HighPoint Resources Corp - FORM 10-Q - October 31, 2018

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

FORM 10-Q
 
(Mark One)
þ
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2018

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

For the transition period from
 
to
 

Commission file number 333-222275

HighPoint Resources Corporation
(Exact name of registrant as specified in its charter)

Delaware
 
82-3620361
(State or other jurisdiction of
incorporation
or organization)
 
(IRS Employer
Identification No.)

1099 18th Street, Suite 2300
Denver, Colorado
 
80202
(Address of principal executive offices)
 
(Zip Code)

(303) 293-9100
(Registrant's telephone number, including area code)

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer
 
o
  
Accelerated filer
 
þ
Non-accelerated filer
 
o  (Do not check if a smaller reporting company)
  
Smaller reporting company
 
o
 
 
 
 
Emerging growth company
 
o

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

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

There were 212,444,845 shares of $0.001 par value common stock outstanding on October 17, 2018.


INDEX TO FINANCIAL STATEMENTS
 

2

PART I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements.

HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

 
September 30, 2018
 
December 31, 2017
 
(in thousands, except share data)
Assets:
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
92,980

 
$
314,466

Accounts receivable, net of allowance for doubtful accounts
68,035

 
51,415

Prepayments and other current assets
2,967

 
1,782

Total current assets
163,982

 
367,663

Property and equipment - at cost, successful efforts method for oil and gas properties:
 
 
 
Proved oil and gas properties
1,876,664

 
1,361,168

Unproved oil and gas properties, excluded from amortization
657,541

 
84,676

Furniture, equipment and other
18,515

 
17,899

 
2,552,720

 
1,463,743

Accumulated depreciation, depletion, amortization and impairment
(578,851
)
 
(444,863
)
Total property and equipment, net
1,973,869

 
1,018,880

Deferred financing costs and other noncurrent assets
6,795

 
4,163

Total
$
2,144,646

 
$
1,390,706

Liabilities and Stockholders' Equity:
 
 
 
Current liabilities:
 
 
 
Accounts payable and other accrued liabilities
$
147,590

 
$
84,055

Amounts payable to oil and gas property owners
55,097

 
16,594

Production taxes payable
46,697

 
26,876

Derivative liabilities
87,470

 
20,940

Current portion of long-term debt
1,978

 
469

Total current liabilities
338,832

 
148,934

Long-term debt, net of debt issuance costs
617,006

 
617,744

Asset retirement obligations
27,036

 
16,097

Deferred income taxes
137,111

 
—

Derivatives and other noncurrent liabilities
36,864

 
9,377

Commitments and contingencies (Note 12)

 

Stockholders' equity:
 
 
 
Common stock, $0.001 par value; authorized 400,000,000 and 300,000,000 shares at September 30, 2018 and December 31, 2017, respectively; 212,445,188 and 110,363,539 shares issued and outstanding at September 30, 2018 and December 31, 2017, respectively, with 2,917,648 and 1,394,868 shares subject to restrictions, respectively
210

 
109

Additional paid-in capital
1,769,852

 
1,279,507

Retained earnings (accumulated deficit)
(782,265
)
 
(681,062
)
Treasury stock, at cost: zero shares at September 30, 2018 and December 31, 2017
—

 
—

Total stockholders' equity
987,797

 
598,554

Total
$
2,144,646

 
$
1,390,706

See notes to Unaudited Consolidated Financial Statements.

3

HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
 
(in thousands, except share and per share data)
Operating Revenues:
 
 
 
 
 
 
 
Oil, gas and NGL production
$
131,585

 
$
67,175

 
$
322,534

 
$
168,541

Other operating revenues, net
(459
)
 
690

 
(200
)
 
926

Total operating revenues
131,126

 
67,865

 
322,334

 
169,467

Operating Expenses:
 
 
 
 
 
 
 
Lease operating expense
7,237

 
5,919

 
21,082

 
17,287

Gathering, transportation and processing expense
1,398

 
620

 
2,829

 
1,644

Production tax expense
11,504

 
5,384

 
26,363

 
9,140

Exploration expense
19

 
18

 
39

 
48

Impairment, dry hole costs and abandonment expense
184

 
261

 
609

 
8,336

(Gain) loss on sale of properties
74

 
—

 
1,046

 
(92
)
Depreciation, depletion and amortization
58,946

 
41,732

 
152,106

 
119,409

Unused commitments
4,574

 
4,557

 
13,684

 
13,687

General and administrative expense
12,696

 
12,496

 
34,427

 
30,788

Merger transaction expense
100

 
—

 
6,140

 
—

Other operating expenses, net
(764
)
 
(282
)
 
(716
)
 
(1,610
)
Total operating expenses
95,968

 
70,705

 
257,609

 
198,637

Operating Income (Loss)
35,158

 
(2,840
)
 
64,725

 
(29,170
)
Other Income and Expense:
 
 
 
 
 
 
 
Interest and other income
451

 
332

 
1,843

 
1,030

Interest expense
(13,165
)
 
(13,926
)
 
(39,348
)
 
(44,014
)
Commodity derivative gain (loss)
(51,547
)
 
(12,408
)
 
(128,166
)
 
19,654

Gain (loss) on extinguishment of debt
(257
)
 
—

 
(257
)
 
(7,904
)
Total other income and expense
(64,518
)
 
(26,002
)
 
(165,928
)
 
(31,234
)
Income (Loss) before Income Taxes
(29,360
)
 
(28,842
)
 
(101,203
)
 
(60,404
)
(Provision for) Benefit from Income Taxes
—

 
—

 
—

 
—

Net Income (Loss)
$
(29,360
)
 
$
(28,842
)
 
$
(101,203
)
 
$
(60,404
)
Net Income (Loss) Per Common Share, Basic
$
(0.14
)
 
$
(0.39
)
 
$
(0.56
)
 
$
(0.81
)
Net Income (Loss) Per Common Share, Diluted
$
(0.14
)
 
$
(0.39
)
 
$
(0.56
)
 
$
(0.81
)
Weighted Average Common Shares Outstanding, Basic
209,501,887

 
74,886,107

 
181,144,822

 
74,742,699

Weighted Average Common Shares Outstanding, Diluted
209,501,887

 
74,886,107

 
181,144,822

 
74,742,699

See notes to Unaudited Consolidated Financial Statements.

4

HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
 
(in thousands)
Net Income (Loss)
$
(29,360
)
 
$
(28,842
)
 
$
(101,203
)
 
$
(60,404
)
Other comprehensive income (loss)
—

 
—

 
—

 
—

Comprehensive Income (Loss)
$
(29,360
)
 
$
(28,842
)
 
$
(101,203
)
 
$
(60,404
)
See notes to Unaudited Consolidated Financial Statements.

5

HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
 
 
Nine Months Ended September 30,
 
2018
 
2017
 
(in thousands)
Operating Activities:
 
 
 
Net Income (Loss)
$
(101,203
)
 
$
(60,404
)
Adjustments to reconcile to net cash provided by operations:
 
 
 
Depreciation, depletion and amortization
152,106

 
119,409

Impairment, dry hole costs and abandonment expense
609

 
8,336

Commodity derivative (gain) loss
128,166

 
(19,654
)
Settlements of commodity derivatives
(42,628
)
 
17,062

Stock compensation and other non-cash charges
5,813

 
5,134

Amortization of deferred financing costs
1,729

 
1,665

(Gain) loss on extinguishment of debt
257

 
7,904

(Gain) loss on sale of properties
1,046

 
(92
)
Change in operating assets and liabilities:
 
 
 
Accounts receivable
(8,789
)
 
(9,252
)
Prepayments and other assets
(1,421
)
 
(980
)
Accounts payable, accrued and other liabilities
(25,287
)
 
20,071

Amounts payable to oil and gas property owners
33,804

 
6,371

Production taxes payable
15,983

 
(187
)
Net cash provided by (used in) operating activities
160,185

 
95,383

Investing Activities:
 
 
 
Additions to oil and gas properties, including acquisitions
(322,614
)
 
(160,788
)
Additions of furniture, equipment and other
(616
)
 
(268
)
Repayment of debt associated with merger, net of cash acquired
(53,357
)
 
—

Proceeds from sale of properties and other investing activities
11

 
(712
)
Net cash provided by (used in) investing activities
(376,576
)
 
(161,768
)
Financing Activities:
 
 
 
Proceeds from debt
—

 
275,000

Principal payments on debt
(350
)
 
(322,228
)
Proceeds from sale of common stock, net of offering costs
1

 
(298
)
Deferred financing costs and other
(4,746
)
 
(6,045
)
Net cash provided by (used in) financing activities
(5,095
)
 
(53,571
)
Increase (Decrease) in Cash and Cash Equivalents
(221,486
)
 
(119,956
)
Beginning Cash and Cash Equivalents
314,466

 
275,841

Ending Cash and Cash Equivalents
$
92,980

 
$
155,885

See notes to Unaudited Consolidated Financial Statements.

6

HIGHPOINT RESOURCES 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, 2016
$
74

 
$
1,113,797

 
$
(542,328
)
 
$
—

 
$
571,543

Cumulative effect of accounting change
—

 
180

 
(509
)
 
—

 
(329
)
Exercise of options, restricted stock activity and shares exchanged for exercise and tax withholding
1

 
—

 
—

 
(1,253
)
 
(1,252
)
Stock-based compensation
—

 
7,099

 
—

 
—

 
7,099

Retirement of treasury stock
—

 
(1,253
)
 
—

 
1,253

 
—

Exchange of senior notes for shares of common stock
11

 
48,981

 
—

 
—

 
48,992

Issuance of common stock, net of offering costs
23

 
110,703

 
—

 
—

 
110,726

Net income (loss)
—

 
—

 
(138,225
)
 
—

 
(138,225
)
Balance at December 31, 2017
109

 
1,279,507

 
(681,062
)
 
—

 
598,554

Exercise of options, restricted stock activity and shares exchanged for exercise and tax withholding
1

 
—

 
—

 
(1,533
)
 
(1,532
)
Stock-based compensation (1)
—

 
7,978

 
—

 
—

 
7,978

Retirement of treasury stock
—

 
(1,533
)
 
—

 
1,533

 
—

Issuance of common stock, merger
100

 
483,900

 
—

 
—

 
484,000

Net income (loss)
—

 
—

 
(101,203
)
 
—

 
(101,203
)
Balance at September 30, 2018
$
210

 
$
1,769,852

 
$
(782,265
)
 
$
—

 
$
987,797

See notes to Unaudited Consolidated Financial Statements.

