was accounted for as a cost recovery. Therefore,
no
gain or loss was recognized.
5
. Long-Term Debt
The Company's outstanding debt is summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of September 30, 2017
|
|
As of December 31, 2016
|
|
|
Maturity Date
|
Principal
|
|
Debt Issuance Costs
|
|
Carrying
Amount
|
|
Principal
|
|
Debt Issuance Costs
|
|
Carrying
Amount
|
|
|
|
(in thousands)
|
|
Amended Credit Facility
|
April 9, 2020
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Convertible Notes
(1)
|
March 15, 2028
|
—
|
|
|
—
|
|
|
—
|
|
|
579
|
|
|
—
|
|
|
579
|
|
|
7.625% Senior Notes
(2)
|
October 1, 2019
|
—
|
|
|
—
|
|
|
—
|
|
|
315,300
|
|
|
(2,169
|
)
|
|
313,131
|
|
|
7.0% Senior Notes
(3)
|
October 15, 2022
|
400,000
|
|
|
(3,684
|
)
|
|
396,316
|
|
|
400,000
|
|
|
(4,227
|
)
|
|
395,773
|
|
|
8.75% Senior Notes
(4)
|
June 15, 2025
|
275,000
|
|
|
(4,548
|
)
|
|
270,452
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Lease Financing Obligation
(5)
|
August 10, 2020
|
2,443
|
|
|
(2
|
)
|
|
2,441
|
|
|
2,782
|
|
|
(3
|
)
|
|
2,779
|
|
|
Total Debt
|
|
$
|
677,443
|
|
|
$
|
(8,234
|
)
|
|
$
|
669,209
|
|
|
$
|
718,661
|
|
|
$
|
(6,399
|
)
|
|
$
|
712,262
|
|
|
Less: Current Portion of Long-Term Debt
(6)
|
|
465
|
|
|
—
|
|
|
465
|
|
|
454
|
|
|
—
|
|
|
454
|
|
|
Total Long-Term Debt
|
|
$
|
676,978
|
|
|
$
|
(8,234
|
)
|
|
$
|
668,744
|
|
|
$
|
718,207
|
|
|
$
|
(6,399
|
)
|
|
$
|
711,808
|
|
|
|
|
|
(1)
|
The Convertible Notes were redeemed on May 30, 2017. The aggregate estimated fair value of the Convertible Notes was approximately
$0.5 million
as of
December 31, 2016
based on reported market trades of these instruments.
|
|
|
|
|
(2)
|
The
7.625%
Senior Notes were redeemed on May 30, 2017. The aggregate estimated fair value of the
7.625%
Senior Notes was approximately
$314.5 million
as of
December 31, 2016
based on reported market trades of these instruments.
|
|
|
|
|
(3)
|
The aggregate estimated fair value of the
7.0%
Senior Notes was approximately
$386.3 million
and
$384.5 million
as of
September 30, 2017
and
December 31, 2016
, respectively, based on reported market trades of these instruments.
|
|
|
|
|
(4)
|
The aggregate estimated fair value of the
8.75%
Senior Notes was approximately
$266.8 million
as of
September 30, 2017
based on reported market trades of these instruments.
|
|
|
|
|
(5)
|
The aggregate estimated fair value of the Lease Financing Obligation was approximately
$2.3 million
and
$2.6 million
as of
September 30, 2017
and
December 31, 2016
, respectively. As there is no active, public market for the Lease Financing Obligation, the aggregate estimated fair value was based on market-based parameters of comparable term secured financing instruments.
|
|
|
|
|
(6)
|
The current portion of long-term debt includes the current portion of the Lease Financing Obligation.
|
Amended Credit Facility
The Company's amended revolving credit facility ("Amended Credit Facility") had commitments from
13
lenders and a borrowing base of
$300.0 million
as of
September 30, 2017
. As credit support for future payments under a contractual obligation, a
$26.0 million
letter of credit was issued under the Amended Credit Facility, which reduced the available borrowing capacity of the Amended Credit Facility as of
September 30, 2017
to
$274.0 million
. There have not been any borrowings under the Amended Credit Facility to date in 2017 and there were no such borrowings in 2016.
Interest rates are LIBOR plus applicable margins of
1.5%
to
2.5%
or ABR plus
0.5%
to
1.5%
and the unused commitment fee is between
0.375%
and
0.5%
based on borrowing base utilization.
The borrowing base under the Amended Credit Facility is determined at the discretion of the lenders, based on the collateral value of the Company's proved reserves that have been mortgaged to the lenders, and is subject to regular re-determinations on or about April 1 and October 1 of each year, as well as following any property sales. In October 2017, the Company's borrowing base was re-confirmed at
$300.0 million
based on proved reserves and the commodity hedge position in place at June 30, 2017. Future borrowing bases will be computed based on proved oil, natural gas and NGL reserves, hedge positions and estimated future cash flows from those reserves calculated using future commodity pricing provided by the Company's lenders, as well as any other outstanding debt. Lower commodity prices could result in a decreased borrowing base.
The Amended Credit Facility contains certain financial covenants. The Company is currently in compliance with all financial covenants and has complied with all financial covenants since issuance. If the Company fails to comply with the covenants or other terms of any agreements governing the Company's debt, the Company's lenders and holders of the Company's senior notes may have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt. The occurrence of any such event would adversely affect the Company's financial condition. In September 2015, the Company obtained an amendment to the Amended Credit Facility that replaced the Company's debt-to-EBITDAX (earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses) covenant in the facility with a
secured debt-to-EBITDAX covenant and an EBITDAX-to-interest covenant through March 31, 2018. There can be no assurance that the Company will be able to obtain similar amendments, or waivers of covenant breaches, in the future if needed.
5% Convertible Senior Notes Due 2028
On May 30, 2017, the Company redeemed the
$0.6 million
of outstanding Convertible Notes with the proceeds of its
8.75%
Senior Notes issued on April 28, 2017. See "
8.75%
Senior Notes due 2025" below for additional information.
7.625% Senior Notes Due 2019
On May 30, 2017, the Company redeemed the
$315.3 million
of outstanding
7.625%
Senior Notes with cash on hand and proceeds from the issuance of its
8.75%
Senior Notes on April 28, 2017. See "
8.75%
Senior Notes due 2025" below for additional information.
Due to the redemption of the Convertible Notes and the
7.625%
Senior Notes, the Company recognized a
$7.9 million
loss on extinguishment of debt on the Consolidated Statement of Operations for the
nine
months ended
September 30, 2017
.
The
7.625%
Senior Notes were issued at
$400.0 million
in principal amount on September 27, 2011. On June 3, 2016, the Company completed a debt exchange with a holder of the
7.625%
Senior Notes (the "Debt Exchange"). The holder exchanged
$84.7 million
principal amount of the
7.625%
Senior Notes for
10,000,000
newly issued shares of the Company’s common stock. Based on the fair value of the shares issued, the Company recognized an
$8.7 million
gain on extinguishment of debt on the Consolidated Statement of Operations for the year ended
December 31, 2016
. Following the Debt Exchange, the remaining aggregate principal amount was
$315.3 million
, which, as indicated above, was then redeemed on May 30, 2017.
7.0% Senior Notes Due 2022
On March 12, 2012, the Company issued
$400.0 million
in aggregate principal amount of
7.0%
Senior Notes due October 15, 2022 at par. The
7.0%
Senior Notes mature on
October 15, 2022
unless earlier redeemed or purchased by the Company. Interest is payable in arrears semi-annually on April 15 and October 15 of each year. The
7.0%
Senior Notes are senior unsecured obligations and rank equal in right of payment with all of the Company's other existing and future senior unsecured indebtedness, including the
8.75%
Senior Notes. The
7.0%
Senior Notes became redeemable at the Company's option on October 15, 2017 at a redemption price of
103.500%
of the principal amount. The redemption price will decrease to
102.333%
,
101.167%
and
100.000%
of the principal amount in 2018, 2019 and 2022, respectively. The
7.0%
Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company's indebtedness under the Amended Credit Facility and the
8.75%
Senior Notes. The
7.0%
Senior Notes include certain covenants that limit the Company's ability to incur additional indebtedness, make restricted payments, create liens or sell assets and that generally prohibit the Company from paying dividends. The Company is currently in compliance with all covenants and has complied with all covenants since issuance.
8.75% Senior Notes Due 2025
On April 28, 2017, the Company issued
$275.0 million
in aggregate principal amount of
8.75%
Senior Notes due
June 15, 2025
at par. Interest is payable in arrears semi-annually on June 15 and December 15 of each year, commencing on December 15, 2017. The
8.75%
Senior Notes are senior unsecured obligations and rank equal in right of payment with all of the Company's other existing and future senior unsecured indebtedness, including the
7.0%
Senior Notes.
The
8.75%
Senior Notes will become redeemable at the Company's option on or after June 15, 2020, 2021, 2022 and 2023 at redemption prices of
106.563%
,
104.375%
,
102.188%
and
100.000%
of the principal amount, respectively. Prior to June 15, 2020, the Company may use proceeds of an equity offering to redeem up to
35%
of the principal amount at a redemption price of
108.750%
of the principal amount. In addition, prior to June 15, 2020, the Company may redeem the notes at a redemption price equal to
100.000%
of the principal amount plus a specified "make-whole" premium.
The
8.75%
Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company's indebtedness under the Amended Credit Facility and the
7.0%
Senior Notes. The
8.75%
Senior Notes include certain covenants that limit the Company's ability to incur additional indebtedness, make restricted payments, create liens or sell assets and that generally prohibit the Company from paying dividends. The Company is currently in compliance with all covenants and has complied with all covenants since issuance.
Nothing in the indentures governing the
7.0%
Senior Notes or the
8.75%
Senior Notes prohibits the Company from repurchasing any of the notes from time to time at any price in open market purchases, negotiated transactions or by tender offer or otherwise without any notice to or consent of the holders.
Lease Financing Obligation Due 2020
The Company has a lease financing obligation with a balance of
$2.4 million
as of
September 30, 2017
resulting from the Company's sale and subsequent lease back of certain compressors and related facilities owned by the Company (the "Lease Financing Obligation"). The Lease Financing Obligation expires on
August 10, 2020
, and the Company has the option to purchase the equipment at the end of the lease term for the then current fair market value. The Lease Financing Obligation also contains an early buyout option pursuant to which the Company may purchase the equipment for
$1.8 million
on February 10, 2019. The lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of
3.3%
. See Note
12
for a discussion of aggregate minimum future lease payments.
6. Asset Retirement Obligations
A reconciliation of the Company's asset retirement obligations for the
nine
months ended
September 30, 2017
is as follows (in thousands):
|
|
|
|
|
|
|
|
As of December 31, 2016
|
$
|
11,238
|
|
|
Liabilities incurred
(1)
|
10,379
|
|
|
Liabilities settled
|
(814
|
)
|
|
Disposition of properties
|
(6
|
)
|
|
Accretion expense
|
765
|
|
|
Revisions to estimate
|
894
|
|
|
As of September 30, 2017
|
$
|
22,456
|
|
|
Less: liabilities associated with assets held for sale
|
4,856
|
|
|
Less: current asset retirement obligations
|
1,829
|
|
|
Long-term asset retirement obligations
|
$
|
15,771
|
|
|
|
|
|
(1)
|
Includes
$8.7 million
associated with properties acquired in the DJ Basin during the nine months ended September 30, 2017. See Note 4 for additional information regarding this acquisition.
|
7. Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company uses market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk. These inputs can be readily observable, market corroborated or generally unobservable. A fair value hierarchy was established that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).
Level 1
– Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2
– Quoted prices are available in active markets for similar assets or liabilities and in non-active markets for identical or similar instruments. Model-derived valuations have inputs that are observable or whose significant value drivers are observable. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Level 3 –
Pricing inputs include significant inputs that are generally less observable than objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. At each balance
sheet date, the Company performs an analysis of all applicable instruments and includes in Level 3 all of those whose fair value is based on significant unobservable inputs.
The following tables set forth by level within the fair value hierarchy the Company's assets and liabilities that were measured at fair value in the Unaudited Consolidated Balance Sheets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of September 30, 2017
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
|
(in thousands)
|
|
Assets
|
|
|
|
|
|
|
|
|
Cash equivalents
(1)
|
$
|
110,772
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
110,772
|
|
|
Deferred compensation plan
(1)
|
1,719
|
|
|
—
|
|
|
—
|
|
|
1,719
|
|
|
Commodity derivatives
(1)
|
—
|
|
|
8,211
|
|
|
—
|
|
|
8,211
|
|
|
Unproved oil and gas properties
(2)
|
—
|
|
|
—
|
|
|
1,088
|
|
|
1,088
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
Commodity derivatives
(1)
|
$
|
—
|
|
|
$
|
2,466
|
|
|
$
|
—
|
|
|
$
|
2,466
|
|
|
|
|
|
(1)
|
This represents a financial asset or liability that is measured at fair value on a recurring basis.
|
|
|
|
|
(2)
|
This represents a non-financial asset or liability that is measured at fair value on a nonrecurring basis.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2016
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
|
(in thousands)
|
|
Assets
|
|
|
|
|
|
|
|
|
Cash equivalents
(1)
|
$
|
40,115
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
40,115
|
|
|
Deferred compensation plan
(1)
|
1,447
|
|
|
—
|
|
|
—
|
|
|
1,447
|
|
|
Commodity derivatives
(1)
|
—
|
|
|
13,156
|
|
|
—
|
|
|
13,156
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
Commodity derivatives
(1)
|
$
|
—
|
|
|
$
|
10,003
|
|
|
$
|
—
|
|
|
$
|
10,003
|
|
|
|
|
|
(1)
|
This represents a financial asset or liability that is measured at fair value on a recurring basis.
|
Cash equivalents
– The highly liquid cash equivalents are recorded at carrying value. Carrying value approximates fair value, which represents a Level 1 input.
Deferred compensation plan
– The Company maintains a non-qualified deferred compensation plan which allows certain management employees to defer receipt of a portion of their compensation. The Company maintains assets for the deferred compensation plan in a rabbi trust. The assets of the rabbi trust are invested in publicly traded mutual funds and are recorded in other current and other long-term assets in the Unaudited Consolidated Balance Sheets. The deferred compensation plan financial assets are reported at fair value based on active market quotes, which represent Level 1 inputs.