(1)
As of September 30, 2018, includes the modification of the 2016 Program and 2017 Program from performance-based liability awards to service-based equity awards. See Note 11 for additional information.

7

HIGHPOINT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

September 30, 2018

1. Organization

HighPoint Resources Corporation, a Delaware corporation, together with its wholly-owned subsidiary (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"). The Company became the successor to Bill Barrett Corporation ("Bill Barrett"), on March 19, 2018, upon closing of the transactions contemplated by the Agreement and Plan of Merger, dated December 4, 2017 (the "Merger Agreement"), pursuant to which Bill Barrett combined with Fifth Creek Energy Operating Company, LLC ("Fifth Creek") (the "Merger"). As a result of the Merger, Bill Barrett became a wholly-owned subsidiary of HighPoint Resources Corporation and subsequently Bill Barrett changed its name to HighPoint Operating Corporation. The Company currently conducts its activities principally in the Denver Julesburg Basin ("DJ Basin") in Colorado. Except where the context indicates otherwise, references herein to the "Company" with respect to periods prior to the completion of the Merger refer to Bill Barrett and its subsidiaries.

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 Annual Report on Form 10-K filed by the Company's predecessor Bill Barrett for the year ended December 31, 2017 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 Bill Barrett 2017 Annual Report on Form10-K.

The results of operations attributable to the merged companies are included in the Unaudited Consolidated Statements of Operations beginning on March 19, 2018.

Use of Estimates. In the course of preparing the Company's 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 relate to volumes of oil, natural gas and NGL reserves used in calculating depreciation, depletion and amortization ("DD&A"), the amount of expected future cash flows used in determining possible impairments of oil and gas properties and the amount of future capital costs used in these calculations. Assumptions, judgments and estimates also are required in determining the fair values of assets acquired and liabilities assumed in business combinations, asset retirement obligations, the timing of dry hole costs, impairments of proved and 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:


8

 
As of September 30, 2018
 
As of December 31, 2017
 
(in thousands)
Oil, gas and NGL sales
$
51,405

 
$
36,569

Due from joint interest owners
16,607

 
14,779

Other
28

 
270

Allowance for doubtful accounts
(5
)
 
(203
)
Total accounts receivable
$
68,035

 
$
51,415


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, 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 value.

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, 2018
 
As of December 31, 2017
 
(in thousands)
Proved properties
$
427,982

 
$
230,800

Wells and related equipment and facilities
1,370,616

 
1,088,692

Support equipment and facilities
64,324

 
38,776

Materials and supplies
13,742

 
2,900

Total proved oil and gas properties
$
1,876,664

 
$
1,361,168

Unproved properties
549,342

 
18,832

Wells and facilities in progress
108,199

 
65,844

Total unproved oil and gas properties, excluded from amortization
$
657,541

 
$
84,676

Accumulated depreciation, depletion, amortization and impairment
(567,156
)
 
(433,234
)
Total oil and gas properties, net (1)
$
1,967,049

 
$
1,012,610


(1)
Total oil and gas properties, net includes $722.0 million of properties acquired in the Merger. See Note 4 for additional information regarding the Merger.

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

9

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.

The Company recognized non-cash impairment charges, which were included within 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,
 
2018
 
2017
 
2018
 
2017
 
(in thousands)
Impairment of unproved oil and gas properties (1)
$
—

 
$
—

 
$
—


$
8,010

Abandonment expense and lease expirations
184

 
261

 
609

 
326

Total impairment, dry hole costs and abandonment expense
$
184

 
$
261

 
$
609

 
$
8,336


(1)
The Company recognized impairment related to unproved oil and gas properties in the Cottonwood Gulch area of the Piceance Basin during the nine months ended September 30, 2017. The Company had 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 based on geologic and reservoir delineation 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 Other Accrued Liabilities. Accounts payable and other accrued liabilities are comprised of the following:

 
As of September 30, 2018
 
As of December 31, 2017
 
(in thousands)
Accrued drilling, completion and facility costs (1)
$
97,634

 
$
35,856

Accrued lease operating, gathering, transportation and processing expenses
7,104

 
4,360

Accrued general and administrative expenses
8,248

 
11,134

Accrued interest payable
18,355

 
6,484

Accrued merger transaction expenses
174

 
8,278

Accrued hedge settlements
6,411

 
65

Prepayments from partners
937

 
2,524

Trade payables
5,341

 
10,067

Other
3,386

 
5,287

Total accounts payable and other accrued liabilities
$
147,590

 
$
84,055


(1)
The increase as of September 30, 2018 is due to an increase in drilling and completions activity.


10

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 obligations for plugging and abandoning wells, and associated reclamation, for assets that were sold to other industry parties in prior years that are now in default. Regulatory agencies and landowners have demanded that the Company perform such activities.

Revenue Recognition. All of the Company's sales of oil, gas and NGLs are made under contracts with customers, whereby revenues are recognized when the Company satisfies its performance obligations and the customer obtains control of the product. Performance obligations under the Company's contracts with customers are typically satisfied at a point-in-time through monthly delivery of oil, gas and/or NGLs. Accordingly, at the end of the reporting period, the Company does not have any unsatisfied performance obligations. The Company's contracts with customers typically include variable consideration based on monthly pricing tied to local indices and volumes delivered in the current month. The nature of the Company's contracts with customers does not require the Company to constrain variable consideration for accounting purposes. As of September 30, 2018, the Company had open contracts with customers with terms of 1 month to 19 years, as well as evergreen contracts that renew on a periodic basis if not canceled by the Company or the customer. The Company's contracts with customers typically require payment within one month of delivery.

Under the Company's contracts with customers, natural gas and its components, including NGLs, are either sold to a midstream entity (which processes the natural gas and subsequently sells the resulting residue gas and NGLs) or are sold to a gas or NGL purchaser after being processed by a third party for a fee. Regardless of the contract structure type, the terms of these contracts compensate the Company for the value of the residue gas and NGLs at current market prices for each product. The Company's oil is sold to multiple oil purchasers at specific delivery points at or near the wellhead. All costs incurred to gather, transport and/or process the Company's oil, gas and NGLs after control has transferred to the customer are considered components of the consideration received from the customer and thus recorded in oil, gas and NGL production revenues in the Unaudited Consolidated Statements of Operations. All costs incurred prior to the transfer of control to the customer are included in gathering, transportation and processing expense in the Unaudited Consolidated Statements of Operations.

Gas imbalances from the sale of natural gas are recorded on the basis of gas actually sold by the Company. If the Company's aggregate sales volumes for a well are greater (or less) than its proportionate share of production from the well, a liability (or receivable) is established to the extent there are insufficient proved reserves available to make-up the overproduced (or underproduced) imbalance. Imbalances have not been significant in the periods presented.

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.

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, planning 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. Changes to the Company's development plans, increases in market prices for hydrocarbons, improvements in our operating results, or other factors, could result in a release of some or all of the valuation allowance in a future period which would result in the recognition of a tax benefit.

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, 2018.

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 (loss) per common share is calculated by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding and other dilutive securities. Potentially dilutive securities for the diluted net

11

income per common share calculations consist of nonvested shares of common stock and outstanding in-the-money stock options to purchase the Company's common stock. As the Company was in a net loss position, all potentially dilutive securities were anti-dilutive for the three and nine months ended September 30, 2018 and 2017.

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,
 
2018
 
2017
 
2018
 
2017
 
(in thousands, except per share amounts)
Net income (loss)
$
(29,360
)
 
$
(28,842
)
 
$
(101,203
)
 
$
(60,404
)
Basic weighted-average common shares outstanding in period
209,502

 
74,886

 
181,145

 
74,743

Diluted weighted-average common shares outstanding in period
209,502

 
74,886

 
181,145

 
74,743

Basic net income (loss) per common share
$
(0.14
)
 
$
(0.39
)
 
$
(0.56
)
 
$
(0.81
)
Diluted net income (loss) per common share
$
(0.14
)
 
$
(0.39
)
 
$
(0.56
)
 
$
(0.81
)

New Accounting Pronouncements. In August 2018, the Securities and Exchange Commission, ("SEC") issued a final rule, Disclosure Update and Simplification, that updates and simplifies SEC disclosure requirements. The primary changes include removing the requirement to disclose outside of the consolidated financial statements historical and pro forma ratios of earnings to fixed charges and historical low and high trading prices and adding a requirement to provide within the interim financial statements an analysis of changes in stockholders' equity for the current and comparative quarterly and year-to-date periods. Other changes included requirements related to segment, geographic area and dividend disclosures. The final rule will be effective November 5, 2018 and will not have a material impact on the Company's disclosures.

In August 2018, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2018-13, Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement. The objective of this update is to improve the effectiveness of fair value measurement disclosures. ASU 2018-13 is effective for annual periods beginning after December 15, 2019, and interim periods within those annual periods. The standard will only impact the Company's disclosures.

In June 2018, the FASB issued ASU 2018-07, Stock Compensation-Improvements to Non-employee Share-Based Payment Accounting. The objective of this update is to simplify several aspects of the accounting for non-employee share-based payment transactions resulting from expanding the scope of Topic 718, Compensation- Stock Compensation, to include share-based payment transactions for acquiring goods and services from non-employees. ASU 2018-07 is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. The standard will not have a material impact on the Company's disclosures and financial statements.

In May 2017, the FASB issued 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 was effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. The standard was adopted on January 1, 2018 and did not have a material impact on the Company's disclosures and financial statements.

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 was effective for annual and interim periods beginning after December 15, 2017. The standard was adopted prospectively on January 1, 2018 and did not have a material impact on the Company's disclosures and financial statements. The accounting treatment of the Merger was not affected by this guidance. See Note 4 for additional information regarding the Merger.