Commodity derivatives
– The fair value of crude oil, natural gas and NGL forwards and options are estimated using a combined income and market valuation methodology with a mid-market pricing convention based upon forward commodity price and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes. The Company did not make any adjustments to the obtained curves. The pricing services publish observable market information from multiple brokers and exchanges. No proprietary models are used by the pricing services for the inputs. The Company utilized the counterparties' valuations to assess the reasonableness of the Company's valuations. The inputs discussed above all represent Level 2 inputs.
The commodity derivatives have been adjusted for non-performance risk. For applicable financial assets carried at fair value, the credit standing of the counterparties is analyzed and factored into the fair value measurement of those assets. In addition, the fair value measurement of a liability has been adjusted to reflect the nonperformance risk of the Company.
Oil and gas properties
–
Oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. If an impairment is necessary, the fair value is estimated by using
either a market approach based on recent sales prices of comparable properties and/or indications from marketing activities or by using the income valuation technique, which involves calculating the present value of future revenues. The present value, net of estimated operating and development costs, is calculated using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the projected cash flows, predominantly all of which are designated as Level 3 inputs within the fair value hierarchy. During the
nine
months ended
September 30, 2017
, the Company reduced its unproved Cottonwood Gulch assets in the Piceance Basin to a fair value of
$1.1 million
, resulting in a non-cash impairment charge of
$8.0 million
. During the year ended
December 31, 2016
,
no
properties were measured at fair value.
Properties classified as held for sale are recorded at the lesser of their respective carrying value or fair value less estimated costs to sell. The fair value is determined using a market approach, based on an estimated selling price, as evidenced by current marketing activities, if possible. If an estimated selling price is not available, the Company utilizes the income valuation technique discussed above. The fair value of the assets held for sale as of September 30, 2017 was in excess of the net carrying value, therefore, no impairment was necessary. See Note 4 for additional information on assets held for sale.
Acquisitions of proved and unproved properties
– Assets acquired and liabilities assumed under transactions that meet the criteria of a business combination under ASC Topic 805,
Business Combinations
are recorded at fair value on the acquisition date using an income valuation technique based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include estimates of reserves, production rates, future operating and development costs, future commodity prices including price differentials, future cash flows and a market participant-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation.
Assets acquired and liabilities assumed under transactions that do not meet the criteria of a business combination under ASC Topic 805,
Business Combinations
are accounted for as asset acquisitions and are recorded based on the fair value of the total consideration transferred on the acquisition date using the lowest observable inputs available. The Company acquired proved and unproved properties in the DJ Basin for total cash consideration of
$11.6 million
during the nine months ended
September 30, 2017
. See Note 4 for additional information regarding this asset acquisition.
Long-term Debt
– Long-term debt is not presented at fair value on the Unaudited Consolidated Balance Sheets, as it is recorded at carrying value, net of unamortized debt issuance costs. The Company issued the
8.75%
Senior Notes on April 28, 2017 and redeemed its
7.625%
Senior Notes on May 30, 2017. The fair values of the Company's fixed rate
7.0%
Senior Notes and
8.75%
Senior Notes totaled
$653.1 million
as of
September 30, 2017
. The fair values of the Company's fixed rate
7.625%
Senior Notes and
7.0%
Senior Notes totaled
$699.0 million
as of
December 31, 2016
. The fair values of the Company's fixed rate Senior Notes are based on active market quotes, which represent Level 1 inputs.
There is no active, public market for the Amended Credit Facility or Lease Financing Obligation and there was no such market for the Convertible Notes when they were outstanding. The recorded value of the Amended Credit Facility approximates its fair value due to its floating rate structure based on the LIBOR spread, secured interest, and the Company's borrowing base utilization. The Amended Credit Facility had a balance of
zero
as of
September 30, 2017
and
December 31, 2016
. The Convertible Notes were redeemed on May 30, 2017 and had a fair value of
$0.5 million
as of
December 31, 2016
. The Lease Financing Obligation fair values of
$2.3 million
and
$2.6 million
as of
September 30, 2017
and
December 31, 2016
, respectively, are measured based on market-based parameters of comparable term secured financing instruments. The fair value measurements for the Amended Credit Facility, Convertible Notes and Lease Financing Obligation represent Level 2 inputs.
8. Derivative Instruments
The Company uses financial derivative instruments as part of its price risk management program to achieve a more predictable cash flow from its production revenues by reducing its exposure to commodity price fluctuations. The Company has entered into financial commodity swap contracts related to the sale of a portion of the Company's production. The Company does not enter into derivative instruments for speculative or trading purposes.
In addition to financial contracts, the Company may at times be party to various physical commodity contracts for the sale of oil, natural gas and NGLs that have varying terms and pricing provisions. These physical commodity contracts qualify for the normal purchase and normal sale exception and therefore are not subject to hedge or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil, natural gas and NGL production revenues at the time of settlement.
All derivative instruments, other than those that meet the normal purchase and normal sale exception as mentioned above, are recorded at fair value and included in the Unaudited Consolidated Balance Sheets as assets or liabilities. The following table summarizes the location, as well as the gross and net fair value amounts, of all derivative instruments presented in the Unaudited Consolidated Balance Sheets as of the dates indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of September 30, 2017
|
|
Balance Sheet
|
|
Gross Amounts of
Recognized Assets
|
|
Gross Amounts
Offset in the Balance
Sheet
|
|
Net Amounts of
Assets Presented in
the Balance Sheet
|
|
|
|
(in thousands)
|
|
Derivative assets
|
|
$
|
7,608
|
|
|
$
|
(1,826
|
)
|
(1)
|
$
|
5,782
|
|
|
Deferred financing costs and other noncurrent assets
|
|
603
|
|
|
(482
|
)
|
(1)
|
121
|
|
|
Total derivative assets
|
|
$
|
8,211
|
|
|
$
|
(2,308
|
)
|
|
$
|
5,903
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Amounts of
Recognized Liabilities
|
|
Gross Amounts
Offset in the Balance
Sheet
|
|
Net Amounts of
Liabilities Presented in
the Balance Sheet
|
|
|
|
(in thousands)
|
|
Derivative liabilities
|
|
$
|
(1,826
|
)
|
|
$
|
1,826
|
|
(1)
|
$
|
—
|
|
|
Derivatives and other noncurrent liabilities
|
|
(640
|
)
|
|
482
|
|
(1)
|
(158
|
)
|
|
Total derivative liabilities
|
|
$
|
(2,466
|
)
|
|
$
|
2,308
|
|
|
$
|
(158
|
)
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2016
|
|
Balance Sheet
|
|
Gross Amounts of
Recognized Assets
|
|
Gross Amounts
Offset in the Balance
Sheet
|
|
Net Amounts of
Assets Presented in
the Balance Sheet
|
|
|
|
(in thousands)
|
|
Derivative assets
|
|
$
|
13,156
|
|
|
$
|
(4,758
|
)
|
(1)
|
$
|
8,398
|
|
|
Deferred financing costs and other noncurrent assets
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total derivative assets
|
|
$
|
13,156
|
|
|
$
|
(4,758
|
)
|
|
$
|
8,398
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Amounts of
Recognized Liabilities
|
|
Gross Amounts
Offset in the Balance
Sheet
|
|
Net Amounts of
Liabilities Presented in
the Balance Sheet
|
|
|
|
(in thousands)
|
|
Derivative liabilities
|
|
$
|
(9,104
|
)
|
|
$
|
4,758
|
|
(1)
|
$
|
(4,346
|
)
|
|
Derivatives and other noncurrent liabilities
|
|
(899
|
)
|
|
—
|
|
|
(899
|
)
|
|
Total derivative liabilities
|
|
$
|
(10,003
|
)
|
|
$
|
4,758
|
|
|
$
|
(5,245
|
)
|
|
|
|
|
(1)
|
Asset and liability balances with the same counterparty are presented as a net asset or liability on the Unaudited Consolidated Balance Sheets.
|
As of
September 30, 2017
, the Company had financial derivative instruments in place related to the sale of a portion of the Company's production for the following volumes for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
October – December 2017
|
|
For the year 2018
|
|
For the year 2019
|
|
|
Derivative
Volumes
|
|
Weighted Average Price
|
|
Derivative Volumes
|
|
Weighted Average Price
|
|
Derivative Volumes
|
|
Weighted Average Price
|
|
Oil (Bbls)
|
747,500
|
|
|
$
|
57.69
|
|
|
2,506,750
|
|
|
$
|
52.47
|
|
|
547,500
|
|
|
$
|
50.38
|
|
|
Natural Gas (MMbtu)
|
920,000
|
|
|
$
|
2.96
|
|
|
1,825,000
|
|
|
$
|
2.68
|
|
|
—
|
|
|
$
|
—
|
|
The Company's derivative financial instruments are generally executed with major financial or commodities trading institutions. The instruments expose the Company to market and credit risks and may, at times, be concentrated with certain counterparties or groups of counterparties. The Company had derivatives in place with
six
different counterparties as of
September 30, 2017
. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk in the event of non-performance by the counterparties, are substantially smaller. The creditworthiness of counterparties is subject to ongoing review by management, and the Company believes all of these institutions currently are acceptable credit risks. Full performance is anticipated, and the Company has no past due receivables from any of these counterparties.
It is the Company's policy to enter into derivative contracts with counterparties that are lenders in the Amended Credit Facility or affiliates of lenders in the Amended Credit Facility. The Company's derivative contracts are documented using an industry standard contract known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. Master Agreement or other contracts. Typical terms for these contracts include credit support requirements, cross default provisions, termination events and set-off provisions. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Amended Credit Facility. The Company has set-off provisions in its derivative contracts with lenders under its Amended Credit Facility which, in the event of a counterparty default, allow the Company to set-off amounts owed to the defaulting counterparty under the Amended Credit Facility or other obligations against monies owed to the Company under the derivative contracts. Where the counterparty is not a lender under the Company's Amended Credit Facility, the Company may not be able to set-off amounts owed by it under the Amended Credit Facility, even if such counterparty is an affiliate of a lender under such facility. The Company does not have any derivative balances that are offset by cash collateral.
9. Income Taxes
The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return in accordance with the FASB’s rules on income taxes. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities. During the
three and nine
months ended
September 30, 2017
and
2016
, the Company had no uncertain tax positions.
The Company’s policy is to classify accrued penalties and interest related to unrecognized tax benefits in the Company’s income tax provision. The Company did not record any accrued interest or penalties associated with unrecognized tax benefits during the
three and nine
months ended
September 30, 2017
and
2016
.
Income tax benefit for the
three and nine
months ended
September 30, 2017
and
2016
differs from the amounts that would be provided by applying the U.S. statutory income tax rates to pretax income or loss principally due to the effect of deferred tax asset valuation allowances, stock-based compensation, political lobbying expense, political contributions, nondeductible officer compensation and state income taxes. For the
three and nine
months ended
September 30, 2017
and
2016
, the effective tax rate remained at
zero
as a result of recording a full valuation allowance against the deferred tax asset balance. The Company considers all available evidence (both positive and negative) to estimate whether sufficient future taxable income will be generated to permit the use of the existing deferred tax assets. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgement is required in considering the relative weight of negative and positive evidence. The Company continues to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized prior to their expiration.
10. Stockholders' Equity
Common and Preferred Stock.
The Company's authorized capital structure consists of
75,000,000
shares of preferred stock, par value of
$0.001
per share, and
300,000,000
shares of common stock, par value of
$0.001
per share. At the annual meeting on May 16, 2017, a proposal to increase the number of authorized shares of common stock from
150,000,000
to
300,000,000
was approved. There are
no
issued and outstanding shares of preferred stock.
On June 10, 2015, the Company entered into an Equity Distribution Agreement (the "Agreement") with Goldman, Sachs and Co. (the "Manager"). Pursuant to the terms of the Agreement, the Company may sell, from time to time through or to the Manager, shares of its common stock having an aggregate gross sales price of up to
$100.0 million
. Sales of the shares, if any, will be made by means of ordinary brokers' transactions through the facilities of the New York Stock Exchange, at market prices, in block transactions, to or through a market maker, through an electronic communications network or as otherwise agreed by the Company and the Manager. As of
September 30, 2017
, and the date of this filing,
no
shares have been sold pursuant to the Agreement.
On June 3, 2016, the Company issued
10,000,000
shares of common stock pursuant to a debt exchange with a holder of the Company's
7.625%
Senior Notes. The holder exchanged
$84.7 million
principal amount of the
7.625%
Senior Notes for
10,000,000
newly issued shares of the Company’s common stock.
11. Equity Incentive Compensation Plans and Other Long-term Incentive Programs
The Company maintains various stock-based compensation plans and other employee benefits as discussed below. Stock-based compensation is measured at the grant date based on the value of the awards, and the fair value is recognized on a straight-line basis over the requisite service period (usually the vesting period). Cash-based compensation is measured at fair value at each reporting date and is recognized on a straight-line basis over the requisite service period (usually the vesting period).
The following table presents the long-term cash and equity incentive compensation related to awards for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
(in thousands)
|
|
Common stock options
(1)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
69
|
|
|
Nonvested common stock
(1)
|
1,434
|
|
|
1,458
|
|
|
4,437
|
|
|
5,273
|
|
|
Nonvested common stock units
(1)
|
174
|
|
|
165
|
|
|
516
|
|
|
711
|
|
|
Nonvested performance-based shares
(1)
|
—
|
|
|
275
|
|
|
558
|
|
|
1,510
|
|
|
Nonvested performance cash units
(2)(3)
|
1,073
|
|
|
242
|
|
|
(27
|
)
|
|
1,088
|
|
|
Total
|
$
|
2,681
|
|
|
$
|
2,140
|
|
|
$
|
5,484
|
|
|
$
|
8,651
|
|
|
|
|
|
(1)
|
Unrecognized compensation cost as of
September 30, 2017
was
$6.8 million
, which related to grants of nonvested shares of common stock that are expected to be recognized over a weighted-average period of
1.7 years
.
|
|
|
|
|
(2)
|
The nonvested performance-based cash units are accounted for as liability awards with
$1.1 million
in accounts payable and accrued liabilities as of
September 30, 2017
and
$2.1 million
and
$2.9 million
in derivatives and other noncurrent liabilities as of
September 30, 2017
and
December 31, 2016
, respectively, in the Unaudited Consolidated Balance Sheets.
|
|
|
|
|
(3)
|
Liability awards are fair valued at each reporting date. For the three months ended
September 30, 2017
, the weighted average fair value share price increased from
$3.41
as of
June 30, 2017
to
$4.29
as of
September 30, 2017
. For the
nine
months ended
September 30, 2017
, the weighted average fair value share price decreased from
$8.89
as of
December 31, 2016
to
$4.29
as of
September 30, 2017
.
|
Nonvested Equity and Cash Awards.
The following table presents the equity and cash awards granted pursuant to the Company's various stock compensation plans:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2017
|
|
Three Months Ended September 30, 2016
|
|
Equity Awards
|
|
Number of
Shares
|
|
Weighted Average
Grant Date Fair
Value Per Share
|
|
Number of
Shares
|
|
Weighted Average
Grant Date Fair
Value Per Share
|
|
Nonvested common stock
|
|
5,267
|
|
|
$
|
3.31
|
|
|
—
|
|
|
$
|
—
|
|
|
Nonvested common stock units
|
|
3,787
|
|
|
$
|
4.29
|
|
|
2,922
|
|
|
$
|
5.56
|
|
|
Total granted
|
|
9,054
|
|
|
|
|
2,922
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2017
|
|
Three Months Ended September 30, 2016
|
|
Cash Awards
|
|
Number of
Units
|
|
Fair Value
Per Unit
|
|
Number of
Units
|
|
Fair Value
Per Unit
|
|
Nonvested performance cash units
|
|
5,267
|
|
|
$
|
4.29
|
|
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2017
|
|
Nine Months Ended September 30, 2016
|
|
Equity Awards
|
|
Number of
Shares
|
|
Weighted Average
Grant Date Fair
Value Per Share
|
|
Number of
Shares
|
|
Weighted Average
Grant Date Fair
Value Per Share
|
|
Nonvested common stock
|
|
782,511
|
|
|
$
|
5.99
|
|
|
686,500
|
|
|
$
|
5.11
|
|
|
Nonvested common stock units
|
|
190,711
|
|
|
$
|
3.53
|
|
|
96,650
|
|
|
$
|
7.02
|
|
|
Total granted
|
|
973,222
|
|
|
|
|
783,150
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2017
|
|
Nine Months Ended September 30, 2016
|
|
Cash Awards
|
|
Number of
Units
|
|
Fair Value
Per Unit
|
|
Number of
Units
|
|
Fair Value
Per Unit
|
|
Nonvested performance cash units
|
|
663,425
|
|
|
$
|
4.29
|
|
|
646,572
|
|
|
$
|
5.56
|
|
Performance Cash Program
2017 Program.
In February 2017, the Compensation Committee approved a performance cash program (the "2017 Program") granting performance cash units that will settle in cash. The performance-based awards contingently vest in February 2020, depending on the level at which the performance goal is achieved. The performance goal, which will be measured over the
three
-year period ending December 31, 2019, will be the Company's total shareholder return ("TSR") based on a matrix measurement of (1) the Company's absolute performance and (2) the Company's ranking relative to a defined peer group's individual TSRs ("Relative TSR"). The Company's absolute performance is measured against the December 30, 2016 closing share price of
$6.99
. If the Company's absolute performance is lower than the
$6.99
share price, the payout is
zero
for this portion. If the Company's absolute performance is greater than the
$6.99
share price, the performance cash units will vest
1%
for each
1%
in growth, up to
100%
of the original grant. If the Company's Relative TSR is less than the median, the payout is
zero
for this portion. If the Company's Relative TSR is above the median, the payout is equal to twice the Company's percentile rank above the median, up to
100%
of the original grant. The Company's combined absolute performance and Relative TSR have a maximum vest of up to
200%
of the original grant. A total of
663,425
units were granted under this program during the
nine
months ended
September 30, 2017
.
12
. Commitments and Contingencies
Lease Financing Obligation.
The Company has a Lease Financing Obligation with Bank of America Leasing & Capital, LLC as the lead bank as discussed in Note
5
. The aggregate undiscounted minimum future lease payments, including both principal and interest components, are presented below. The Lease Financing Obligation contains an early buyout option pursuant to which the Company may purchase the equipment for
$1.8 million
on February 10, 2019.
|
|
|
|
|
|
|
|
|
As of September 30, 2017
|
|
|
(in thousands)
|
|
2017
|
$
|
135
|
|
|
2018
|
537
|
|
|
2019
|
1,824
|
|
|
Total
|
$
|
2,496
|
|
Transportation Charges
. The Company is party to
two
firm transportation contracts, through July 2021, to provide capacity on natural gas pipeline systems. The contracts require the Company to pay transportation charges regardless of the amount of pipeline capacity utilized by the Company. These monthly transportation payments are included in unused commitments expense in the Unaudited Consolidated Statements of Operations. As a result of previous divestitures in 2013 and 2014, the Company will likely not utilize the firm capacity on the natural gas pipelines.
The amounts in the table below represent the Company's future minimum transportation charges:
|
|
|
|
|
|
|
|
|
As of September 30, 2017
|
|
|
(in thousands)
|
|
2017
|
$
|
4,634
|
|
|
2018
|
18,691
|
|
|
2019
|
18,691
|
|
|
2020
|
18,691
|
|
|
2021
|
10,902
|
|
|
Thereafter
|
—
|
|
|
Total
|
$
|
71,609
|
|
Lease and Other Commitments.
The Company leases office space, vehicles and certain office equipment. In addition, the Company has various long-term agreements for telecommunication services. Future minimum annual payments under lease and other agreements are as follows:
|
|
|
|
|
|
|
|
|
As of September 30, 2017
|
|
|
(in thousands)
|
|
2017
|
$
|
951
|
|
|
2018
|
3,038
|
|
|
2019
|
1,070
|
|
|
2020
|
113
|
|
|
2021
|
6
|
|
|
Thereafter
|
—
|
|
|
Total
|
$
|
5,178
|
|
Litigation.
The Company is subject to litigation, claims and governmental and regulatory proceedings arising in the ordinary course of business. It is the opinion of the Company's management that current claims and litigation involving the Company are not likely to have a material adverse effect on its Unaudited Consolidated Balance Sheet, Cash Flows or Statements of Operations.
13. Guarantor Subsidiaries
In addition to the Amended Credit Facility, the
7.0%
Senior Notes and
8.75%
Senior Notes, which have been registered under the Securities Act of 1933, are jointly and severally guaranteed on a full and unconditional basis by the Company's
100%
owned subsidiaries ("Guarantor Subsidiaries"). Presented below are the Company's condensed consolidating balance sheets, statements of operations, statements of other comprehensive income (loss) and statements of cash flows, as required by Securities and Exchange Commission ("SEC") Rule 3-10 of Regulation S-X.
The following unaudited condensed consolidating financial statements have been prepared from the Company's financial information on the same basis of accounting as the Unaudited Consolidated Financial Statements. Investments in the subsidiaries are accounted for under the equity method. Accordingly, the entries necessary to consolidate the Company and the Guarantor Subsidiaries are reflected in the intercompany eliminations column.
Condensed Consolidating Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of September 30, 2017
|
|
|
Parent
Issuer
|
|
Guarantor
Subsidiaries
|
|
Intercompany
Eliminations
|
|
Consolidated
|
|
|
(in thousands)
|
|
Assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
155,885
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
155,885
|
|
|
Accounts receivable, net of allowance for doubtful accounts
|
41,935
|
|
|
154
|
|
|
—
|
|
|
42,089
|
|
|
Other current assets
|
153,544
|
|
|
—
|
|
|
—
|
|
|
153,544
|
|
|
Property and equipment, net
|
970,444
|
|
|
5,401
|
|
|
—
|
|
|
975,845
|
|
|
Intercompany receivable
|
20,304
|
|
|
—
|
|
|
(20,304
|
)
|
|
—
|
|
|
Investment in subsidiaries
|
(14,811
|
)
|
|
—
|
|
|
14,811
|
|
|
—
|
|
|
Noncurrent assets
|
3,143
|
|
|
—
|
|
|
—
|
|
|
3,143
|
|
|
Total assets
|
$
|
1,330,444
|
|
|
$
|
5,555
|
|
|
$
|
(5,493
|
)
|
|
$
|
1,330,506
|
|
|
Liabilities and Stockholders' Equity:
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
$
|
85,678
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
85,678
|
|
|
Other current liabilities
|
40,689
|
|
|
—
|
|
|
—
|
|
|
40,689
|
|
|
Intercompany payable
|
—
|
|
|
20,304
|
|
|
(20,304
|
)
|
|
—
|
|
|
Long-term debt
|
668,744
|
|
|
—
|
|
|
—
|
|
|
668,744
|
|
|
Other noncurrent liabilities
|
20,319
|
|
|
62
|
|
|
—
|
|
|
20,381
|
|
|
Stockholders' equity
|
515,014
|
|
|
(14,811
|
)
|
|
14,811
|
|
|
515,014
|
|
|
Total liabilities and stockholders' equity
|
$
|
1,330,444
|
|
|
$
|
5,555
|
|
|
$
|
(5,493
|
)
|
|
$
|
1,330,506
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2016
|
|
|
Parent
Issuer
|
|
Guarantor
Subsidiaries
|
|
Intercompany
Eliminations
|
|
Consolidated
|
|
|
(in thousands)
|
|
Assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
275,841
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
275,841
|
|
|
Accounts receivable, net of allowance for doubtful accounts
|
32,659
|
|
|
178
|
|
|
—
|
|
|
32,837
|
|
|
Other current assets
|
9,774
|
|
|
—
|
|
|
—
|
|
|
9,774
|
|
|
Property and equipment, net
|
1,056,343
|
|
|
5,806
|
|
|
—
|
|
|
1,062,149
|
|
|
Intercompany receivable
|
20,678
|
|
|
—
|
|
|
(20,678
|
)
|
|
—
|
|
|
Investment in subsidiaries
|
(14,751
|
)
|
|
—
|
|
|
14,751
|
|
|
—
|
|
|
Noncurrent assets
|
4,740
|
|
|
—
|
|
|
—
|
|
|
4,740
|
|
|
Total assets
|
$
|
1,385,284
|
|
|
$
|
5,984
|
|
|
$
|
(5,927
|
)
|
|
$
|
1,385,341
|
|
|
Liabilities and Stockholders' Equity:
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
$
|
49,447
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
49,447
|
|
|
Other current liabilities
|
35,571
|
|
|
—
|
|
|
—
|
|
|
35,571
|
|
|
Intercompany payable
|
—
|
|
|
20,678
|
|
|
(20,678
|
)
|
|
—
|
|
|
Long-term debt
|
711,808
|
|
|
—
|
|
|
—
|
|
|
711,808
|
|
|
Other noncurrent liabilities
|
16,915
|
|
|
57
|
|
|
—
|
|
|
16,972
|
|
|
Stockholders' equity
|
571,543
|
|
|
(14,751
|
)
|
|
14,751
|
|
|
571,543
|
|
|
Total liabilities and stockholders' equity
|
$
|
1,385,284
|
|
|
$
|
5,984
|
|
|
$
|
(5,927
|
)
|
|
$
|
1,385,341
|
|
Condensed Consolidating Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2017
|
|
|
Parent
Issuer
|
|
Guarantor
Subsidiaries
|
|
Intercompany
Eliminations
|
|
Consolidated
|
|
|
(in thousands)
|
|
Operating revenues
|
$
|
67,697
|
|
|
$
|
168
|
|
|
$
|
—
|
|
|
$
|
67,865
|
|
|
Operating expenses
|
(58,053
|
)
|
|
(156
|
)
|
|
—
|
|
|
(58,209
|
)
|
|
General and administrative
|
(12,496
|
)
|
|
—
|
|
|
—
|
|
|
(12,496
|
)
|
|
Interest expense
|
(13,926
|
)
|
|
—
|
|
|
—
|
|
|
(13,926
|
)
|
|
Interest income and other income (expense)
|
(12,076
|
)
|
|
—
|
|
|
—
|
|
|
(12,076
|
)
|
|
Income (loss) before income taxes and equity in earnings of subsidiaries
|
(28,854
|
)
|
|
12
|
|
|
—
|
|
|
(28,842
|
)
|
|
(Provision for) Benefit from income taxes
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Equity in earnings (loss) of subsidiaries
|
12
|
|
|
—
|
|
|
(12
|
)
|
|
—
|
|
|
Net income (loss)
|
$
|
(28,842
|
)
|
|
$
|
12
|
|
|
$
|
(12
|
)
|
|
$
|
(28,842
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2017
|
|
|
Parent
Issuer
|
|
Guarantor
Subsidiaries
|
|
Intercompany
Eliminations
|
|
Consolidated
|
|
|
(in thousands)
|
|
Operating revenues
|
$
|
169,041
|
|
|
$
|
426
|
|
|
$
|
—
|
|
|
$
|
169,467
|
|
|
Operating expenses
|
(167,363
|
)
|
|
(486
|
)
|
|
—
|
|
|
(167,849
|
)
|
|
General and administrative
|
(30,788
|
)
|
|
—
|
|
|
—
|
|
|
(30,788
|
)
|
|
Interest expense
|
(44,014
|
)
|
|
—
|
|
|
—
|
|
|
(44,014
|
)
|
|
Interest income and other income (expense)
|
12,780
|
|
|
—
|
|
|
—
|
|
|
12,780
|
|
|
Income (loss) before income taxes and equity in earnings of subsidiaries
|
(60,344
|
)
|
|
(60
|
)
|
|
—
|
|
|
(60,404
|
)
|
|
(Provision for) benefit from income taxes
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Equity in earnings (loss) of subsidiaries
|
(60
|
)
|
|
—
|
|
|
60
|
|
|
—
|
|
|
Net income (loss)
|
$
|
(60,404
|
)
|
|
$
|
(60
|
)
|
|
$
|
60
|
|
|
$
|
(60,404
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2016
|
|
|
Parent
Issuer
|
|
Guarantor
Subsidiaries
|
|
Intercompany
Eliminations
|
|
Consolidated
|
|
|
(in thousands)
|
|
Operating revenues
|
$
|
50,325
|
|
|
$
|
156
|
|
|
$
|
—
|
|
|
$
|
50,481
|
|
|
Operating expenses
|
(59,498
|
)
|
|
(155
|
)
|
|
—
|
|
|
(59,653
|
)
|
|
General and administrative
|
(9,178
|
)
|
|
—
|
|
|
—
|
|
|
(9,178
|
)
|
|
Interest expense
|
(13,991
|
)
|
|
—
|
|
|
—
|
|
|
(13,991
|
)
|
|
Interest and other income (expense)
|
6,155
|
|
|
—
|
|
|
—
|
|
|
6,155
|
|
|
Income (loss) before income taxes and equity in earnings of subsidiaries
|
(26,187
|
)
|
|
1
|
|
|
—
|
|
|
(26,186
|
)
|
|
(Provision for) Benefit from income taxes
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Equity in earnings of subsidiaries
|
1
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
Net income (loss)
|
$
|
(26,186
|
)
|
|
$
|
1
|
|
|
$
|
(1
|
)
|
|
$
|
(26,186
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2016
|
|
|
Parent
Issuer
|
|
Guarantor
Subsidiaries
|
|
Intercompany
Eliminations
|
|
Consolidated
|
|
|
(in thousands)
|
|
Operating revenues
|
$
|
126,730
|
|
|
$
|
469
|
|
|
$
|
—
|
|
|
$
|
127,199
|
|
|
Operating expenses
|
(172,759
|
)
|
|
(480
|
)
|
|
—
|
|
|
(173,239
|
)
|
|
General and administrative
|
(31,535
|
)
|
|
—
|
|
|
—
|
|
|
(31,535
|
)
|
|