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 was effective for the annual periods beginning after December 15, 2017, and interim periods within those annual periods. The standard was adopted on January 1, 2018 and did not have a material impact on the Company's disclosures and financial statements. 

12


In February 2016, the FASB issued ASU 2016-02, Leases, followed by additional accounting standards updates that provided additional practical expedients and policy election options (collectively, Accounting Standards Codification Topic 842, ("ASC 842")). The objective of ASC 842 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. ASC 842 is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. The Company intends to adopt ASC 842 using the modified retrospective method and to use the option to not apply ASC 842 to comparative periods. The Company has also elected the following practical expedients:

•
not to recognize lease assets or liabilities on the balance sheet when lease terms are less than twelve months,
•
carryforward previous conclusions related to current lease classification under the current lease accounting standard to lease classification for these existing leases under ASC 842, and
•
exclude from evaluation under ASC 842 land easements that existed or expired before adoption of ASC 842.

The Company has compiled and analyzed its contracts and has identified which leasing arrangements will be affected. However, the Company is still evaluating the full impact of adopting this standard.

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 was effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. The standard was adopted on January 1, 2018 using the modified retrospective transition method, which was applied to contracts in place at the date of adoption. The adoption required the Company to net some additional gathering, transportation and processing expenses against its oil, gas and NGL production revenues. However, the cash flow and timing of the Company's revenue was not impacted and therefore no impact on the Company's net income (loss) or net income (loss) per common share. The standard also required additional footnote disclosures. See the "Revenue Recognition" section above for additional disclosures.

3. Supplemental Disclosures of Cash Flow Information

Supplemental cash flow information is as follows:

 
Nine Months Ended September 30,
 
2018
 
2017
 
(in thousands)
Cash paid for interest
$
25,746

 
$
31,113

Cash paid for income taxes
—

 
—

Supplemental disclosures of non-cash investing and financing activities:
 
 
 
Accrued liabilities - oil and gas properties
101,838

 
37,319

Accrued liabilities - financing costs
215

 
—

Change in asset retirement obligations, net of disposals
9,885

 
10,453

Retirement of treasury stock
(1,533
)
 
(1,246
)
Properties exchanged in non-cash transactions
—

 
13,323

Issuance of common stock for Merger
484,000

 
—


4. Mergers

Merger with Fifth Creek Operating Company, LLC

On March 19, 2018, the Company completed the Merger with Fifth Creek. Assets acquired include approximately 81,000 net acres in Weld County in the DJ Basin, substantially all of which are operated, and 62 producing standard-length lateral wells and 10 producing extended-reach lateral wells. In addition, the Company recorded net proved reserves of  9.3 MMBoe, of which 4.7 MMBoe were proved developed reserves and 4.6 MMBoe were proved undeveloped reserves.


13

The Merger was effected through the issuance of 100,000,000 shares of the Company's common stock, with a fair value of $484.0 million on the date of closing, and the repayment of $53.9 million of Fifth Creek debt. In connection with the Merger, the Company incurred costs of approximately $14.9 million to date of severance, consulting, advisory, legal and other merger-related fees, of which $6.1 million was included in the Company's Unaudited Consolidated Statement of Operations for the nine months ended September 30, 2018, with the remainder incurred in 2017.

Purchase Price Allocation

The transaction was accounted for as a business combination, using the acquisition method, with the Company being the acquirer for accounting purposes. The following table represents the preliminary allocation of the total purchase price to the identifiable assets acquired and the liabilities assumed based on the estimated fair values at the acquisition date. The Company expects to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets and liabilities may be revised as appropriate. The following table sets forth the Company's preliminary purchase price allocation:

 
 
March 19, 2018
 
 
(in thousands)
Purchase Price:
 
 
Fair value of common stock issued
 
$
484,000

Plus: Repayment of Fifth Creek debt
 
53,900

Total purchase price
 
537,900

 
 
 
Plus Liabilities Assumed:
 
 
Accounts payable and accrued liabilities
 
25,782

Current unfavorable contract
 
2,651

Other current liabilities
 
13,797

Asset retirement obligations
 
7,361

Long-term deferred tax liability
 
137,111

Long-term unfavorable contract
 
4,449

Other noncurrent liabilities
 
2,354

Total purchase price plus liabilities assumed
 
$
731,405

 
 
 
Fair Value of Assets Acquired:
 
 
Cash
 
543

Accounts receivable
 
7,831

Oil and Gas Properties:
 
 
Proved oil and gas properties
 
105,702

Unproved oil and gas properties
 
608,972

Asset Retirement Obligations
 
7,361

Furniture, equipment and other
 
931

Other noncurrent assets
 
65

Total asset value
 
$
731,405


The fair value measurements of oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of proved oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) recoverable reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average cost of capital rate. The fair value of unproved properties was determined using a market approach utilizing recent transactions of a similar nature in the same basin. These inputs required significant judgments and estimates by management at the time of the valuation and are the most sensitive to possible future changes.

14


The results of operations attributable to the merged companies are included in the Unaudited Consolidated Statements of Operations beginning on March 19, 2018. The Company generated revenues of approximately $20.9 million and $35.2 million from the Fifth Creek assets during the three and nine months ended September 30, 2018, respectively, and expenses of approximately $13.7 million and $25.1 million during the three and nine months ended September 30, 2018, respectively.

Pro Forma Financial Information

The following pro forma condensed combined financial information was derived from the historical financial statements of the Company and Fifth Creek and gives effect to the acquisition as if it had occurred on January 1, 2017. The below information reflects pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) the repayment of Fifth Creek's debt, (ii) depletion of Fifth Creek's fair-valued proved crude oil and natural gas properties, and (iii) the estimated tax impacts of the pro forma adjustments.

Additionally, pro forma earnings for the three and nine months ended September 30, 2018 were adjusted to exclude merger-related costs of $0.1 million and $6.1 million, respectively, incurred by the Company and zero and $4.0 million, respectively, incurred by Fifth Creek. The pro forma results of operations do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the Fifth Creek assets. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the acquisition taken place on January 1, 2017; furthermore, the financial information is not intended to be a projection of future results.

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
 
(in thousands, except per share data)
Revenues
$
131,126

 
$
80,973

 
$
338,266

 
$
195,727

Net Income (Loss) and Comprehensive Income (Loss)
(29,260
)
 
(33,301
)
 
(98,993
)
 
(65,180
)
Net Income (Loss) per Common Share, Basic and Diluted
(0.14
)
 
(0.19
)
 
(0.47
)
 
(0.37
)

5. Long-Term Debt

The Company's outstanding debt is summarized below:
 
 
 
As of September 30, 2018
 
As of December 31, 2017
 
Maturity Date
Principal
 
Debt Issuance Costs
 
Carrying
Amount
 
Principal
 
Debt Issuance Costs
 
Carrying
Amount
 
 
(in thousands)
Amended Credit Facility
September 14, 2023
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

7.0% Senior Notes (1)
October 15, 2022
350,000

 
(3,419
)
 
346,581

 
350,000

 
(4,033
)
 
345,967

8.75% Senior Notes (2)
June 15, 2025
275,000

 
(4,575
)
 
270,425

 
275,000

 
(5,080
)
 
269,920

Lease Financing Obligation (3)
August 10, 2020
1,978

 
—

 
1,978

 
2,328

 
(2
)
 
2,326

Total Debt
 
$
626,978

 
$
(7,994
)
 
$
618,984

 
$
627,328

 
$
(9,115
)
 
$
618,213

Less: Current Portion of Long-Term Debt (4)
 
1,978

 
—

 
1,978

 
469

 
—

 
469

Total Long-Term Debt
 
$
625,000

 
$
(7,994
)
 
$
617,006

 
$
626,859

 
$
(9,115
)
 
$
617,744


(1)
The aggregate estimated fair value of the 7.0% Senior Notes was approximately $348.6 million and $356.1 million as of September 30, 2018 and December 31, 2017, respectively, based on reported market trades of these instruments.
(2)
The aggregate estimated fair value of the 8.75% Senior Notes was approximately $290.2 million and $305.3 million as of September 30, 2018 and December 31, 2017, respectively, based on reported market trades of these instruments.
(3)
The aggregate estimated fair value of the Lease Financing Obligation was approximately $1.8 million and $2.1 million as of September 30, 2018 and December 31, 2017, 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.

15

(4)
The current portion of long-term debt includes the current portion of the Lease Financing Obligation. The Company has elected to exercise the early buyout option pursuant to which the Company will purchase the equipment for $1.8 million on February 10, 2019.

Amended Credit Facility

The Company entered into a fourth amended and restated credit facility (the "Amended Credit Facility"), which extends the maturity date to September 14, 2023, and provides for a maximum credit amount of $1.5 billion, an initial elected commitment amount of $500.0 million and an initial borrowing base of $500.0 million. Due to the amendment, the Company recognized a loss on extinguishment of debt of $0.3 million on the Unaudited Consolidated Statement of Operations for the three and nine months ended September 30, 2018. As credit support for future payments 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, 2018 to $474.0 million. There have been no borrowings under the Amended Credit Facility (or, as applicable, the facility then in place) to date in 2018 and there were no such borrowings in 2017.

Interest rates are either adjusted LIBOR plus applicable margins of 1.5% to 2.5% or an alternate base rate plus applicable margins of 0.5% to 1.5%, and the unused commitment fee is between 0.375% and 0.5%. The applicable margin and the unused commitment fee rate are determined 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-determination on or about April 1 and October 1 of each year, as well as following certain property sales. Borrowing bases are computed based on proved oil, natural gas and NGL reserves, hedge positions and estimated future cash flows from the 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 lenders under the Amended Credit Facility and holders of the Company's senior notes may have the right to accelerate the maturity of the relevant 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.

7.0% Senior Notes Due 2022

The Company's $350.0 million aggregate principal amount 7.0% Senior Notes mature on October 15, 2022 at par, 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 are redeemable at the Company's option at redemption prices of 102.333%, 101.167% and 100.000% of the principal amount on or after October 15, 2018, 2019 and 2020, respectively.