Interest expense
|
(45,160
|
)
|
|
—
|
|
|
—
|
|
|
(45,160
|
)
|
|
Interest and other income (expense)
|
1,634
|
|
|
—
|
|
|
—
|
|
|
1,634
|
|
|
Income (loss) before income taxes and equity in earnings of subsidiaries
|
(121,090
|
)
|
|
(11
|
)
|
|
—
|
|
|
(121,101
|
)
|
|
(Provision for) benefit from income taxes
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Equity in earnings (loss) of subsidiaries
|
(11
|
)
|
|
—
|
|
|
11
|
|
|
—
|
|
|
Net income (loss)
|
$
|
(121,101
|
)
|
|
$
|
(11
|
)
|
|
$
|
11
|
|
|
$
|
(121,101
|
)
|
Condensed Consolidating Statements of Comprehensive Income (Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2017
|
|
|
Parent
Issuer
|
|
Guarantor
Subsidiaries
|
|
Intercompany
Eliminations
|
|
Consolidated
|
|
|
(in thousands)
|
|
Net income (loss)
|
$
|
(28,842
|
)
|
|
$
|
12
|
|
|
$
|
(12
|
)
|
|
$
|
(28,842
|
)
|
|
Other comprehensive income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Comprehensive income (loss)
|
$
|
(28,842
|
)
|
|
$
|
12
|
|
|
$
|
(12
|
)
|
|
$
|
(28,842
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2017
|
|
|
Parent
Issuer
|
|
Guarantor
Subsidiaries
|
|
Intercompany
Eliminations
|
|
Consolidated
|
|
|
(in thousands)
|
|
Net income (loss)
|
$
|
(60,404
|
)
|
|
$
|
(60
|
)
|
|
$
|
60
|
|
|
$
|
(60,404
|
)
|
|
Other comprehensive income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Comprehensive income (loss)
|
$
|
(60,404
|
)
|
|
$
|
(60
|
)
|
|
$
|
60
|
|
|
$
|
(60,404
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2016
|
|
|
Parent
Issuer
|
|
Guarantor
Subsidiaries
|
|
Intercompany
Eliminations
|
|
Consolidated
|
|
|
(in thousands)
|
|
Net income (loss)
|
$
|
(26,186
|
)
|
|
$
|
1
|
|
|
$
|
(1
|
)
|
|
$
|
(26,186
|
)
|
|
Other comprehensive income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Comprehensive income (loss)
|
$
|
(26,186
|
)
|
|
$
|
1
|
|
|
$
|
(1
|
)
|
|
$
|
(26,186
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2016
|
|
|
Parent
Issuer
|
|
Guarantor
Subsidiaries
|
|
Intercompany
Eliminations
|
|
Consolidated
|
|
|
(in thousands)
|
|
Net income (loss)
|
$
|
(121,101
|
)
|
|
$
|
(11
|
)
|
|
$
|
11
|
|
|
$
|
(121,101
|
)
|
|
Other comprehensive income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Comprehensive income (loss)
|
$
|
(121,101
|
)
|
|
$
|
(11
|
)
|
|
$
|
11
|
|
|
$
|
(121,101
|
)
|
Condensed Consolidating Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2017
|
|
|
Parent
Issuer
|
|
Guarantor
Subsidiaries
|
|
Intercompany
Eliminations
|
|
Consolidated
|
|
|
(in thousands)
|
|
Cash flows from operating activities
|
$
|
95,009
|
|
|
$
|
374
|
|
|
$
|
—
|
|
|
$
|
95,383
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
Additions to oil and gas properties, including acquisitions
|
(160,788
|
)
|
|
—
|
|
|
—
|
|
|
(160,788
|
)
|
|
Additions to furniture, fixtures and other
|
(268
|
)
|
|
—
|
|
|
—
|
|
|
(268
|
)
|
|
Proceeds from sale of properties and other investing activities
|
(712
|
)
|
|
—
|
|
|
—
|
|
|
(712
|
)
|
|
Intercompany transfers
|
374
|
|
|
—
|
|
|
(374
|
)
|
|
—
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
Proceeds from debt
|
275,000
|
|
|
—
|
|
|
—
|
|
|
275,000
|
|
|
Principal payments on debt
|
(322,228
|
)
|
|
—
|
|
|
—
|
|
|
(322,228
|
)
|
|
Proceeds from sale of common stock, net of offering costs
|
(298
|
)
|
|
—
|
|
|
—
|
|
|
(298
|
)
|
|
Intercompany transfers
|
—
|
|
|
(374
|
)
|
|
374
|
|
|
—
|
|
|
Other financing activities
|
(6,045
|
)
|
|
—
|
|
|
—
|
|
|
(6,045
|
)
|
|
Change in cash and cash equivalents
|
(119,956
|
)
|
|
—
|
|
|
—
|
|
|
(119,956
|
)
|
|
Beginning cash and cash equivalents
|
275,841
|
|
|
—
|
|
|
—
|
|
|
275,841
|
|
|
Ending cash and cash equivalents
|
$
|
155,885
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
155,885
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2016
|
|
|
Parent
Issuer
|
|
Guarantor
Subsidiaries
|
|
Intercompany
Eliminations
|
|
Consolidated
|
|
|
(in thousands)
|
|
Cash flows from operating activities
|
$
|
115,695
|
|
|
$
|
512
|
|
|
$
|
—
|
|
|
$
|
116,207
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
Additions to oil and gas properties, including acquisitions
|
(93,686
|
)
|
|
(18
|
)
|
|
—
|
|
|
(93,704
|
)
|
|
Additions to furniture, fixtures and other
|
(1,184
|
)
|
|
—
|
|
|
—
|
|
|
(1,184
|
)
|
|
Proceeds from sale of properties and other investing activities
|
25,571
|
|
|
—
|
|
|
—
|
|
|
25,571
|
|
|
Intercompany transfers
|
494
|
|
|
—
|
|
|
(494
|
)
|
|
—
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
Principal payments on debt
|
(329
|
)
|
|
—
|
|
|
—
|
|
|
(329
|
)
|
|
Intercompany transfers
|
—
|
|
|
(494
|
)
|
|
494
|
|
|
—
|
|
|
Other financing activities
|
(1,134
|
)
|
|
—
|
|
|
—
|
|
|
(1,134
|
)
|
|
Change in cash and cash equivalents
|
45,427
|
|
|
—
|
|
|
—
|
|
|
45,427
|
|
|
Beginning cash and cash equivalents
|
128,836
|
|
|
—
|
|
|
—
|
|
|
128,836
|
|
|
Ending cash and cash equivalents
|
$
|
174,263
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
174,263
|
|
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.
This Quarterly Report on Form 10-Q contains "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934, as amended, and the Private Securities Litigation Reform Act of 1995. Forward-looking statements include statements as to future plans, estimates, beliefs and expected performance of Bill Barrett Corporation (the "Company", "we", "us" or "our"). Forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, risks and uncertainties relating to:
|
|
|
|
•
|
potential failure to achieve expected production from existing and future exploration or development projects or acquisitions;
|
|
|
|
|
•
|
volatility of market prices received for oil, natural gas and natural gas liquids ("NGLs"), and the risk of a prolonged period of depressed prices;
|
|
|
|
|
•
|
declines in the values of our oil and natural gas properties resulting in impairments;
|
|
|
|
|
•
|
reduction of proved undeveloped reserves due to failure to develop within the five-year development window defined by the Securities and Exchange Commission;
|
|
|
|
|
•
|
derivative and hedging activities;
|
|
|
|
|
•
|
legislative, judicial or regulatory changes including initiatives to impose standard setbacks from occupied structures and other sensitive areas, initiatives to give local governmental authorities the ability to further regulate or to ban oil and gas development activities within their boundaries, and initiatives related to drilling and completion techniques such as hydraulic fracturing;
|
|
|
|
|
•
|
solely operating in the Rocky Mountain region;
|
|
|
|
|
•
|
compliance with environmental and other regulations;
|
|
|
|
|
•
|
economic and competitive conditions;
|
|
|
|
|
•
|
occurrence of property divestitures or acquisitions;
|
|
|
|
|
•
|
possible inability to complete planned dispositions;
|
|
|
|
|
•
|
costs and availability of third party facilities for gathering, processing, refining and transportation;
|
|
|
|
|
•
|
future processing volumes and pipeline throughput;
|
|
|
|
|
•
|
impact of health and safety issues on operations;
|
|
|
|
|
•
|
operational risks, including industrial accidents and natural disasters;
|
|
|
|
|
•
|
reductions in the borrowing base under our amended revolving credit facility (the "Amended Credit Facility");
|
|
|
|
|
•
|
debt and equity market conditions and availability of capital;
|
|
|
|
|
•
|
ability to receive drilling and other permits, regulatory approvals and required surface access and rights of way;
|
|
|
|
|
•
|
higher than expected costs and expenses including production, drilling and well equipment costs;
|
|
|
|
|
•
|
changes in estimates of proved reserves;
|
|
|
|
|
•
|
the potential for production decline rates from our wells, or drilling and related costs, to be greater than we expect;
|
|
|
|
|
•
|
ability to replace natural production declines with acquisitions, new drilling or recompletion activities;
|
|
|
|
|
•
|
exploration risks such as drilling unsuccessful wells;
|
|
|
|
|
•
|
capital expenditures and contractual obligations;
|
|
|
|
|
•
|
liabilities resulting from litigation concerning alleged damages related to environmental issues, pollution, contamination, personal injury, royalties, marketing, title to properties, validity of leases, or other matters that may not be covered by an effective indemnity or insurance;
|
|
|
|
|
•
|
changes in tax laws and statutory tax rates; and
|
|
|
|
|
•
|
other uncertainties, including those factors discussed below and in our Annual Report on Form 10-K for the year ended
December 31, 2016
under the headings "Cautionary Note Regarding Forward-Looking Statements" and "Risk Factors" and in Item 1A, "Risk Factors" of this Quarterly Report on Form 10-Q, all of which are difficult to predict.
|
In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. Readers should not place undue reliance on these forward-looking statements, which reflect management's views only as of the date hereof. Other than as required under the securities laws, we do not undertake any obligation to update any forward-looking statements whether as a result of changes in internal estimates or expectations, new information, subsequent events or circumstances or otherwise.
Overview
We develop oil and natural gas in the Rocky Mountain region of the United States. We seek to build stockholder value by delivering profitable growth in cash flow, reserves and production through the development of oil and natural gas assets. In order to deliver profitable growth, we allocate capital to our highest return assets, concentrate expenditures on exploiting our
core assets, maintain capital discipline and optimize operations while upholding high-level standards for health, safety and the environment. Substantially all of our revenues are generated through the sale of oil and natural gas production and NGL recovery at market prices.
We were formed in January 2002 and are incorporated in the State of Delaware. In December 2004, we completed our initial public offering. In December 2016, we completed an additional public offering of our common stock, selling 15,525,000 shares at a price of $7.40 per share. The sale included the full exercise by the underwriters of their option to purchase 2,025,000 shares of common stock.
On April 28, 2017, we issued $275.0 million in aggregate principal amount of 8.75% senior unsecured notes due 2025, at par. We used the net proceeds from the offering, together with available cash on hand, to fund the redemption and repurchase of all of our outstanding 7.625% Senior Notes due 2019 and all of our outstanding 5% Convertible Senior Notes due 2028.
We are committed to developing and producing oil and natural gas in a responsible and safe manner. Our employees work diligently with regulatory agencies, as well as environmental, wildlife and community organizations, to ensure that exploration and development activities meet stakeholders' expectations and regulatory requirements.
Future acquisitions or dispositions could have a material impact on our financial condition and results of operations by increasing or decreasing our reserves, production and revenues as well as expenses and future capital expenditures. We currently anticipate that we would finance any future acquisitions with available borrowings under our Amended Credit Facility, other indebtedness, sales of properties, and/or the issuance of debt, equity or equity-linked securities. Our prior acquisitions and capital expenditures were financed with a combination of cash on hand, funding from the sale of our equity securities, our Amended Credit Facility, other debt financing and cash flows from operations.
As a result of acquisitions and dispositions of properties, our historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful. In addition, past results are not necessarily indicative of future results.
Commodity prices are inherently volatile and are influenced by many factors outside of our control. As of
October 17, 2017
, we have hedged
747,500
barrels of oil and
920,000
MMbtu of natural gas, or approximately 43% of our expected remaining
2017
production,
2,552,000
barrels of oil and
1,825,000
MMbtu of natural gas for
2018
and
547,500
barrels of oil for 2019 at price levels that provide some economic certainty to our cash flows. We focus our efforts on increasing oil, natural gas and NGLs reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future earnings and cash flows are dependent on our ability to manage our revenues and overall cost structure to a level that allows for profitable production.
We operate in one industry segment, which is the development and production of crude oil, natural gas and NGLs, and all of our operations are conducted in the Rocky Mountain region of the United States. Consequently, we currently report a single reportable segment.
Results of Operations
The following table sets forth selected operating data for the periods indicated:
Three Months Ended
September 30, 2017
Compared with Three Months Ended
September 30, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Increase (Decrease)
|
|
2017
|
|
2016
|
|
Amount
|
|
Percent
|
|
($ in thousands, except per unit data)
|
|
Operating Results:
|
|
|
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
Oil, gas and NGL production
|
$
|
67,175
|
|
|
$
|
50,133
|
|
|
$
|
17,042
|
|
|
34
|
%
|
|
Other operating revenues
|
690
|
|
|
348
|
|
|
342
|
|
|
98
|
%
|
|
Total operating revenues
|
67,865
|
|
|
50,481
|
|
|
17,384
|
|
|
34
|
%
|
|
Operating Expenses
|
|
|
|
|
|
|
|
|
Lease operating expense
|
5,919
|
|
|
4,795
|
|
|
1,124
|
|
|
23
|
%
|
|
Gathering, transportation and processing expense
|
620
|
|
|
472
|
|
|
148
|
|
|
31
|
%
|
|
Production tax expense
|
5,384
|
|
|
3,832
|
|
|
1,552
|
|
|
41
|
%
|
|
Exploration expense
|
18
|
|
|
16
|
|
|
2
|
|
|
13
|
%
|
|
Impairment, dry hole costs and abandonment expense
|
261
|
|
|
974
|
|
|
(713
|
)
|
|
(73
|
)%
|
|
(Gain) loss on sale of properties
|
—
|
|
|
1,914
|
|
|
(1,914
|
)
|
|
*nm
|
|
|
Depreciation, depletion and amortization
|
41,732
|
|
|
43,083
|
|
|
(1,351
|
)
|
|
(3
|
)%
|
|
Unused commitments
|
4,557
|
|
|
4,567
|
|
|
(10
|
)
|
|
—
|
%
|
|
General and administrative expense
(1)
|
12,496
|
|
|
9,178
|
|
|
3,318
|
|
|
36
|
%
|
|
Other operating expense, net
|
(282
|
)
|
|
—
|
|
|
(282
|
)
|
|
*nm
|
|
|
Total operating expenses
|
$
|
70,705
|
|
|
$
|
68,831
|
|
|
$
|
1,874
|
|
|
3
|
%
|
|
Production Data:
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
1,202
|
|
|
1,016
|
|
|
186
|
|
|
18
|
%
|
|
Natural gas (MMcf)
|
2,274
|
|
|
1,734
|
|
|
540
|
|
|
31
|
%
|
|
NGLs (MBbls)
|
339
|
|
|
261
|
|
|
78
|
|
|
30
|
%
|
|
Combined volumes (MBoe)
|
1,920
|
|
|
1,566
|
|
|
354
|
|
|
23
|
%
|
|
Daily combined volumes (Boe/d)
|
20,870
|
|
|
17,022
|
|
|
3,848
|
|
|
23
|
%
|
|
Average Realized Prices Before Hedging:
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
$
|
46.08
|
|
|
$
|
41.92
|
|
|
$
|
4.16
|
|
|
10
|
%
|
|
Natural gas (per Mcf)
|
2.37
|
|
|
2.29
|
|
|
0.08
|
|
|
3
|
%
|
|
NGLs (per Bbl)
|
18.93
|
|
|
13.65
|
|
|
5.28
|
|
|
39
|
%
|
|
Combined (per Boe)
|
34.99
|
|
|
32.02
|
|
|
2.97
|
|
|
9
|
%
|
|
Average Realized Prices with Hedging:
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
$
|
51.86
|
|
|
$
|
61.30
|
|
|
$
|
(9.44
|
)
|
|
(15
|
)%
|
|
Natural gas (per Mcf)
|
2.51
|
|
|
2.71
|
|
|
(0.20
|
)
|
|
(7
|
)%
|
|
NGLs (per Bbl)
|
18.93
|
|
|
13.65
|
|
|
5.28
|
|
|
39
|
%
|
|
Combined (per Boe)
|
38.78
|
|
|
45.06
|
|
|
(6.28
|
)
|
|
(14
|
)%
|
|
Average Costs (per Boe):
|
|
|
|
|
|
|
|
|
Lease operating expense
|
$
|
3.08
|
|
|
$
|
3.06
|
|
|
$
|
0.02
|
|
|
1
|
%
|
|
Gathering, transportation and processing expense
|
0.32
|
|
|
0.30
|
|
|
0.02
|
|
|
7
|
%
|
|
Production tax expense
|
2.80
|
|
|
2.45
|
|
|
0.35
|
|
|
14
|
%
|
|
Depreciation, depletion and amortization
(2)
|
22.52
|
|
|
27.51
|
|
|
(4.99
|
)
|
|
(18
|
)%
|
|
General and administrative expense
(1)
|
6.51
|
|
|
5.86
|
|
|
0.65
|
|
|
11
|
%
|
|
|
|
|
(1)
|
Included in general and administrative expense is long-term cash and equity incentive compensation of
$2.7 million
(or
$1.40
per Boe) and
$2.1 million
(or
$1.37
per Boe) for the three months ended
September 30, 2017
and
2016
, respectively.
|
|
|
|
|
(2)
|
The DD&A rate per Boe excludes production of 67 MBoe associated with our properties that were classified as held for sale in the Uinta Basin, as these were not depleted the month of September 30, 2017.
|
Production Revenues and Volumes
. Production revenues
increased
to
$67.2 million
for the three months ended
September 30, 2017
from
$50.1 million
for the three months ended
September 30, 2016
. The
increase
in production revenues was due to a
23%
increase in production volumes and a
9%
increase in average realized prices before hedging. The increase in production volumes increased production revenues by approximately $12.4 million, while the increase in average realized prices before hedging increased production revenues by approximately $4.7 million.
The
23%
increase in total production from the three months ended
September 30, 2016
to the three months ended
September 30, 2017
was primarily due to a 27% increase in production from the DJ Basin, offset by a 5% decrease in production from the Uinta Oil Program. Additional information concerning production is in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2017
|
|
Three Months Ended September 30, 2016
|
|
% Increase (Decrease)
|
|
|
Oil
|
NGL
|
Natural
Gas
|
Total
|
|
Oil
|
NGL
|
Natural
Gas
|
Total
|
|
Oil
|
NGL
|
Natural
Gas
|
Total
|
|
|
(MBbls)
|
(MBbls)
|
(MMcf)
|
(MBoe)
|
|
(MBbls)
|
(MBbls)
|
(MMcf)
|
(MBoe)
|
|
(MBbls)
|
(MBbls)
|
(MMcf)
|
(MBoe)
|
|
DJ Basin
|
1,005
|
|
335
|
|
2,178
|
|
1,703
|
|
|
827
|
|
252
|
|
1,554
|
|
1,338
|
|
|
22
|
%
|
33
|
%
|
40
|
%
|
27
|
%
|
|
Uinta Oil Program
|
195
|
|
4
|
|
96
|
|
215
|
|
|
188
|
|
9
|
|
174
|
|
226
|
|
|
4
|
%
|
(56
|
)%
|
(45
|
)%
|
(5
|
)%
|
|
Other
|
2
|
|
—
|
|
—
|
|
2
|
|
|
1
|
|
—
|
|
6
|
|
2
|
|
|
100
|
%
|
*nm
|
|
*nm
|
|
—
|
%
|
|
Total
|
1,202
|
|
339
|
|
2,274
|
|
1,920
|
|
|
1,016
|
|
261
|
|
1,734
|
|
1,566
|
|
|
18
|
%
|
30
|
%
|
31
|
%
|
23
|
%
|
Lease Operating Expense ("LOE")
. LOE remained consistent at
$3.08
per Boe for the three months ended
September 30, 2017
compared to
$3.06
per Boe for the three months ended
September 30, 2016
.
Production Tax Expense
. Total production taxes
increased
to
$5.4 million
for the three months ended
September 30, 2017
from
$3.8 million
for the three months ended
September 30, 2016
. The increase is attributable to the 23% increase in production and the 9% increase in averaged realized prices before hedging. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production taxes as a percentage of oil, natural gas and NGL sales before hedging adjustments were 8.0% and 7.6% for the three months ended
September 30, 2017
and
September 30, 2016
, respectively.
Production tax rates vary across the different areas in which we operate. As the proportion of our production changes from area to area, our average production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect for those areas.
Impairment, Dry Hole Costs and Abandonment Expense.
Our impairment, dry hole costs and abandonment expense for the three months ended
September 30, 2017
and
2016
is summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
2017
|
|
2016
|
|
|
(in thousands)
|
|
Dry hole expense
|
$
|
—
|
|
|
$
|
1
|
|
|
Abandonment expense and lease expirations
|
261
|
|
|
973
|
|
|
Total impairment, dry hole costs and abandonment expense
|
$
|
261
|
|
|
$
|
974
|
|
We review our oil and natural gas properties for impairment on a quarterly basis or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected undiscounted future net cash flows of our oil and gas properties using proved and risked probable and possible reserves based on our development plans and best estimate of future production, commodity pricing, reserve risking, gathering and transportation deductions, production tax rates, lease operating expenses and future development costs. We compare such undiscounted future
net cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the undiscounted future net cash flows exceed the carrying amount of the oil and gas properties, no impairment is taken. If the carrying amount of a property exceeds the undiscounted future net cash flows, we will impair the carrying value to fair value based on an analysis of quantitative and qualitative factors existing as of the balance sheet date. We do not believe that the undiscounted future net cash flows of our oil and gas properties represent the applicable market value. The factors used to determine fair value may include, but are not limited to, recent sales prices of comparable properties, indications from marketing activities, the present value of future revenues, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the projected cash flows.
Oil and gas properties are assessed for impairment once they meet the criteria to be classified as held for sale. Assets held for sale are carried at the lower of carrying cost or fair value less costs to sell. The fair value of the assets is determined using a market approach, based on an estimated selling price, as evidenced by current marketing activities, if possible. If an estimated selling price is not available, we utilize the income valuation technique, which involves calculating the present value of future net cash flows, as discussed above. If the carrying amount of the assets exceeds the fair value less costs to sell, an impairment will result to reduce the value of the properties down to fair value less costs to sell.
During the three months ended September 30, 2017, we committed to a plan to sell our remaining assets in the Uinta Basin. Therefore, the related assets and liabilities were classified as held for sale in the Unaudited Consolidated Balance Sheet as of September 30, 2017. We utilized the income valuation technique to determine that the fair value of the assets held for sale was in excess of the asset carrying value as of September 30, 2017.
Unproved oil and gas properties are assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, future plans to develop acreage, recent sales prices of comparable properties and other relevant matters. We generally expect impairments of unproved properties to be more likely to occur in periods of low commodity prices because we will be less likely to devote capital to exploration activities.
Given current and projected future commodity prices, we will continue to review our acreage position and future drilling plans. In addition, we will assess the carrying value of our properties relative to their estimated future net cash flows. Estimated future net cash flows from our properties are based on our aggregate best estimates of future production, commodity pricing, gathering and transportation deducts, production tax rates, lease operating expenses and future development costs as of the balance sheet date.
Our current recoverability test on our existing oil and gas properties as of
September 30, 2017
uses commodity pricing based on market data and a combination of assumptions, which are closely aligned with the assumptions management uses in its budgeting and forecasting process, including adjustments for geographical location and quality differentials as well as other factors that management believes will impact realized prices. The application of this test as of
September 30, 2017
results in a surplus of undiscounted future net cash flows over the carrying amount of our oil and gas properties. If the recoverability test described above would result in the carrying amount exceeding undiscounted future estimated net cash flows, and an impairment is necessary, we would reduce the carrying value to fair value. If future commodity prices assumed in the recoverability test are not realized, we could incur a significant impairment. However, there are many other variables besides oil price that are included in the recoverability test that could impact the results.
Depreciation, Depletion and Amortization ("DD&A").
DD&A
decreased
to
$41.7 million
for the three months ended
September 30, 2017
compared with
$43.1 million
for the three months ended
September 30, 2016
. The
decrease
of
$1.4 million
was a result of an
18%
decrease
in the DD&A rate, offset by a
23%
increase in production volumes for the three months ended
September 30, 2017
compared with the three months ended
September 30, 2016
. The decrease in the DD&A rate accounted for an $11.1 million decrease in DD&A expense, while the increase in production accounted for a $9.7 million increase in DD&A expense.
Under successful efforts accounting, depletion expense is calculated on a field-by-field basis based on geologic and reservoir delineation using the unit-of-production method. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field determine a depletion rate for current production. For the three months ended
September 30, 2017
, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of
$22.52
per Boe compared with
$27.51
per Boe for the three months ended
September 30, 2016
.
Unused Commitments.
During March 2010, we entered into two firm natural gas pipeline transportation contracts to provide a guaranteed outlet for production from the West Tavaputs area of the Uinta Basin and the Gibson Gulch area of the Piceance Basin. These transportation contracts were not included in the sales of these assets in December 2013 and September 2014, respectively. Both firm transportation contracts require the pipeline to provide transportation capacity and require us to pay transportation charges regardless of the amount of pipeline capacity utilized. The agreements expire July 31, 2021. Unused commitments expense for each of the three months ended
September 30, 2017
and
September 30, 2016
consisted of
$4.6 million
related to these contracts.
General and Administrative Expense.
General and administrative expense
increased
to
$12.5 million
for the three months ended
September 30, 2017
from
$9.2 million
for the three months ended
September 30, 2016
primarily due to an increase in variable employee compensation related to performance, legal and professional services fees.
Included in general and administrative expense is long-term cash and equity incentive compensation of
$2.7 million
and
$2.1 million
for the three months ended
September 30, 2017
and
2016
, respectively. The components of long-term cash and equity incentive compensation for the three months ended
September 30, 2017
and
2016
are shown in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
2017
|
|
2016
|
|
|
(in thousands)
|
|
Stock options and nonvested common stock
|
$
|
1,434
|
|
|
$
|
1,733
|
|
|
Nonvested common stock units
|
174
|
|
|
165
|
|
|
Performance cash units
(1)
|
1,073
|
|
|
242
|
|
|
Total
|
$
|
2,681
|
|
|
$
|
2,140
|
|
|
|
|
|
(1)
|
The performance cash units will be settled in cash for the performance metrics that are met.
|
Commodity Derivative Gain (Loss).
Commodity derivative gain (loss)
was a
loss
of
$12.4 million
for the three months ended
September 30, 2017
compared with a
gain
of
$6.1 million
for the three months ended
September 30, 2016
. The gain or loss on commodity derivatives is related to fluctuations of oil and natural gas future pricing compared to actual pricing of commodity hedges in place as of
September 30, 2017
and
2016
or during the periods then ended.