8.75% Senior Notes Due 2025

The Company's $275.0 million aggregate principal amount 8.75% Senior Notes mature on June 15, 2025 at par, unless earlier redeemed or purchased by the Company. Interest is payable in arrears semi-annually on June 15 and December 15 of each year. 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 issuer of the 7.0% Senior Notes and the 8.75% Senior Notes is HighPoint Operating Corporation (f/k/a Bill Barrett). Pursuant to supplemental indentures entered into in connection with the Merger, HighPoint Resources Corporation became a

16

guarantor of the 7.0% Senior Notes and the 8.75% Senior Notes in March 2018. All covenants in the indentures governing the notes limit the activities of HighPoint Operating Corporation, including limitations on the ability to pay dividends, incur additional indebtedness, make restricted payments, create liens, sell assets or make loans to HighPoint Resources Corporation, but in most cases the covenants in the indentures are not applicable to HighPoint Resources Corporation. HighPoint Operating Corporation 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 $2.0 million as of September 30, 2018 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 will 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, 2018 is as follows (in thousands):
As of December 31, 2017
$
17,586

Liabilities incurred (1)
9,818

Liabilities settled
(1,429
)
Disposition of properties
(351
)
Accretion expense
922

Revisions to estimate
1,847

As of September 30, 2018
$
28,393

Less: Current asset retirement obligations
1,357

Long-term asset retirement obligations
$
27,036


(1)
Includes $7.4 million associated with properties acquired in the Merger during the nine months ended September 30, 2018. See Note 4 for additional information regarding this Merger.

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

17

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.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Certain assets and liabilities are measured at fair value on a recurring basis in the Company's consolidated balance sheet. The following methods and assumptions were used to estimate the fair values:

Cash equivalents – The highly liquid cash equivalents are recorded at fair 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 swaps and costless collars are valued based on an income approach using various assumptions, such as quoted forward prices for commodities, risk-free discount rates, volatility factors and time value factors. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace, and are, therefore, designated as Level 2 inputs. The Company utilizes its counterparties' valuations to assess the reasonableness of its own valuations.

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.

The following tables set forth by level within the fair value hierarchy the Company's non-financial assets and liabilities that were measured at fair value on a recurring basis in the Unaudited Consolidated Balance Sheets.

 
Level 1
 
Level 2
 
Level 3
 
Total
 
(in thousands)
As of September 30, 2018
 
 
 
 
 
 
 
Financial Assets
 
 
 
 
 
 
 
Cash equivalents
$
63,189

 
$
—

 
$
—

 
$
63,189

Deferred compensation plan
1,516

 
—

 
—

 
1,516

Commodity derivatives
—

 
1,222

 
—

 
1,222

Financial Liabilities
 
 
 
 
 
 
 
Commodity derivatives
—

 
119,242

 
—

 
119,242

As of December 31, 2017
 
 
 
 
 
 
 
Financial Assets
 
 
 
 
 
 
 
Cash equivalents
271,027

 
—

 
—

 
271,027

Deferred compensation plan
1,749

 
—

 
—

 
1,749

Commodity derivatives
—

 
656

 
—

 
656

Financial Liabilities
 
 
 
 
 
 
 
Commodity derivatives
—

 
25,714

 
—

 
25,714


Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis


18

Certain assets and liabilities are measured at fair value on a nonrecurring basis in the Company's consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

Oil and gas properties – Oil and gas property costs are evaluated for impairment 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 net 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.

Information about impaired assets is as follows:

 
Level 1
 
Level 2
 
Level 3
 
Net Book
Value (1)
 
Impairment
Loss
 
(in thousands)
As of September 30, 2018
 
 
 
 
 
 
 
 
 
Oil and gas properties
$
—

 
$
—

 
$
—

 
$
—

 
$
—

As of December 31, 2017
 
 
 
 
 
 
 
 
 
Uinta Basin oil and gas properties (2)
—

 
—

 
106,587

 
144,532

 
37,945

DJ Basin unproved properties (3)
—

 
—

 
18,832

 
20,887

 
2,055

Piceance Basin unproved properties (4)
—

 
—

 
—

 
9,098

 
9,098


(1)
Amount represents net book value at the date of assessment.
(2)
The Company recognized a non-cash impairment charge of $37.9 million associated with the Company's Uinta Oil Program proved properties during the year ended December 31, 2017. The properties were sold on December 29, 2017.
(3)
As a result of having no future plans to develop certain acreage and/or estimated market values below carrying value, the Company recognized non-cash impairment charges of $2.1 million associated with certain non-core unproved properties in the DJ Basin during the year ended December 31, 2017.
(4)
As a result of having no future plans to develop certain acreage and/or estimated market values below carrying value, the Company recognized non-cash impairment charges of $9.1 million associated with certain unproved properties in the Cottonwood Gulch area of the Piceance Basin during the year ended December 31, 2017.

Purchase price allocation – The Merger was accounted for as a business combination, using the acquisition method. The allocation of the total purchase price to the identifiable assets acquired and the liabilities assumed was based on the fair values at the acquisition date. See Note 4 for additional information regarding the fair value of the Merger.

Additional Fair Value Disclosures

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 fair values of the Company's fixed rate 7.0% Senior Notes and 8.75% Senior Notes totaled $638.8 million and $661.4 million as of September 30, 2018 and December 31, 2017, respectively. 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. 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, 2018 and December 31, 2017. The Lease Financing Obligation fair values of $1.8 million and $2.1 million as of September 30, 2018 and December 31, 2017, respectively, are measured based on market-based parameters of comparable term secured financing instruments. The fair value measurements for the Amended Credit Facility and Lease Financing Obligation represent Level 2 inputs.

8. Derivative Instruments


19

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 and costless collars 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 on 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 on the Unaudited Consolidated Balance Sheets as of the dates indicated.

  
 
As of September 30, 2018
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
 
$
642

 
$
(642
)
(1) 
$
—

Deferred financing costs and other noncurrent assets
 
580

 
(580
)
(1) 
—

Total derivative assets
 
$
1,222

 
$
(1,222
)
 
$
—

 
 
 
 
 
 
 
 
 
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
 
$
(88,112
)
 
$
642

(1) 
$
(87,470
)
Derivatives and other noncurrent liabilities
 
(31,130
)
 
580

(1) 
(30,550
)
Total derivative liabilities
 
$
(119,242
)
 
$
1,222

  
$
(118,020
)
 
 
 
 
 
 
 
  
 
As of December 31, 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
 
$
594

 
$
(594
)
(1) 
$
—

Deferred financing costs and other noncurrent assets
 
62

 
(62
)
(1) 
—

Total derivative assets
 
$
656

 
$
(656
)
 
$
—

 
 
 
 
 
 
 
 
 
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
 
$
(21,534
)
 
$
594

(1) 
$
(20,940
)
Derivatives and other noncurrent liabilities
 
(4,180
)
 
62

(1) 
(4,118
)
Total derivative liabilities
 
$
(25,714
)
 
$
656

  
$
(25,058
)
 
(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, 2018, the Company had swap contracts in place to hedge the following volumes for the periods indicated:

20


 
October – December 2018
 
For the year 2019
 
For the year 2020
 
Derivative
Volumes
 
Weighted Average Price
 
Derivative Volumes
 
Weighted Average Price
 
Derivative Volumes
 
Weighted Average Price
Oil (Bbls)
1,270,140

 
$
54.63

 
6,704,184

 
$
58.85

 
2,286,000

 
$
61.32

Natural Gas (MMbtu)
460,000

 
$
2.68

 
1,825,000

 
$
2.05

 
—

 
$
—


As of September 30, 2018, the Company had cashless collars (purchased put options and written call options) in place to hedge the following volumes for the periods indicated:

 
October – December 2018
 
For the year 2019
 
Derivative
Volumes
 
Weighted Average Floor Price
 
Weighted Average Ceiling Price
 
Derivative
Volumes
 
Weighted Average Floor Price
 
Weighted Average Ceiling Price
Oil (Bbls)
184,000

 
$
60.00

 
$
77.27

 
552,000

 
$
55.00

 
$
77.56


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 eight different counterparties as of September 30, 2018. 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 continual 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, affiliates of lenders in the Amended Credit Facility or potential 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. ("ISDA") 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 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 the Company 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

On the date of the Merger, the Fifth Creek assets were acquired in a nontaxable transaction pursuant to Section 351 of the Internal Revenue Code. Accordingly, a deferred tax liability of $137.1 million was recorded to reflect the difference between the fair value recorded and the tax basis of the assets acquired and liabilities assumed.

The tax effects of temporary differences that give rise to significant components of the deferred tax assets and deferred tax liabilities as of September 30, 2018 and December 31, 2017 are presented below:


21


 
As of September 30, 2018
 
As of December 31, 2017
 
(in thousands)
Deferred tax assets:
 
 
 
Net operating loss carryforward
$
115,423

 
$
170,536

Stock-based compensation
3,507

 
3,826

Deferred rent
101

 
163

Deferred compensation
988

 
1,824

State tax credit carryforwards
—

 
6,499

Financing obligation
620

 
705

Accrued expenses
583

 
248

Investment in partnership
1,255

 
—

Derivative instruments
29,075

 
6,158

Other assets
2,276

 
228

Less: Valuation allowance
(69,980
)
 
(114,530
)
Total deferred tax assets
83,848

 
75,657

Deferred tax liabilities:
 
 
 
Oil and gas properties
(220,759
)
 
(75,409
)
Prepaid expenses
(200
)
 
(248
)
Total deferred tax assets (liabilities)
(220,959
)
 
(75,657
)
Net deferred tax assets (liabilities)
$
(137,111
)
 
$
—


In connection with the Merger, the Company had a greater than 50% ownership change pursuant to Section 382 of the Internal Revenue Code. As a result of the ownership change, the Company's ability to use pre-change net operating losses ("NOLs") and credits against post-change taxable income is limited to an annual amount plus any built-in gains recognized within five years of the ownership change. The Company's annual limitation amount is approximately $11.7 million. The Company has reduced its federal and state NOLs by $274.6 million and $10.0 million, respectively, and eliminated its state tax credits by $8.2 million to reflect the expected impact of the Section 382 limitation. Deferred tax assets and the corresponding valuation allowance have been reduced by $64.5 million for the expected tax effect of the Section 382 limitation. As of September 30, 2018, the Company projected approximately $468.0 million and $468.4 million of federal and state NOLs, respectively. The federal NOLs begin to expire in 2025 and the state NOLs begin to expire in 2029.