The table below summarizes our commodity derivative gains and losses that were recognized in the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
2017
|
|
2016
|
|
|
(in thousands)
|
|
Realized gain (loss) on derivatives
(1)
|
$
|
7,263
|
|
|
$
|
20,412
|
|
|
Prior year unrealized (gain) loss transferred to realized (gain) loss
(1)
|
(1,036
|
)
|
|
(21,706
|
)
|
|
Unrealized gain (loss) on derivatives
(1)
|
(18,635
|
)
|
|
7,348
|
|
|
Total commodity derivative gain (loss)
|
$
|
(12,408
|
)
|
|
$
|
6,054
|
|
|
|
|
|
(1)
|
Realized and unrealized gains and losses on commodity derivatives are presented herein as separate line items but are combined for a total commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the realized and unrealized commodity derivative gains and losses is useful because the realized cash settlement portion provides a better understanding of our hedge position. We also believe that this disclosure allows for a more accurate comparison to our peers.
|
During the three months ended
September 30, 2017
, approximately
55%
of our oil volumes and
39%
of our natural gas volumes were subject to financial hedges, which resulted in an
increase
in oil income of
$6.9 million
and natural gas income of
$0.3 million
after settlements for all commodity derivatives. During the three months ended
September 30, 2016
, approximately
66%
of our oil volumes and
27%
of our natural gas volumes were subject to financial hedges, which resulted in an
increase
in oil income of
$19.7 million
and natural gas income of
$0.7 million
after settlements for all commodity derivatives.
Income Tax (Expense) Benefit
. We recorded an additional valuation allowance of $10.9 million and $10.0 million for the three months ended
September 30, 2017
and
2016
, respectively, against our deferred tax asset balance, which reduced our effective tax rate to zero. In regard to the valuation allowance recorded against our deferred tax asset balance we considered all available evidence in assessing the need for a valuation allowance. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. We continue to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized prior to their expiration. Additionally, for both the
2017
and
2016
periods, our effective tax rate differs from the federal statutory rate as a result of recording permanent differences for stock-based compensation expense, lobbying and political contributions, and officer compensation as well as the effect of state income taxes.
Nine
Months Ended
September 30, 2017
Compared with
Nine
Months Ended
September 30, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
Increase (Decrease)
|
|
2017
|
|
2016
|
|
Amount
|
|
Percent
|
|
($ in thousands, except per unit data)
|
|
Operating Results:
|
|
|
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
Oil, gas and NGL production
|
$
|
168,541
|
|
|
$
|
126,279
|
|
|
$
|
42,262
|
|
|
33
|
%
|
|
Other operating revenues
|
926
|
|
|
920
|
|
|
6
|
|
|
1
|
%
|
|
Total operating revenues
|
169,467
|
|
|
127,199
|
|
|
42,268
|
|
|
33
|
%
|
|
Operating Expenses
|
|
|
|
|
|
|
|
|
Lease operating expense
|
17,287
|
|
|
22,101
|
|
|
(4,814
|
)
|
|
(22
|
)%
|
|
Gathering, transportation and processing expense
|
1,644
|
|
|
1,871
|
|
|
(227
|
)
|
|
(12
|
)%
|
|
Production tax expense
|
9,140
|
|
|
7,037
|
|
|
2,103
|
|
|
30
|
%
|
|
Exploration expense
|
48
|
|
|
64
|
|
|
(16
|
)
|
|
(25
|
)%
|
|
Impairment, dry hole costs and abandonment expense
|
8,336
|
|
|
1,766
|
|
|
6,570
|
|
|
*nm
|
|
|
(Gain) loss on sale of properties
|
(92
|
)
|
|
1,206
|
|
|
(1,298
|
)
|
|
108
|
%
|
|
Depreciation, depletion and amortization
|
119,409
|
|
|
125,491
|
|
|
(6,082
|
)
|
|
(5
|
)%
|
|
Unused commitments
|
13,687
|
|
|
13,703
|
|
|
(16
|
)
|
|
—
|
%
|
|
General and administrative expense
(1)
|
30,788
|
|
|
31,535
|
|
|
(747
|
)
|
|
(2
|
)%
|
|
Other operating expenses, net
|
(1,610
|
)
|
|
—
|
|
|
(1,610
|
)
|
|
*nm
|
|
|
Total operating expenses
|
$
|
198,637
|
|
|
$
|
204,774
|
|
|
$
|
(6,137
|
)
|
|
(3
|
)%
|
|
Production Data:
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
2,929
|
|
|
2,925
|
|
|
4
|
|
|
—
|
%
|
|
Natural gas (MMcf)
|
6,084
|
|
|
5,298
|
|
|
786
|
|
|
15
|
%
|
|
NGLs (MBbls)
|
936
|
|
|
732
|
|
|
204
|
|
|
28
|
%
|
|
Combined volumes (MBoe)
|
4,879
|
|
|
4,540
|
|
|
339
|
|
|
7
|
%
|
|
Daily combined volumes (Boe/d)
|
17,872
|
|
|
16,569
|
|
|
1,303
|
|
|
7
|
%
|
|
Average Realized Prices Before Hedging:
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
$
|
46.52
|
|
|
$
|
36.88
|
|
|
$
|
9.64
|
|
|
26
|
%
|
|
Natural gas (per Mcf)
|
2.48
|
|
|
1.81
|
|
|
0.67
|
|
|
37
|
%
|
|
NGLs (per Bbl)
|
18.40
|
|
|
12.05
|
|
|
6.35
|
|
|
53
|
%
|
|
Combined (per Boe)
|
34.54
|
|
|
27.82
|
|
|
6.72
|
|
|
24
|
%
|
|
Average Realized Prices with Hedging:
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
$
|
52.18
|
|
|
$
|
62.74
|
|
|
$
|
(10.56
|
)
|
|
(17
|
)%
|
|
Natural gas (per Mcf)
|
2.56
|
|
|
2.34
|
|
|
0.22
|
|
|
9
|
%
|
|
NGLs (per Bbl)
|
18.40
|
|
|
12.05
|
|
|
6.35
|
|
|
53
|
%
|
|
Combined (per Boe)
|
38.04
|
|
|
45.09
|
|
|
(7.05
|
)
|
|
(16
|
)%
|
|
Average Costs (per Boe):
|
|
|
|
|
|
|
|
|
Lease operating expense
|
$
|
3.54
|
|
|
$
|
4.87
|
|
|
$
|
(1.33
|
)
|
|
(27
|
)%
|
|
Gathering, transportation and processing expense
|
0.34
|
|
|
0.41
|
|
|
(0.07
|
)
|
|
(17
|
)%
|
|
Production tax expense
|
1.87
|
|
|
1.55
|
|
|
0.32
|
|
|
21
|
%
|
|
Depreciation, depletion and amortization
(2)
|
24.81
|
|
|
27.64
|
|
|
(2.83
|
)
|
|
(10
|
)%
|
|
General and administrative expense
(1)
|
6.31
|
|
|
6.95
|
|
|
(0.64
|
)
|
|
(9
|
)%
|
|
|
|
|
(1)
|
Included in general and administrative expense is long-term cash and equity incentive compensation of
$5.5 million
(or
$1.12
per Boe) and
$8.7 million
(or
$1.91
per Boe) for the
nine
months ended
September 30, 2017
and
2016
, respectively.
|
|
|
|
|
(2)
|
The DD&A rate per Boe excludes production of 67 MBoe associated with our properties that were classified as held for sale in the Uinta Basin, as these were not depleted the month of September 30, 2017.
|
Production Revenues and Volumes
. Production revenues
increased
to
$168.5 million
for the
nine
months ended
September 30, 2017
from
$126.3 million
for the
nine
months ended
September 30, 2016
. The
increase
in production revenues was due to a
24%
increase in average realized prices before hedging and a
7%
increase
in production volumes. The increase in average realized prices before hedging increased production revenues by approximately $30.5 million, while the
increase
in production volumes increased production revenues by approximately $11.7 million.
The
7%
increase
in total production from the
nine
months ended
September 30, 2016
to the
nine
months ended
September 30, 2017
was primarily due to a 16% increase in the DJ Basin as a result of new wells placed into production, offset by a 31% decrease in production from the Uinta Oil Program primarily due to the sale of certain non-core Uinta Oil Program assets during July 2016. Additional information concerning production is set forth in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2017
|
|
Nine Months Ended September 30, 2016
|
|
% Increase (Decrease)
|
|
|
Oil
|
NGL
|
Natural
Gas
|
Total
|
|
Oil
|
NGL
|
Natural
Gas
|
Total
|
|
Oil
|
NGL
|
Natural
Gas
|
Total
|
|
|
(MBbls)
|
(MBbls)
|
(MMcf)
|
(MBoe)
|
|
(MBbls)
|
(MBbls)
|
(MMcf)
|
(MBoe)
|
|
(MBbls)
|
(MBbls)
|
(MMcf)
|
(MBoe)
|
|
DJ Basin
|
2,399
|
|
927
|
|
5,814
|
|
4,295
|
|
|
2,247
|
|
693
|
|
4,500
|
|
3,690
|
|
|
7
|
%
|
34
|
%
|
29
|
%
|
16
|
%
|
|
Uinta Oil Program
|
526
|
|
9
|
|
258
|
|
578
|
|
|
674
|
|
37
|
|
762
|
|
838
|
|
|
(22
|
)%
|
(76
|
)%
|
(66
|
)%
|
(31
|
)%
|
|
Other
|
4
|
|
—
|
|
12
|
|
6
|
|
|
4
|
|
2
|
|
36
|
|
12
|
|
|
—
|
%
|
*nm
|
|
(67
|
)%
|
(50
|
)%
|
|
Total
|
2,929
|
|
936
|
|
6,084
|
|
4,879
|
|
|
2,925
|
|
732
|
|
5,298
|
|
4,540
|
|
|
—
|
%
|
28
|
%
|
15
|
%
|
7
|
%
|
Lease Operating Expense
. LOE
decreased
to
$3.54
per Boe for the
nine
months ended
September 30, 2017
from
$4.87
per Boe for the
nine
months ended
September 30, 2016
. The decrease per Boe for the
nine
months ended
September 30, 2017
compared with the
nine
months ended
September 30, 2016
is primarily related to operational efficiencies and sales of certain non-core assets in the Uinta Oil Program during July 2016, which had relatively high LOE costs on a per Boe basis.
Production Tax Expense
. Total production taxes
increased
to
$9.1 million
for the
nine
months ended
September 30, 2017
from
$7.0 million
for the
nine
months ended
September 30, 2016
. The increase is attributable to the 24% increase in average realized prices before hedging and the 7% increase in production. Production tax expense for both periods included an annual true-up of Colorado ad valorem tax based on actual assessments and a true-up of the Colorado severance tax. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Excluding the ad valorem and severance tax adjustments, production taxes as a percentage of oil, natural gas and NGL sales were 7.2% and 7.3% for the
nine
months ended
September 30, 2017
and
September 30, 2016
, respectively.
Production tax rates vary across the different areas in which we operate. As the proportion of our production changes from area to area, our average production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect for those areas.
Impairment, Dry Hole Costs and Abandonment Expense.
Our impairment, dry hole costs and abandonment expense for the
nine
months ended
September 30, 2017
and
2016
are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
2017
|
|
2016
|
|
|
(in thousands)
|
|
Impairment of unproved oil and gas properties
(1)
|
$
|
8,010
|
|
|
$
|
183
|
|
|
Dry hole expense
|
—
|
|
|
71
|
|
|
Abandonment expense and lease expirations
|
326
|
|
|
1,512
|
|
|
Total impairment, dry hole costs and abandonment expense
|
$
|
8,336
|
|
|
$
|
1,766
|
|
|
|
|
|
(1)
|
We recognized a non-cash impairment charge associated with unproved oil and gas properties in the Cottonwood Gulch area of the Piceance Basin during the nine months ended September 30, 2017. We have no current plan to develop this acreage.
|
We review our oil and natural gas properties for impairment on a quarterly basis or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected undiscounted future net cash flows of our oil and gas properties using proved and risked probable and possible reserves based on our development plans and best estimate of future production, commodity pricing, reserve risking, gathering and transportation deductions, production tax rates, lease operating expenses and future development costs. We compare such undiscounted future net cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the undiscounted future net cash flows exceed the carrying amount of the oil and gas properties, no impairment is taken. If the carrying amount of a property exceeds the undiscounted future net cash flows, we will impair the carrying value to fair value based on an analysis of quantitative and qualitative factors existing as of the balance sheet date. We do not believe that the undiscounted future net cash flows of our oil and gas properties represent the applicable market value. The factors used to determine fair value may include, but are not limited to, recent sales prices of comparable properties, indications from marketing activities, the present value of future revenues, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the projected cash flows.
Oil and gas properties are assessed for impairment once they meet the criteria to be classified as held for sale. Assets held for sale are carried at the lower of carrying cost or fair value less costs to sell. The fair value of the assets is determined using a market approach, based on an estimated selling price, as evidenced by current marketing activities, if possible. If an estimated selling price is not available, we utilize the income valuation technique, which involves calculating the present value of future net cash flows, as discussed above. If the carrying amount of the assets exceeds the fair value less costs to sell, an impairment will result to reduce the value of the properties down to fair value less costs to sell.
During the three months ended September 30, 2017, we committed to a plan to sell our remaining assets in the Uinta Basin. Therefore, the related assets and liabilities were classified as held for sale in the Unaudited Consolidated Balance Sheet as of September 30, 2017. We utilized the income valuation technique to determine that the fair value of the assets held for sale was in excess of the asset carrying value as of September 30, 2017.
Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, future plans to develop acreage, recent sales prices of comparable properties and other relevant matters. We generally expect impairments of unproved properties to be more likely to occur in periods of low commodity prices because we will be less likely to devote capital to exploration activities.
Given current and projected future commodity prices, we will continue to review our acreage position and future drilling plans. In addition, we will assess the carrying value of our properties relative to their estimated future net cash flows. Estimated future net cash flows from our properties are based on our aggregate best estimates of future production, commodity pricing, gathering and transportation deducts, production tax rates, lease operating expenses and future development costs as of the balance sheet date.
Our current recoverability test on our existing oil and gas properties as of
September 30, 2017
uses commodity pricing based on market data and a combination of assumptions, which are closely aligned with the assumptions management uses in its budgeting and forecasting process, including adjustments for geographical location and quality differentials as well as other factors that management believes will impact realized prices. The application of this test as of
September 30, 2017
results in a surplus of undiscounted future net cash flows over the carrying amount of our oil and gas properties. If the recoverability test described above would result in the carrying amount exceeding undiscounted future estimated net cash flows, and an impairment is necessary, we would reduce the carrying value to fair value. If future commodity prices assumed in the recoverability test are not realized, we could incur a significant impairment. However, there are many other variables besides oil price that are included in the recoverability test that could impact the results.