On December 22, 2017, the Tax Cut and Jobs Act of 2017 ("TCJA") became law. The TCJA includes significant changes to the U.S. corporate tax system, including a rate reduction from 35% to 21% beginning in January 2018. Accordingly, the 21% federal tax rate is utilized in computing the Company's annualized effective tax rate. Other provisions of TCJA include the elimination of the corporate alternative minimum tax, acceleration of depreciation for U.S. tax purposes, limitations on deductibility of interest expense, expanded Section 162(m) limitations on the deductibility of officers' compensation, the elimination of NOL carrybacks, and indefinite carryforwards on losses generated after 2017, subject to restrictions on their utilization.

In assessing the Company's ability to realize the benefit of the deferred tax assets, management must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities and projected future taxable income and tax planning strategies, and judgment is required in considering the relative weight of negative and positive evidence. In regard to the Company's deferred tax assets, the Company considered all available evidence in assessing the need for a valuation allowance.

10. Stockholders' Equity

Common and Preferred Stock. The Company's authorized capital structure consists of 75,000,000 shares of preferred stock, par value, $0.001 per share, and 400,000,000 shares of common stock, par value $0.001 per share. In March 2018, the Company adopted an amended and restated Certificate of Incorporation which increased the number of authorized shares of common stock from 300,000,000 to 400,000,000. There are no issued and outstanding shares of preferred stock.


22

In March 2018, the Company completed the Merger with Fifth Creek. Pursuant to the Merger Agreement, each share of Bill Barrett common stock, par value $0.001 per share (the "BBG Common Stock"), issued and outstanding immediately prior to the closing of the Merger was converted into one share of the Company's common stock and all outstanding equity interests in Fifth Creek, in the aggregate, were converted into 100,000,000 shares of the Company's common stock. In addition, all options to purchase shares of BBG Common Stock and all common stock awards and performance-based cash unit awards relating to BBG Common Stock that were outstanding immediately prior to the closing of the Merger were generally converted into corresponding awards relating to shares of the Company's common stock on the same terms and conditions (excluding performance conditions) as applied prior to the closing of the Merger (with 2016 and 2017 Program performance-based cash units converting into time-based common stock awards based on actual performance for the 2016 program and target performance for the 2017 program through the closing date). See Note 11 for additional information on equity compensation.

In March 2018, the Company terminated the Equity Distribution Agreement, dated as of June 2015, by and between the Company and Goldman, Sachs and Co., which established an "at-the-market" program for sales of common stock from time to time. The agreement was terminable at will upon written notification by the Company with no penalty. No shares had been sold pursuant to this agreement.

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). Nonvested shares of common stock generally vest ratably over a three year service period and nonvested shares of common stock units vest over a one year service 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). Cash-based awards generally have a cliff vest of three years.

The following table presents the long-term equity and cash incentive compensation related to awards for the periods indicated:

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
 
(in thousands)
Nonvested common stock (1)
$
1,654

 
$
1,434

 
$
4,504

 
$
4,437

Nonvested common stock units (1)
344

 
174

 
791

 
516

Nonvested performance-based shares (1)
—

 
—

 
—

 
558

Nonvested performance cash units (2)(3)
257

 
1,073

 
635

 
(27
)
Total
$
2,255

 
$
2,681

 
$
5,930

 
$
5,484


(1)
Unrecognized compensation expense as of September 30, 2018 was $10.0 million, which related to grants of nonvested shares of common stock that are expected to be recognized over a weighted-average period of 1.9 years.
(2)
The nonvested performance-based cash units are accounted for as liability awards with $1.4 million in accounts payable and accrued liabilities as of December 31, 2017 and $0.9 million and $3.0 million in derivatives and other noncurrent liabilities as of September 30, 2018 and December 31, 2017, respectively, in the Unaudited Consolidated Balance Sheets.
(3)
Liability awards are fair valued at each reporting date. The expense for the period will increase or decrease based on updated fair values of these awards at each reporting date.

Nonvested Equity and Cash Awards. The following tables present the equity and cash awards granted pursuant to the Company's various stock compensation plans. A summary of the Company's nonvested common stock awards for the three and nine months ended September 30, 2018 and 2017 is presented below:


23

 
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
Nonvested Common Stock Awards
 
Shares
 
Weighted Average
Grant Date
Fair Value
 
Shares
 
Weighted Average
Grant Date
Fair Value
Outstanding at July 1,
 
2,858,278

 
$
5.28

 
1,400,260

 
$
7.10

Granted
 
123,094

 
6.79

 
5,267

 
3.31

Vested
 
(25,432
)
 
7.16

 
(13,721
)
 
15.35

Forfeited or expired
 
(38,292
)
 
5.34

 
(550
)
 
15.15

Outstanding at September 30,
 
2,917,648

 
5.33

 
1,391,256

 
7.00

 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2018
 
Nine Months Ended September 30, 2017
Nonvested Common Stock Awards
 
Shares
 
Weighted Average
Grant Date
Fair Value
 
Shares
 
Weighted Average
Grant Date
Fair Value
Outstanding at January 1,
 
1,394,868

 
$
7.00

 
1,169,099

 
$
9.33

Granted
 
1,140,542

 
5.60

 
782,511

 
5.99

Modified (1)
 
1,146,305

 
4.84

 
—

 
—

Vested
 
(693,364
)
 
8.24

 
(508,613
)
 
10.71

Forfeited or expired
 
(70,703
)
 
5.98

 
(51,741
)
 
7.87

Outstanding at September 30,
 
2,917,648

 
5.33

 
1,391,256

 
7.00


(1)
Due to the closing of the Merger, the 2016 and 2017 Performance Cash Programs were converted from nonvested performance-based cash units to nonvested common stock awards, resulting in an increase of nonvested common stock awards for the nine months ended September 30, 2018.
 
A summary of the Company's nonvested common stock unit awards for the three and nine months ended September 30, 2018 and 2017 is presented below:

 
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
Nonvested Common Stock Unit Awards
 
Units
 
Weighted Average
Grant Date
Fair Value
 
Units
 
Weighted Average
Grant Date
Fair Value
Outstanding at July 1,
 
302,417

 
$
7.37

 
272,559

 
$
6.37

Granted
 
18,695

 
4.88

 
3,787

 
4.29

Vested
 
(18,695
)
 
4.88

 
(3,787
)
 
4.29

Outstanding at September 30,
 
302,417

 
7.37

 
272,559

 
6.37

 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2018
 
Nine Months Ended September 30, 2017
Nonvested Common Stock Unit Awards
 
Units
 
Weighted Average
Grant Date
Fair Value
 
Units
 
Weighted Average
Grant Date
Fair Value
Outstanding at January 1,
 
272,559

 
$
6.37

 
147,167

 
$
10.09

Granted
 
180,778

 
6.63

 
190,711

 
3.53

Vested
 
(150,920
)
 
4.66

 
(65,319
)
 
6.49

Outstanding at September 30,
 
302,417

 
7.37

 
272,559

 
6.37


A summary of the Company's nonvested performance-based cash unit awards for the three and nine months ended September 30, 2018 and 2017 is presented below:


24

 
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
Nonvested Performance-Based Cash Unit Awards
 
Units
 
Weighted Average
Fair Value
 
Units
 
Weighted Average
Fair Value
Outstanding at July 1,
 
846,256

 
 
 
1,537,198

 
 
Granted
 
89,037

 
 
 
5,267

 
 
Forfeited or expired
 
(16,232
)
 
 
 
—

 
 
Outstanding at September 30,
 
919,061

 
$
4.88

 
1,542,465

 
$
4.29

 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2018
 
Nine Months Ended September 30, 2017
Nonvested Performance-Based Cash Unit Awards
 
Units
 
Weighted Average
Fair Value
 
Units
 
Weighted Average
Fair Value
Outstanding at January 1,
 
1,548,083

 
 
 
942,326

 
 
Granted
 
935,293

 
 
 
663,425

 
 
Performance goal adjustment (1)
 
11,289

 
 
 
—

 
 
Modified (2)
 
(1,211,478
)
 
 
 
—

 
 
Vested
 
(286,652
)
 
 
 
—

 
 
Forfeited or expired
 
(77,474
)
 
 
 
(63,286
)
 
 
Outstanding at September 30,
 
919,061

 
$
4.88

 
1,542,465

 
$
4.29


(1)
The 2015 Program vested at 104.1% in excess of target level and resulted in additional units vested in March 2018. These units are included in the vested line item for the nine months ended September 30, 2018.
(2)
Due to the closing of the Merger, the 2016 and 2017 Performance Cash Programs were converted from nonvested performance-based cash units to nonvested common stock awards, resulting in a decrease in nonvested performance-based cash units for the nine months ended September 30, 2018. The 2016 Program converted based on its performance through March 19, 2018, which resulted in 89% of the units converting to nonvested common stock awards or a reduction of 65,173 units converting to nonvested common stock awards.

Performance Cash Program

2018 Program. In February 2018, the Compensation Committee of the Board of Directors of the Company approved a performance cash program (the "2018 Program") granting performance cash units that will settle in cash and are accounted for as liability awards. The performance-based awards contingently vest in February 2021, 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, 2020, 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 29, 2017 closing share price of $5.13. If the Company's absolute performance is lower than the $5.13 share price, the payout is zero for this portion. If the Company's absolute performance is greater than the $5.13 share price, the performance cash units will vest 1% for each 1% in growth, up to 150% 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 the Company's percentile rank above the median, up to 50% 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.

2017 Program. In February 2017, the Compensation Committee approved a performance cash program (the "2017 Program") granting performance cash units that would settle in cash and were accounted for as liability awards. In March 2018, upon the Merger closing, each award under the 2017 Program was converted to a nonvested common stock award at 100% of the original award. At the time of the modification, 619,006 units were converted to 619,006 nonvested shares of the Company's common stock. These awards no longer have a performance criterion, but continue to have a service-based criterion through the cliff vest in February 2020. The conversion of the performance-based liability award to a service-based equity award was accounted for as a modification in accordance with ASC 718, Compensation - Stock Compensation. The Company recorded an increase to additional paid-in capital ("APIC") and a decrease to derivative and other noncurrent liabilities of $0.9 million as of September 30, 2018 in the Unaudited Consolidated Statement of Stockholders' Equity and the Unaudited Consolidated Balance Sheets, respectively.