Depreciation, Depletion and Amortization.
DD&A
decreased
to
$119.4 million
for the
nine
months ended
September 30, 2017
compared with
$125.5 million
for the
nine
months ended
September 30, 2016
. The
decrease
of
$6.1 million
was a result of a
10%
decrease
in the DD&A rate, offset by a
7%
increase
in production for the
nine
months ended
September 30, 2017
compared with the
nine
months ended
September 30, 2016
. The decrease in the DD&A rate accounted for a $15.5 million decrease in DD&A expense, while the increase in production accounted for a $9.4 million increase in DD&A expense.
Under successful efforts accounting, depletion expense is calculated on a field-by-field basis based on geologic and reservoir delineation using the unit-of-production method. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field determine a depletion rate for current production. For the
nine
months ended
September 30, 2017
, the relationship of capital expenditures, proved reserves and production from
certain producing fields yielded a depletion rate of
$24.81
per Boe compared with
$27.64
per Boe for the
nine
months ended
September 30, 2016
.
Unused Commitments.
During March 2010, we entered into two firm natural gas pipeline transportation contracts to provide a guaranteed outlet for production from the West Tavaputs area of the Uinta Basin and the Gibson Gulch area of the Piceance Basin. These transportation contracts were not included in the sales of these assets in December 2013 and September 2014, respectively. Both firm transportation contracts require the pipeline to provide transportation capacity and require us to pay monthly transportation charges regardless of the amount of pipeline capacity utilized. The agreements expire July 31, 2021. Unused commitments expense for each of the
nine
months ended
September 30, 2017
and 2016 consisted of
$13.7 million
related to these contracts.
General and Administrative Expense.
General and administrative expense
decreased
to
$30.8 million
for the
nine
months ended
September 30, 2017
from
$31.5 million
for the
nine
months ended
September 30, 2016
primarily due to a decrease in long-term cash and equity compensation discussed below, offset by an increase in variable employee compensation related to performance, legal and professional services fees.
Included in general and administrative expense is long-term cash and equity incentive compensation of
$5.5 million
and
$8.7 million
for the
nine
months ended
September 30, 2017
and
2016
, respectively. The components of long-term cash and equity incentive compensation for the
nine
months ended
September 30, 2017
and
2016
are shown in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
2017
|
|
2016
|
|
|
(in thousands)
|
|
Stock options and nonvested common stock
|
$
|
4,995
|
|
|
$
|
6,852
|
|
|
Nonvested common stock units
|
516
|
|
|
711
|
|
|
Performance cash units
(1)(2)
|
(27
|
)
|
|
1,088
|
|
|
Total
|
$
|
5,484
|
|
|
$
|
8,651
|
|
|
|
|
|
(1)
|
The performance cash units will be settled in cash for the performance metrics that are met.
|
|
|
|
|
(2)
|
The performance cash units are accounted for as liability awards and fair valued at each reporting date. The weighted average fair value share price decreased from
$8.89
as of
December 31, 2016
to
$4.29
as of
September 30, 2017
.
|
Commodity Derivative Gain (Loss).
Commodity derivative gain (loss)
was a
gain
of
$19.7 million
for the
nine
months ended
September 30, 2017
compared with a
loss
of
$7.3 million
for the
nine
months ended
September 30, 2016
. The gain or loss on commodity derivatives is related to fluctuations of oil and natural gas future pricing compared to actual pricing of commodity hedges in place as of
September 30, 2017
and
2016
and during the periods then ended.
The table below summarizes our commodity derivative gains and losses that were recognized in the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
2017
|
|
2016
|
|
|
(in thousands)
|
|
Realized gain (loss) on derivatives
(1)
|
$
|
17,062
|
|
|
$
|
78,417
|
|
|
Prior year unrealized (gain) loss transferred to realized (gain) loss
(1)
|
(2,114
|
)
|
|
(79,055
|
)
|
|
Unrealized gain (loss) on derivatives
(1)
|
4,706
|
|
|
(6,620
|
)
|
|
Total commodity derivative gain (loss)
|
$
|
19,654
|
|
|
$
|
(7,258
|
)
|
|
|
|
|
(1)
|
Realized and unrealized gains and losses on commodity derivatives are presented in the table as separate line items but are combined for a total commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the realized and unrealized commodity derivative gains and losses is useful because the realized cash settlement portion provides a better understanding of our hedge position. We also believe that this disclosure allows for a more accurate comparison to our peers.
|
During the
nine
months ended
September 30, 2017
, approximately
63%
of our oil volumes and
43%
of our natural gas volumes were subject to financial hedges, which resulted in
increased
oil income of
$16.6 million
and natural gas income of
$0.5 million
after settlements for all commodity derivatives. During the
nine
months ended
September 30, 2016
, approximately
68%
of our oil volumes and
25%
of our natural gas volumes were subject to financial hedges, which resulted in increased oil income of
$75.6 million
and natural gas income of
$2.8 million
after settlements for all commodity derivatives.
Income Tax (Expense) Benefit
. We recorded an additional valuation allowance of $22.9 million and $45.8 million for the
nine
months ended
September 30, 2017
and
2016
, respectively, against our deferred tax asset balance, which reduced our effective tax rate to zero. We consider all available evidence in assessing the need for recording a valuation allowance. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. We continue to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforward, credits and other deferred tax assets will be utilized prior to their expiration. Additionally, for both the
nine
months ended
September 30, 2017
and
2016
, our effective tax rate before valuation allowance differs from the federal statutory rate because of recording permanent differences for stock-based compensation expense, lobbying and political contributions, and officer compensation as well as state income tax expense.
Capital Resources and Liquidity
Our primary sources of liquidity since our formation in January 2002 have been net cash provided by operating activities, sales and other issuances of equity and debt securities, bank credit facilities, proceeds from sale-leasebacks, joint exploration agreements and sales of interests in properties. Our primary use of capital has been for the development, exploration and acquisition of oil and natural gas properties. As we pursue profitable reserves and production growth, we continually monitor the capital resources, including potential issuances of equity and debt securities, available to us to meet our future financial obligations, fund planned capital expenditure activities and ensure adequate liquidity. Our future success in growing proved reserves and production will be highly dependent on capital resources available to us and our success in finding or acquiring additional reserves. We believe that we have sufficient liquidity available to us from cash on hand, cash flows from operations and under our Amended Credit Facility for our planned uses of capital for the remainder of
2017
and 2018. However, we expect to pursue opportunities to further improve our liquidity position through capital markets or other transactions, such as additional property dispositions, if we believe conditions to be favorable. During the three months ended September 30, 2017,
we committed to a plan to sell our remaining assets in the Uinta Basin. The proceeds from a sale of the Uinta Basin properties will be used to fund a portion of our 2018 capital expenditures. However, the closing of such a sale, the timing of closing and the proceeds to us are uncertain.
At
September 30, 2017
, we had cash and cash equivalents of
$155.9 million
and no amounts outstanding under our Amended Credit Facility. At
December 31, 2016
, we had cash and cash equivalents of
$275.8 million
and no amounts outstanding under our Amended Credit Facility. In October 2017, our borrowing base was re-confirmed at $300.0 million based on proved reserves and the commodity hedge position in place at June 30, 2017. Our effective borrowing capacity is reduced by
$26.0 million
to
$274.0 million
due to an outstanding irrevocable letter of credit related to a firm transportation agreement. The borrowing base is dependent on our proved reserves and hedge position and is calculated using future commodity pricing provided by our lenders, and may be adjusted in the future at the sole discretion of the lenders.
Cash Flow from Operating Activities
Net cash provided by operating activities for the
nine
months ended
September 30, 2017
and
2016
was
$95.4 million
and
$116.2 million
, respectively. The decrease in net cash provided by operating activities was primarily due to decreases in cash from derivative settlements offset by an increase in production revenues.
Commodity Hedging Activities
Our operating cash flow is sensitive to many variables, the most significant of which are the prices we receive for the oil, natural gas and NGLs we produce. Prices for these commodities are determined primarily by prevailing market conditions. National and worldwide economic activity and political stability, weather, infrastructure capacity to reach markets, supply levels and other variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict.
To mitigate some of the potential negative impact on cash flow caused by changes in oil, natural gas and NGL prices, we have entered into financial commodity swap contracts to receive fixed prices for a portion of our production. At
September 30,
2017
, we had in place crude oil swaps covering portions of our 2017, 2018 and 2019 production and natural gas swaps covering portions of our 2017 and 2018 production.
In addition to financial contracts, we may at times enter into various physical commodity contracts for the sale of oil and natural gas that cover varying periods of time and have varying pricing provisions. These physical commodity contracts qualify for the normal purchase and normal sales exception and therefore are not subject to hedge or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil, gas and NGL production revenues at the time of settlement.
All derivative instruments, other than those that meet the normal purchase and normal sales exception as mentioned above, are recorded at fair market value and are included in the Unaudited Consolidated Balance Sheets as assets or liabilities. All fair values are adjusted for non-performance risk. All changes in the derivative's fair value are recorded in earnings. These mark-to-market adjustments produce a degree of earnings volatility but have no cash flow impact relative to changes in market prices. Our cash flow is only impacted when the associated derivative instrument contract is settled by making a payment to or receiving a payment from the counterparty.
At
September 30, 2017
, the estimated fair value of all of our commodity derivative instruments, summarized in the following table, was a net
asset
of
$5.7 million
, comprised of current and noncurrent assets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract
|
|
Total
Hedged
Volumes
|
|
Quantity
Type
|
|
Weighted
Average
Fixed
Price
|
|
Index
Price
(1)
|
|
Fair Market
Value
(in thousands)
|
|
Swap Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
747,500
|
|
|
Bbls
|
|
$
|
57.69
|
|
|
WTI
|
|
$
|
4,251
|
|
|
Natural gas
|
|
920,000
|
|
|
MMBtu
|
|
$
|
2.96
|
|
|
NWPL
|
|
216
|
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
2,506,750
|
|
|
Bbls
|
|
$
|
52.47
|
|
|
WTI
|
|
1,471
|
|
|
Natural gas
|
|
1,825,000
|
|
|
MMBtu
|
|
$
|
2.68
|
|
|
NWPL
|
|
109
|
|
|
2019
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
547,500
|
|
|
Bbls
|
|
$
|
50.38
|
|
|
WTI
|
|
(302
|
)
|
|
Total
|
|
|
|
|
|
|
|
|
|
$
|
5,745
|
|
|
|
|
|
(1)
|
WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. NWPL refers to the Northwest Pipeline Corporation price as quoted in Platt's Inside FERC on the first business day of each month.
|
The following table includes all hedges entered into from October 1, 2017 to
October 17, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract
|
|
Total
Hedged
Volumes
|
|
Quantity
Type
|
|
Weighted
Average
Fixed
Price
|
|
Index
Price
|
|
Swap Contracts:
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
|
|
|
|
|
|
|
Oil
|
|
45,250
|
|
|
Bbls
|
|
$
|
52.20
|
|
|
WTI
|
By removing the price volatility from a portion of our oil, natural gas and NGL related revenue, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices.
It is our policy to enter into derivative contracts with counterparties that are lenders in the Amended Credit Facility, affiliates of lenders in the Amended Credit Facility or potential lenders in the Amended Credit Facility. Our derivative contracts are documented using an industry standard contract known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. Master Agreement or other contracts. Typical terms for these contracts include credit support requirements, cross default provisions, termination events and set-off provisions. We are not required to provide any credit support to our counterparties other than cross collateralization with the properties securing the Amended Credit Facility. We have set-off provisions in our derivative contracts with lenders under our Amended Credit Facility which, in the event of a
counterparty default, allow us to set-off amounts owed to the defaulting counterparty under the Amended Credit Facility or other obligations, if any, against monies owed to us under the derivative contracts. Where the counterparty is not a lender under the Amended Credit Facility, we may not be able to set-off amounts owed by us under the Amended Credit Facility, even if such counterparty is an affiliate of a lender under such facility.
Capital Expenditures
Our capital expenditures are summarized in the following tables for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
Basin/Area
|
2017
|
|
2016
|
|
|
(in millions)
|
|
DJ
|
$
|
165.4
|
|
|
$
|
67.0
|
|
|
Uinta Oil Program
|
8.7
|
|
|
1.1
|
|
|
Other
|
0.4
|
|
|
1.4
|
|
|
Total
|
$
|
174.5
|
|
|
$
|
69.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
2017
|
|
2016
|
|
|
(in millions)
|
|
Acquisitions of proved and unproved properties and other real estate
|
$
|
20.2
|
|
|
$
|
2.5
|
|
|
Drilling, development, exploration and exploitation of oil and natural gas properties
|
150.1
|
|
|
60.8
|
|
|
Gathering and compression facilities
|
3.9
|
|
|
5.0
|
|
|
Furniture, fixtures and equipment
|
0.3
|
|
|
1.2
|
|
|
Total
|
$
|
174.5
|
|
|
$
|
69.5
|
|
Our current estimated capital expenditure budget in
2017
is $250.0 million to $270.0 million, with all drilling activities targeting oil. We may adjust capital expenditures as business conditions and operating results warrant. The amount, timing and allocation of capital expenditures are generally discretionary and within our control. If oil, natural gas and NGL prices decline below acceptable levels or costs increase above acceptable levels, we could choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity. We would generally do this by prioritizing capital projects to first focus on those that we believe will have the highest expected financial returns and ability to generate near-term cash flow.
We believe that we have sufficient available liquidity with available cash on hand, available borrowing under the Amended Credit Facility and cash flow from operations to fund our
2017
and 2018 capital expenditures. Future cash flows are subject to a number of variables, including our level of oil and natural gas production, commodity prices and operating costs. There can be no assurance that cash flow from operations and other capital resources will provide sufficient amounts of cash flow to maintain planned levels of capital expenditures.
Financing Activities
Amended Credit Facility.
The Amended Credit Facility had commitments from 13 lenders and a borrowing base of
$300.0 million
as of
September 30, 2017
. As credit support for future payment under a contractual obligation, a
$26.0 million
letter of credit has been issued under the Amended Credit Facility, which reduced the available borrowing capacity under the Amended Credit Facility as of
September 30, 2017
to
$274.0 million
. There have not been any borrowings under the Amended Credit Facility to date in 2017 and there were no such borrowings in 2016.