2016 Program. In March 2016, the Compensation Committee approved a performance cash program (the "2016 Program") granting performance cash units that would settle in cash and were accounted for as liability awards. In March 2018,

25

upon the Merger closing, each award under the 2016 Program was converted to a nonvested common stock award at 89% of the original award based on the Company's performance through March 19, 2018. At the time of the modification, 592,472 units were converted to 527,299 nonvested shares of the Company's common stock. These awards no longer have a performance criterion, but continue to have a service-based criterion through the cliff vest in February 2019. The conversion of the performance-based liability award to a service-based equity award was accounted for as a modification in accordance with ASC 718, Compensation - Stock Compensation. The Company recorded an increase to APIC and a decrease to derivative and other noncurrent liabilities of $1.8 million as of September 30, 2018 in the Unaudited Consolidated Statement of Stockholders' Equity and the Unaudited Consolidated Balance Sheets, respectively.

2015 Program. In February 2015, the Compensation Committee approved a performance cash program (the "2015 Program") granting performance cash units that would settle in cash and were accounted for as liability awards. The performance-based awards were to contingently vest in May 2018, depending on the level at which the performance goals were achieved. The performance goals, which were measured over the three year period ending December 31, 2017, consisted of the TSR compared to Relative TSR (weighted at 60%) and the percentage change in discretionary cash flow per debt adjusted share relative to a defined peer group's percentage calculation ("DCF per Debt Adjusted Share") (weighted at 40%). The Relative TSR and DCF per Debt Adjusted Share goals would vest at 25% or 50%, respectively, of the total award for performance met at the threshold level, 100% at the target level and 200% at the stretch level. If the actual results for a metric were between the threshold and target levels or between the target and stretch levels, the vested number of units would be prorated based on the actual results compared to the threshold, target and stretch goals. If the threshold metrics were not met, no units would vest. In any event, the total number of units that could vest would not exceed 200% of the original number of performance cash units granted. At the end of the three year vesting period, any units that had not vested would be forfeited. A total of 422,345 units were granted under this program during the year ended December 31, 2015. All compensation expense related to the TSR metric would be recognized if the requisite service period was fulfilled, even if the market condition was not achieved. All compensation expense related to the DCF per Debt Adjusted Share metric would be based on the number of shares expected to vest at the end of the three year period. The Company modified the vesting date of these awards from May 2018 to March 2018. Based upon the Company's performance through 2017, 104.1% or 286,652 units of the 2015 Program vested in March 2018.

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 Company has elected to exercise the early buyout option pursuant to which the Company will purchase the equipment for $1.8 million on February 10, 2019.

 
As of September 30, 2018
 
(in thousands)
2018
$
134

2019
1,869

Thereafter
—

Total
$
2,003


Firm Transportation Agreements. 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:


26

 
As of September 30, 2018
 
(in thousands)
2018
$
4,572

2019
18,590

2020
18,691

2021
10,903

Thereafter
—

Total
$
52,756


Gas Gathering and Processing Agreements. The Company is party to three minimum volume commitments and one reimbursement obligation. The minimum volume commitments require the Company to deliver a minimum volume of natural gas to midstream entities for gathering and processing. The contracts require the Company to pay a fee associated with the contracted volumes regardless of the amount delivered. The reimbursement obligation requires the Company to pay a monthly gathering and processing fee per Mcf of production over a one year period to reimburse a midstream entity for its costs to construct gas gathering and processing facilities. If the costs are not reimbursed by the Company via the monthly gathering and processing fees through August 2019, the Company must pay the difference. The amounts in the table below represent the Company's future minimum charges under both agreements:

 
As of September 30, 2018
 
(in thousands)
2018
$
2,737

2019 (1)
10,114

2020
2,167

2021
1,997

Thereafter
—

Total
$
17,015


(1)
Includes $6.9 million associated with the reimbursement obligation discussed above.

Lease and Other Commitments. The Company leases office space, vehicles and certain equipment under non-cancellable operating leases. The Company incurred rent expense related to these operating leases of $0.8 million and $2.0 million for the three and nine months ended September 30, 2018, respectively, and $0.5 million and $1.5 million for the three and nine months ended September 30, 2017, respectively. The Company also has non-cancellable agreements for telecommunication and geological and geophysical services. Future minimum annual payments under lease and other agreements are as follows:

 
As of September 30, 2018
 
(in thousands)
2018
$
2,604

2019
4,404

2020
2,532

2021
2,821

2022
2,764

Thereafter
13,087

Total
$
28,212


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

27


The condensed consolidating financial information as of and for the periods ended September 30, 2018 presents the results of operations, financial position and cash flows of HighPoint Resources Corporation, or parent guarantor, and HighPoint Operating Corporation (f/k/a Bill Barrett), or subsidiary issuer, as well as the consolidating adjustments necessary to present HighPoint Resources Corporation's results on a consolidated basis. The parent guarantor fully and unconditionally guarantees the debt securities of the subsidiary issuer. The indentures governing those securities limit the ability of the subsidiary issuer to pay dividends or otherwise provide funding to the parent guarantor.

In September 2018, Circle B Land Company LLC, a 100% owned subsidiary, merged into its parent company, HighPoint Operating Corporation. Prior periods are presented under the structure of the Company prior to the Merger and prior to the elimination of Circle B Land Company LLC. Circle B Land Company LLC and Aurora Gathering, LLC (both of which were 100% owned subsidiaries of the Company), on a joint and several basis, fully and unconditionally guaranteed the debt of Bill Barrett, the parent issuer. On December 29, 2017, the Company completed the sale of its remaining assets in the Uinta Basin, which included the equity of Aurora Gathering, LLC.

For the purpose of the following financial information, investments in subsidiaries are reflected in accordance with the equity method of accounting. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiaries operated as independent entities.

Condensed Consolidating Balance Sheets

 
As of September 30, 2018
 
Parent
Guarantor
 
Subsidiary
Issuer
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Assets:
 
 
 
 
 
 
 
Cash and cash equivalents
$
—

 
$
92,980

 
$
—

 
$
92,980

Accounts receivable, net of allowance for doubtful accounts
—

 
68,035

 
—

 
68,035

Other current assets
—

 
2,967

 
—

 
2,967

Property and equipment, net
—

 
1,973,869

 
—

 
1,973,869

Intercompany receivable
—

 
—

 
—

 
—

Investment in subsidiaries
987,797

 
—

 
(987,797
)
 
—

Noncurrent assets
—

 
6,795

 
—

 
6,795

Total assets
$
987,797

 
$
2,144,646

 
$
(987,797
)
 
$
2,144,646

Liabilities and Stockholders' Equity:
 
 
 
 
 
 
 
Accounts payable and other accrued liabilities
$
—

 
$
147,590

 
$
—

 
$
147,590

Other current liabilities
—

 
191,242

 
—

 
191,242

Long-term debt
—

 
617,006

 
—

 
617,006

Deferred income taxes
—

 
137,111

 
—

 
137,111

Other noncurrent liabilities
—

 
63,900

 
—

 
63,900

Stockholders' equity
987,797

 
987,797

 
(987,797
)
 
987,797

Total liabilities and stockholders' equity
$
987,797

 
$
2,144,646

 
$
(987,797
)
 
$
2,144,646

 

28

 
As of December 31, 2017
 
Parent
Issuer
 
Subsidiary
Guarantors
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Assets:
 
 
 
 
 
 
 
Cash and cash equivalents
$
314,466

 
$
—

 
$
—

 
$
314,466

Accounts receivable, net of allowance for doubtful accounts
51,415

 
—

 
—

 
51,415

Other current assets
1,782

 
—

 
—

 
1,782

Property and equipment, net
1,016,986

 
1,894

 
—

 
1,018,880

Intercompany receivable
854

 
—

 
(854
)
 
—

Investment in subsidiaries
1,040

 
—

 
(1,040
)
 
—

Noncurrent assets
4,163

 
—

 
—

 
4,163

Total assets
$
1,390,706

 
$
1,894

 
$
(1,894
)
 
$
1,390,706

Liabilities and Stockholders' Equity:
 
 
 
 
 
 
 
Accounts payable and other accrued liabilities
$
84,055

 
$
—

 
$
—

 
$
84,055

Other current liabilities
64,879

 
—

 
—

 
64,879

Intercompany payable
—

 
854

 
(854
)
 
—

Long-term debt
617,744

 
—

 
—

 
617,744

Other noncurrent liabilities
25,474

 
—

 
—

 
25,474

Stockholders' equity
598,554

 
1,040

 
(1,040
)
 
598,554

Total liabilities and stockholders' equity
$
1,390,706

 
$
1,894

 
$
(1,894
)
 
$
1,390,706


29


Condensed Consolidating Statements of Operations 

 
Three Months Ended September 30, 2018
 
Parent
Guarantor
 
Subsidiary
Issuer
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Operating and other revenues
$
—

 
$
131,126

 
$
—

 
$
131,126

Operating expenses
—

 
(83,172
)
 
—

 
(83,172
)
General and administrative
—

 
(12,696
)
 
—

 
(12,696
)
Merger transaction expense
—

 
(100
)
 
—

 
(100
)
Interest expense
—

 
(13,165
)
 
—

 
(13,165
)
Interest income and other income (expense)
—

 
(51,353
)
 
—

 
(51,353
)
Income (loss) before income taxes and equity in earnings (loss) of subsidiaries
—

 
(29,360
)
 
—

 
(29,360
)
(Provision for) benefit from income taxes
—

 
—

 
—

 
—

Equity in earnings (loss) of subsidiaries
(29,360
)
 
—

 
29,360

 
—

Net income (loss)
$
(29,360
)
 
$
(29,360
)
 
$
29,360

 
$
(29,360
)
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2018
 
Parent
Guarantor
 
Subsidiary
Issuer
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Operating and other revenues
$
—

 
$
322,334

 
$
—

 
$
322,334

Operating expenses
—

 
(217,042
)
 