Interest rates are LIBOR plus applicable margins of
1.5%
to
2.5%
or ABR plus
0.5%
to
1.5%
and the unused commitment fee is between
0.375%
to
0.5%
based on borrowing base utilization.
The borrowing base under the Amended Credit Facility is determined at the discretion of the lenders, based on the collateral value of our proved reserves that have been mortgaged to the lenders, and is subject to regular re-determinations on or about April 1 and October 1 of each year, as well as following any property sales. In October 2017, our borrowing base was
re-confirmed at $300.0 million based on proved reserves and the commodity hedge position in place at June 30, 2017. Future borrowing bases will be computed based on proved oil, natural gas and NGL reserves, hedge positions and estimated future cash flows from those reserves calculated using future commodity pricing provided by our lenders, as well as any other outstanding debt. Lower commodity prices will generally result in a lower borrowing base.
The Amended Credit Facility contains certain financial covenants. We are currently in compliance with all financial covenants and have complied with all financial covenants since issuance. We expect to be in compliance with all financial covenants based on the 2017 budget at current commodity prices. However, if commodity prices significantly decline, our EBITDAX, which is a critical underpinning of our required financial covenants, will be significantly reduced. If this were to occur, it may become necessary for us to negotiate an amendment to one or more of these financial covenants. In September 2015, we obtained an amendment to the Amended Credit Facility that replaced our debt-to-EBITDAX covenant in the facility with a secured debt-to-EBITDAX covenant and an EBITDAX-to-interest covenant through March 31, 2018. There can be no assurance that we will be able to obtain similar amendments, or waivers of covenant breaches, in the future if needed.
If we fail to comply with the covenants or other terms of any agreements governing our debt, including the Amended Credit Facility, our lenders and holders of our senior notes may have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt. The occurrence of any such event would adversely affect our financial condition.
5% Convertible Senior Notes Due 2028.
On May 30, 2017, we redeemed our $0.6 million of outstanding Convertible Notes with the proceeds of our 8.75% Senior Notes issued on April 28, 2017. See "8.75% Senior Notes Due 2025" below for additional information.
7.625% Senior Notes Due 2019.
On May 30, 2017, we redeemed our $315.3 million of outstanding 7.625% Senior Notes with cash on hand and proceeds from the issuance of our 8.75% Senior Notes on April 28, 2017. See "8.75% Senior Notes Due 2025" below for additional information.
Due to the redemption of the Convertible Notes and the 7.625% Senior Notes, we recognized a
$7.9 million
loss on extinguishment of debt on the Consolidated Statement of Operations for the
nine
months ended
September 30, 2017
.
7.0% Senior Notes Due 2022.
On March 12, 2012, we issued $400.0 million in aggregate principal amount of 7.0% Senior Notes due October 15, 2022 at par. The 7.0% Senior Notes mature on October 15, 2022, unless earlier redeemed or purchased by us. Interest is payable in arrears semi-annually on April 15 and October 15 of each year. The 7.0% Senior Notes are senior unsecured obligations and rank equal in right of payment with all of our other existing and future senior unsecured indebtedness, including the 8.75% Senior Notes. The 7.0% Senior Notes became redeemable at our option on October 15, 2017 at a redemption price of 103.500%. The redemption price will decrease to 102.333%, 101.167% and 100.000% of the principal amount in 2018, 2019 and 2020, respectively. The 7.0% Senior Notes are fully and unconditionally guaranteed by our subsidiaries that guarantee the Amended Credit Facility and the 8.75% Senior Notes. The 7.0% Senior Notes include certain covenants that limit our ability to incur additional indebtedness, make restricted payments, create liens or sell assets and that generally prohibit us from paying dividends. We are currently in compliance with all covenants and have complied with all covenants since issuance.
8.75% Senior Notes Due 2025.
On April 28, 2017, we issued $275.0 million in aggregate principal amount of 8.75% Senior Notes due June 15, 2025 at par. Interest is payable in arrears semi-annually on June 15 and December 15 of each year, commencing on December 15, 2017. The 8.75% Senior Notes are senior unsecured obligations and rank equal in right of payment with all of our other existing and future senior unsecured indebtedness, including the 7.0% Senior Notes.
The 8.75% Senior Notes will become redeemable at our option on or after June 15, 2020, 2021, 2022 and 2023 at redemption prices of 106.563%, 104.375%, 102.188% and 100.000% of the principal amount, respectively. Prior to June 15, 2020, we may use proceeds of an equity offering to redeem up to 35% of the principal amount at a redemption price of 108.750% of the principal amount. In addition, prior to June 15, 2020, we may redeem the notes at a redemption price equal to 100% of the principal amount plus a specified "make-whole" premium.
The 8.75% Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee our indebtedness under the Amended Credit Facility and the 7.0% Senior Notes. The 8.75% Senior Notes include certain covenants that limit our ability to incur additional indebtedness, make restricted payments, create liens or sell assets and that generally prohibit us from paying dividends. We are currently in compliance with all covenants and have complied with all covenants since issuance.
Nothing in the indentures governing the 7.0% Senior Notes or the 8.75% Senior Notes prohibits us from repurchasing any of the notes from time to time at any price in open market purchases or negotiated transactions or by tender offer or otherwise without any notice to or consent of the holders.
Lease Financing Obligation Due 2020.
We have a Lease Financing Obligation with a balance of
$2.4 million
as of
September 30, 2017
resulting from our sale and subsequent lease back of certain compressors and related facilities owned by us. The Lease Financing Obligation expires on August 10, 2020, and we have the option to purchase the equipment at the end of the lease term for the then current fair market value. The Lease Financing Obligation also contains an early buyout option pursuant to which we may purchase the equipment for $1.8 million on February 10, 2019. The lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 3.3%. See Note
12
to the accompanying Unaudited Consolidated Financial Statements for a discussion of aggregate minimum future lease payments.
Our outstanding debt is summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of September 30, 2017
|
|
As of December 31, 2016
|
|
|
Maturity Date
|
Principal
|
|
Unamortized
Discount
|
|
Carrying
Amount
|
|
Principal
|
|
Unamortized
Discount
|
|
Carrying
Amount
|
|
|
|
(in thousands)
|
|
Amended Credit Facility
|
April 9, 2020
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Convertible Notes
(1)
|
March 15, 2028
|
—
|
|
|
—
|
|
|
—
|
|
|
579
|
|
|
—
|
|
|
579
|
|
|
7.625% Senior Notes
(2)
|
October 1, 2019
|
—
|
|
|
—
|
|
|
—
|
|
|
315,300
|
|
|
(2,169
|
)
|
|
313,131
|
|
|
7.0% Senior Notes
(3)
|
October 15, 2022
|
400,000
|
|
|
(3,684
|
)
|
|
396,316
|
|
|
400,000
|
|
|
(4,227
|
)
|
|
395,773
|
|
|
8.75% Senior Notes
(4)
|
June 15, 2025
|
275,000
|
|
|
(4,548
|
)
|
|
270,452
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Lease Financing Obligation
(5)
|
August 10, 2020
|
2,443
|
|
|
(2
|
)
|
|
2,441
|
|
|
2,782
|
|
|
(3
|
)
|
|
2,779
|
|
|
Total Debt
|
|
$
|
677,443
|
|
|
$
|
(8,234
|
)
|
|
$
|
669,209
|
|
|
$
|
718,661
|
|
|
$
|
(6,399
|
)
|
|
$
|
712,262
|
|
|
Less: Current Portion of Long-Term Debt
(6)
|
|
465
|
|
|
—
|
|
|
465
|
|
|
454
|
|
|
—
|
|
|
454
|
|
|
Total Long-Term Debt
|
|
$
|
676,978
|
|
|
$
|
(8,234
|
)
|
|
$
|
668,744
|
|
|
$
|
718,207
|
|
|
$
|
(6,399
|
)
|
|
$
|
711,808
|
|
|
|
|
|
(1)
|
The Convertible Notes were redeemed on May 30, 2017. The aggregate estimated fair value of the Convertible Notes was approximately
$0.5 million
as of
December 31, 2016
based on reported market trades of these instruments.
|
|
|
|
|
(2)
|
The 7.625% Senior Notes were redeemed on May 30, 2017. The aggregate estimated fair value of the 7.625% Senior Notes was approximately
$314.5 million
as of
December 31, 2016
based on reported market trades of these instruments.
|
|
|
|
|
(3)
|
The aggregate estimated fair value of the 7.0% Senior Notes was approximately
$386.3 million
and
$384.5 million
as of
September 30, 2017
and
December 31, 2016
, respectively, based on reported market trades of these instruments.
|
|
|
|
|
(4)
|
The aggregate estimated fair value of the 8.75% Senior Notes was approximately
$266.8 million
as of
September 30, 2017
based on reported market trades of these instruments.
|
|
|
|
|
(5)
|
The aggregate estimated fair value of the Lease Financing Obligation was approximately
$2.3 million
and
$2.6 million
as of
September 30, 2017
and
December 31, 2016
, respectively. Because there is no active, public market for the Lease Financing Obligation, the aggregate estimated fair value was based on market-based parameters of comparable term secured financing instruments.
|
|
|
|
|
(6)
|
The current portion of long-term debt includes the current portion of the Lease Financing Obligation.
|
Credit Ratings.
Our credit risk is evaluated by two independent rating agencies based on publicly available information and information obtained during our ongoing discussions with the rating agencies. Moody's Investor Services and Standard & Poor's Rating Services currently rate our 7.0% Senior Notes and 8.75% Senior Notes and have assigned a credit rating. We do not have any credit rating triggers that would accelerate the maturity of amounts due under our Amended Credit Facility, 7.0% Senior Notes or 8.75% Senior Notes. However, our ability to raise funds and the costs of any financing activities will be affected by our credit rating at the time any such financing activities are conducted.
Contractual Obligations.
A summary of our contractual obligations as of
September 30, 2017
is provided in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Year
|
|
Year 1
|
|
Year 2
|
|
Year 3
|
|
Year 4
|
|
Year 5
|
|
Thereafter
|
|
Total
|
|
|
Twelve Months Ended September 30, 2018
|
|
Twelve Months Ended September 30, 2019
|
|
Twelve Months Ended September 30, 2020
|
|
Twelve Months Ended September 30, 2021
|
|
Twelve Months Ended September 30, 2022
|
|
After
September 30, 2022
|
|
|
|
|
(in thousands)
|
|
Notes payable
(1)
|
$
|
322
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
322
|
|
|
7.0% Senior Notes
(2)
|
28,000
|
|
|
28,000
|
|
|
28,000
|
|
|
28,000
|
|
|
28,000
|
|
|
414,000
|
|
|
554,000
|
|
|
8.75% Senior Notes
(3)
|
27,334
|
|
|
24,063
|
|
|
24,063
|
|
|
24,063
|
|
|
24,063
|
|
|
347,188
|
|
|
470,774
|
|
|
Lease Financing Obligation
(4)
|
537
|
|
|
1,959
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,496
|
|
|
Office and office equipment leases and other
(5)
|
3,157
|
|
|
1,739
|
|
|
255
|
|
|
27
|
|
|
—
|
|
|
—
|
|
|
5,178
|
|
|
Firm transportation and processing agreements
(6)
|
18,652
|
|
|
18,691
|
|
|
18,691
|
|
|
15,575
|
|
|
—
|
|
|
—
|
|
|
71,609
|
|
|
Asset retirement obligations
(7)
|
1,829
|
|
|
1,304
|
|
|
1,279
|
|
|
1,602
|
|
|
1,532
|
|
|
14,910
|
|
|
22,456
|
|
|
Derivative liability
(8)
|
138
|
|
|
20
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
158
|
|
|
Total
|
$
|
79,969
|
|
|
$
|
75,776
|
|
|
$
|
72,288
|
|
|
$
|
69,267
|
|
|
$
|
53,595
|
|
|
$
|
776,098
|
|
|
$
|
1,126,993
|
|
|
|
|
|
(1)
|
Notes payable includes interest on a $26.0 million letter of credit that accrues interest at 2.0% and 0.125% per annum for participation fees and fronting fees, respectively. The expected term of the letter of credit is April 30, 2018. There is currently no balance outstanding under the Amended Credit Facility due April 9, 2020.
|
|
|
|
|
(2)
|
On March 25, 2012, we issued $400.0 million aggregate principal amount of 7.0% Senior Notes. We are obligated to make semi-annual interest payments through maturity on October 15, 2022 equal to $14.0 million.
|
|
|
|
|
(3)
|
On April 28, 2017, we issued $275.0 million aggregate principal amount of 8.75% Senior Notes. We are obligated to make semi-annual interest payments through maturity on June 15, 2025 equal to $12.0 million. See Note
5
to the accompanying financial statements for additional information.
|
|
|
|
|
(4)
|
The Lease Financing Obligation is calculated based on the aggregate undiscounted minimum future lease payments, which include both an interest and principal component.
|
|
|
|
|
(5)
|
The lease for our principal office in Denver, Colorado extends through March 2019.
|
|
|
|
|
(6)
|
We have entered into contracts that provide firm transportation capacity on pipeline systems. The contracts require us to pay transportation demand charges regardless of the amount of gas we deliver to the processing facility or pipeline.
|
|
|
|
|
(7)
|
Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance. See "Critical Accounting Policies and Estimates" in Part II, Item 7 of our Annual Report on Form 10-K for the year ended
December 31, 2016
for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.
|
|
|
|
|
(8)
|
Derivative liability represents the net fair value for oil, gas and NGL commodity derivatives presented as liabilities in our Unaudited Consolidated Balance Sheets as of
September 30, 2017
. The ultimate settlement amounts of our derivative liabilities are unknown because they are subject to continuing market fluctuations. See "Critical Accounting Policies and Estimates" in Part II, Item 7 of our Annual Report on Form 10-K for the year ended
December 31, 2016
and in "Commodity Hedging Activities" above in this Quarterly Report on Form 10-Q for a more detailed discussion of the nature of the accounting estimates involved in valuing derivative instruments.
|
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements as of
September 30, 2017
.
Trends and Uncertainties
We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended
December 31, 2016
for a discussion of trends and uncertainties that may affect our financial condition or liquidity. Also see "Risk Factors" in Part II of this report.
Critical Accounting Policies and Estimates
We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended
December 31, 2016
and the notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Quarterly Report on Form 10-Q for a description of critical accounting policies and estimates.