—

 
(217,042
)
General and administrative
—

 
(34,427
)
 
—

 
(34,427
)
Merger transaction expense
—

 
(6,140
)
 
—

 
(6,140
)
Interest expense
—

 
(39,348
)
 
—

 
(39,348
)
Interest income and other income (expense)
—

 
(126,580
)
 
—

 
(126,580
)
Income (loss) before income taxes and equity in earnings (loss) of subsidiaries
—

 
(101,203
)
 
—

 
(101,203
)
(Provision for) benefit from income taxes
—

 
—

 
—

 
—

Equity in earnings (loss) of subsidiaries
(101,203
)
 
—

 
101,203

 
—

Net income (loss)
$
(101,203
)
 
$
(101,203
)
 
$
101,203

 
$
(101,203
)


30

 
Three Months Ended September 30, 2017
 
Parent
Issuer
 
Subsidiary
Guarantors
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Operating and other 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 (loss) 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
 
Subsidiary
Guarantors
 
Intercompany Eliminations
 
Consolidated
 
(in thousands)
Operating and other 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 (loss) 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
)

Condensed Consolidating Statements of Comprehensive Income (Loss)
 
 
Three Months Ended September 30, 2018
 
Parent
Guarantor
 
Subsidiary
Issuer
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Net income (loss)
$
(29,360
)
 
$
(29,360
)
 
$
29,360

 
$
(29,360
)
Other comprehensive loss
—

 
—

 
—

 
—

Comprehensive income (loss)
$
(29,360
)
 
$
(29,360
)
 
$
29,360

 
$
(29,360
)
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2018
 
Parent
Guarantor
 
Subsidiary
Issuer
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Net income (loss)
$
(101,203
)
 
$
(101,203
)
 
$
101,203

 
$
(101,203
)
Other comprehensive loss
—

 
—

 
—

 
—

Comprehensive income (loss)
$
(101,203
)
 
$
(101,203
)
 
$
101,203

 
$
(101,203
)


31

 
Three Months Ended September 30, 2017
 
Parent
Issuer
 
Subsidiary
Guarantors
 
Intercompany Eliminations
 
Consolidated
 
(in thousands)
Net income (loss)
$
(28,842
)
 
$
12

 
$
(12
)
 
$
(28,842
)
Other comprehensive loss
—

 
—

 
—

 
—

Comprehensive income (loss)
$
(28,842
)
 
$
12

 
$
(12
)
 
$
(28,842
)
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2017
 
Parent
Issuer
 
Subsidiary
Guarantors
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Net income (loss)
$
(60,404
)
 
$
(60
)
 
$
60

 
$
(60,404
)
Other comprehensive loss
—

 
—

 
—

 
—

Comprehensive income (loss)
$
(60,404
)
 
$
(60
)
 
$
60

 
$
(60,404
)

Condensed Consolidating Statements of Cash Flows
 
 
Nine Months Ended September 30, 2018
 
Parent
Guarantor
 
Subsidiary
Issuer
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Cash flows from operating activities
$
—

 
$
160,185

 
$
—

 
$
160,185

Cash flows from investing activities:
 
 
 
 
 
 
 
Additions to oil and gas properties, including acquisitions
—

 
(322,614
)
 
—

 
(322,614
)
Additions to furniture, fixtures and other
—

 
(616
)
 
—

 
(616
)
Repayment of debt associated with merger, net of cash acquired
—

 
(53,357
)
 
—

 
(53,357
)
Proceeds from sale of properties and other investing activities
—

 
11

 
—

 
11

Intercompany transfers
—

 
—

 
—

 
—

Cash flows from financing activities:
 
 
 
 
 
 
 
Principal payments on debt
—

 
(350
)
 
—

 
(350
)
Proceeds from sale of common stock, net of offering costs
—

 
1

 
—

 
1

Intercompany transfers
—

 
—

 
—

 
—

Other financing activities
—

 
(4,746
)
 
—

 
(4,746
)
Change in cash and cash equivalents
—

 
(221,486
)
 
—

 
(221,486
)
Beginning cash and cash equivalents
—

 
314,466

 
—

 
314,466

Ending cash and cash equivalents
$
—

 
$
92,980

 
$
—

 
$
92,980

 

32

 
Nine Months Ended September 30, 2017
 
Parent
Issuer
 
Subsidiary
Guarantors
 
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

  

33

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 HighPoint Resources Corporation. 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:

•
legislative, judicial or regulatory changes including initiatives to impose increased 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;
•
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;
•
the concentration of our properties in the Rocky Mountain region;
•
compliance with environmental and other regulations;
•
economic and competitive conditions;
•
occurrence of property divestitures or acquisitions;
•
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 the risk of 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, and/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 the risk of 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;
•
midstream capacity issues;
•
changes in tax laws and statutory tax rates; and
•
other uncertainties, including those factors discussed below and in Bill Barrett's Annual Report on Form 10-K for the year ended December 31, 2017 under the headings "Cautionary Note Regarding Forward-Looking Statements" and "Risk Factors" and in Part II, 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


34

We became the successor to Bill Barrett Corporation ("Bill Barrett") on March 19, 2018 upon completion of the business combination (the "Merger") between Bill Barrett and Fifth Creek Energy Operating Company, LLC ("Fifth Creek"). Except where the context indicates otherwise, the terms "we", "us", "our" or the "Company" as used herein refer, for periods prior to the completion of the Merger, to Bill Barrett and its subsidiaries and, for periods following the completion of the Merger, to HighPoint Resources Corporation and its subsidiaries (including Bill Barrett, which has subsequently been renamed HighPoint Operating Corporation).

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.

As previously disclosed, there were attempts in the last two state election cycles to qualify ballot initiatives that would have amended the state constitution in order to restrict oil and gas development in Colorado by empowering local government control or imposing mandatory statewide setbacks in excess of current rules. These previous efforts were either withdrawn or failed to qualify for the ballot due to lack of petition signatures.

In Bill Barrett's Annual Report on Form 10-K for the year ended December 31, 2017, we disclosed that “similar proposals may be approved for the 2018 ballot” and that because “substantially all of our operations and reserves are located in Colorado, the passage and implementation of any such proposal could have a materially adverse effect on our operations, reserves, financial condition and business generally.”

In fact, a statutory setback initiative, Proposition 112, did qualify for the November 2018 ballot. Proposition 112 would amend the Oil and Gas Conservation Act by prohibiting the Colorado Oil and Gas Conservation Commission from permitting new oil and gas development closer than 2,500 feet from “occupied structures” or “vulnerable areas” such as playgrounds, parks, public open space and water bodies, including irrigation canals, perennial or intermittent streams and creeks. Development on federal land is excluded from the prohibition. The state and local governments are also empowered to expand the list of vulnerable areas and to increase the “buffer zone” to more than 2,500 feet.

Due to the rural nature of our acreage position, Proposition 112, if it had been limited to occupied structures, would have had a minimal impact on our development activities. However, due to its extension to vulnerable areas, notably including intermittent streams and creeks, adoption of the measure would impact our development activities on more than two-thirds of the well pads located on our currently configured drilling units.

To mitigate this risk, we have established an inventory of approved drilling permits and expect additional permits to be approved before Proposition 112, if approved by the voters, would take effect. In addition, we believe that we can reconfigure drilling units and relocate well pads to avoid restricted areas, in some cases by moving to federal lands, and reach nearly all of our acreage position, although such relocation would entail additional cost and permitting delays.

The industry, through its trade associations and political arms, is engaged in an intensive campaign to defeat Proposition 112 at the ballot box. This effort is being supported by the general business community and most local and state elected officials and candidates, including the gubernatorial candidates of both major parties.

Should Proposition 112 be adopted, the state and local governments will, over time, face significant budgetary pressure from reduced oil and gas tax revenues, compounded by “takings” lawsuits seeking billions of dollars in compensation. These pressures could result in legislation to modify Proposition 112’s statutory provisions to ameliorate its impact. On the other hand, should Proposition 112 be defeated, legislation may be introduced to address public concerns about oil and gas development through increased setbacks of less than 2,500 feet, increased local control, emission limits or other means. The identity of the next governor and the make-up of the next General Assembly will be determinative factors in either scenario.

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

35

Facility, 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, 2018, we have hedged 1,454,140 barrels of oil and 460,000 MMbtu of natural gas, or approximately 48% of our expected remaining 2018 production, 7,256,184 barrels of oil and 1,825,000 MMbtu of natural gas for 2019 and 2,286,000 barrels of oil for 2020 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.

As a result of the closing of the Merger on March 19, 2018, Fifth Creek's revenues and expenses are included in the Unaudited Consolidated Statement of Operations beginning on March 19, 2018. See Note 4 for additional information regarding the accounting for the Merger.

36

Results of Operations

The following table sets forth selected operating data for the periods indicated:

Three Months Ended September 30, 2018 Compared with Three Months Ended September 30, 2017
 
 
Three Months Ended September 30,
 
Increase (Decrease)
2018
 
2017
 
Amount
 
Percent
($ in thousands, except per unit data)
Operating Results:
 
 
 
 
 
 
 
Operating Revenues
 
 
 
 
 
 
 
Oil, gas and NGL production
$
131,585

 
$
67,175

 
$
64,410

 
96
 %
Other operating revenues
(459
)
 
690

 
(1,149
)
 
*nm

Total operating revenues
131,126

 
67,865

 
63,261

 
93
 %
Operating Expenses
 
 
 
 
 
 
 
Lease operating expense
7,237

 
5,919

 
1,318

 
22
 %
Gathering, transportation and processing expense
1,398

 
620

 
778

 
125
 %
Production tax expense
11,504

 
5,384

 
6,120

 
114
 %
Exploration expense
19

 
18

 
1

 
6
 %
Impairment, dry hole costs and abandonment expense
184

 
261

 
(77
)
 
(30
)%
(Gain) loss on sale of properties
74

 
—

 
74

 
*nm

Depreciation, depletion and amortization
58,946

 
41,732

 
17,214

 
41
 %
Unused commitments
4,574

 
4,557

 
17

 
—
 %
General and administrative expense (1)
12,696

 
12,496

 
200

 
2
 %
Merger transaction expense
100

 
—

 
100

 
*nm

Other operating expense, net
(764
)
 
(282
)
 
(482
)
 
*nm

Total operating expenses
$
95,968

 
$
70,705

 
$
25,263

 
36
 %
Production Data:
 
 
 
 
 
 
 
Oil (MBbls)
1,716

 
1,202

 
514

 
43
 %
Natural gas (MMcf)
3,294

 
2,274

 
1,020

 
45
 %
NGLs (MBbls)
471

 
339

 
132

 
39
 %
Combined volumes (MBoe)
2,736

 
1,920

 
816

 
43
 %
Daily combined volumes (Boe/d)
29,739

 
20,870

 
8,869

 
43
 %
Average Realized Prices Before Hedging:
 
 
 
 
 
 
 
Oil (per Bbl)
$
66.96

 
$
46.08

 
$
20.88

 
45
 %
Natural gas (per Mcf)
1.59

 
2.37

 
(0.78
)
 
(33
)%
NGLs (per Bbl)
24.31

 
18.93

 
5.38

 
28
 %
Combined (per Boe)
48.10

 
34.99

 
13.11

 
37
 %
Average Realized Prices with Hedging:
 
 
 
 
 
 
 
Oil (per Bbl)
$
55.92

 
$
51.86

 
$
4.06

 
8
 %
Natural gas (per Mcf)
1.64

 
2.51

 
(0.87
)
 
(35
)%
NGLs (per Bbl)
24.31

 
18.93

 
5.38

 
28
 %
Combined (per Boe)
41.23

 
38.78

 
2.45

 
6
 %
Average Costs (per Boe):
 
 
 
 
 
 
 
Lease operating expense
$
2.65

 
$
3.08

 
$
(0.43
)
 
(14
)%
Gathering, transportation and processing expense
0.51

 
0.32

 
0.19

 
59
 %
Production tax expense
4.20

 
2.80

 
1.40

 
50
 %
Depreciation, depletion and amortization
21.54

 
22.52

 
(0.98
)
 
(4
)%
General and administrative expense (1)
4.64

 
6.51

 
(1.87
)
 
(29
)%

*
Not meaningful.

37

(1)
Included in general and administrative expense is long-term cash and equity incentive compensation of $2.3 million (or $0.82 per Boe) and $2.7 million (or $1.40 per Boe) for the three months ended September 30, 2018 and 2017, respectively.

Production Revenues and Volumes. Production revenues increased to $131.6 million for the three months ended September 30, 2018 from $67.2 million for the three months ended September 30, 2017. The increase in production revenues was due to a 43% increase in production volumes and a 37% increase in average realized prices before hedging. The increase in production volumes increased production revenues by approximately $39.3 million, while the increase in average realized prices before hedging increased production revenues by approximately $25.1 million.

The 43% increase in total production from the three months ended September 30, 2017 to the three months ended September 30, 2018 was primarily due to a 61% increase in the DJ Basin as a result of new wells placed into production, along with wells acquired in the Merger, offset by the sale of our remaining assets in the Uinta Oil Program in December 2017. Additional information concerning production is in the following table:

 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
 
% 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
1,716

471

3,294

2,736

 
1,005

335

2,178

1,703

 
71
%
41
%
51
%
61
%
Other (1)
—

—

—

—

 
197

4

96

217

 
*nm

*nm

*nm

*nm

Total
1,716

471

3,294

2,736

 
1,202

339

2,274

1,920

 
43
%
39
%
45
%
43
%

(1)
Other includes 195 MBbls of oil, 4 MBbls of NGLs and 96 MMcf of natural gas production in the Uinta Oil Program for the three months ended September 30, 2017.

Lease Operating Expense ("LOE"). LOE decreased to $2.65 per Boe for the three months ended September 30, 2018 from $3.08 per Boe for the three months ended September 30, 2017. The decrease per Boe for the three months ended September 30, 2018 compared with the three months ended September 30, 2017 is primarily related to operational efficiencies in our legacy DJ Basin assets and the sale of our remaining assets in the Uinta Oil Program in December 2017, which had relatively high LOE costs on a per Boe basis.

Gathering, Transportation and Processing Expense ("GTP"). GTP expense increased to $0.51 per Boe for the three months ended September 30, 2018 from $0.32 per Boe for the three months ended September 30, 2017.

Costs incurred to gather, transport and/or process our oil, gas and NGLs prior to the transfer of control to the customer are included in GTP expense. Costs incurred to gather, transport and/or process our oil, gas and NGLs after control has transferred to the customer are considered components of the consideration received from the customer and thus recorded in oil, gas and NGL production revenues. In general, based on specific contract arrangements, costs incurred in the Hereford Field in the DJ Basin, which was acquired in the Merger, are included in GTP expense and costs incurred in the Northeast Wattenberg Field in the DJ Basin are included in production revenues. See the "Revenue Recognition" section in Note 2 for additional information.

GTP expense for the three months ended September 30, 2018 of $0.51 per Boe is primarily associated with the Hereford Field. We expect GTP expense per Boe to increase in the future as we further develop and increase our production mix from the Hereford Field under the existing contractual arrangements.

Production Tax Expense. Total production taxes increased to $11.5 million for the three months ended September 30, 2018 from $5.4 million for the three months ended September 30, 2017. The increase is attributable to the 43% increase in production and the 37% 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 8.7% and 8.0% for the three months ended September 30, 2018 and September 30, 2017, respectively. The increase was due to an increase in the effective rate of Colorado severance taxes for the three months ended September 30, 2018.

Depreciation, Depletion and Amortization ("DD&A"). DD&A increased to $58.9 million for the three months ended September 30, 2018 compared with $41.7 million for the three months ended September 30, 2017. The increase of $17.2 million was a result of a 43% increase in production volumes offset by a 4% decrease in the DD&A rate for the three months ended September 30, 2018 compared with the three months ended September 30, 2017. The increase in production accounted

38

for a $18.4 million increase in DD&A expense, while the decrease in the DD&A rate accounted for a $1.2 million decrease 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, 2018, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $21.54 per Boe compared with $22.52 per Boe for the three months ended September 30, 2017. The decrease in the depletion rate of 4% is the result of adding proved developed producing reserves at lower costs.

Unused Commitments. Unused commitments expense for each of the three months ended September 30, 2018 and September 30, 2017 consisted of $4.6 million related to gas transportation contracts. 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.

General and Administrative Expense. General and administrative expense increased slightly to $12.7 million for the three months ended September 30, 2018 from $12.5 million for the three months ended September 30, 2017.

Included in general and administrative expense is long-term cash and equity incentive compensation of $2.3 million and $2.7 million for the three months ended September 30, 2018 and 2017, respectively. The components of long-term cash and equity incentive compensation for the three months ended September 30, 2018 and 2017 are shown in the following table:

 
Three Months Ended September 30,
 
2018
 
2017
 
(in thousands)
Nonvested common stock
$
1,654

 
$
1,434

Nonvested common stock units
344

 
174

Nonvested performance cash units (1)
257

 
1,073

Total
$
2,255

 
$
2,681


(1)
The nonvested performance cash units are accounted for as liability awards and will be settled in cash for the performance metrics that are met. The expense for the period will increase or decrease based on updated fair values of these awards at each reporting date.

Commodity Derivative Gain (Loss). Commodity derivative gain (loss) was a loss of $51.5 million for the three months ended September 30, 2018 compared with a loss of $12.4 million for the three months ended September 30, 2017. 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, 2018 and 2017 or during the periods then ended.

The fair value of our open, but not yet settled derivative contracts is based on an income approach using various assumptions, such as quoted forward prices for commodities, risk-free discount rates, volatility factors and time value factors. The mark-to-market fair value of the open commodity derivative contracts will generally be inversely related to the price movement of the underlying commodity. If commodity price trends reverse from period to period, prior unrealized gains may become unrealized losses and vice versa. Higher underlying commodity price volatility will generally lead to higher volatility in our unrealized gains and losses and, by association, the fair value of our commodity derivative contracts. These unrealized gains and losses will impact our net income in the period reported. The mark-to-market fair value can create non-cash volatility in our reported earnings during periods of commodity price volatility. We have experienced such volatility in the past and are likely to experience it in the future. Gains on our derivatives generally indicate lower wellhead revenues in the future while losses indicate higher future wellhead revenues.

The table below summarizes our commodity derivative gains and losses that were recognized in the periods presented:


39

 
Three Months Ended September 30,
 
2018
 
2017
 
(in thousands)
Realized gain (loss) on derivatives (1)
$
(18,780
)
 
$
7,263

Prior year unrealized (gain) loss transferred to realized (gain) loss (1)
4,920

 
(1,036
)
Unrealized gain (loss) on derivatives (1)
(37,687
)
 
(18,635
)
Total commodity derivative gain (loss)
$
(51,547
)
 
$
(12,408
)

(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, 2018, approximately 74% of our oil volumes and 13% of our natural gas volumes were subject to financial hedges, which resulted in a decrease in oil income of $18.9 million and an increase in natural gas income of $0.1 million after settlements. 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.


40

Nine Months Ended September 30, 2018 Compared with Nine Months Ended September 30, 2017

 
Nine Months Ended September 30,
 
Increase (Decrease)
2018
 
2017
 
Amount
 
Percent
($ in thousands, except per unit data)
Operating Results:
 
 
 
 
 
 
 
Operating Revenues
 
 
 
 
 
 
 
Oil, gas and NGL production
$
322,534

 
$
168,541

 
$
153,993

 
91
 %
Other operating revenues
(200
)
 
926

 
(1,126
)
 
*nm

Total operating revenues
322,334

 
169,467

 
152,867

 
90
 %
Operating Expenses
 
 
 
 
 
 
 
Lease operating expense
21,082

 
17,287

 
3,795

 
22
 %
Gathering, transportation and processing expense
2,829

 
1,644

 
1,185

 
72
 %
Production tax expense
26,363

 
9,140

 
17,223

 
188
 %
Exploration expense
39

 
48

 
(9
)
 
(19
)%
Impairment, dry hole costs and abandonment expense
609

 
8,336

 
(7,727
)
 
(93
)%
(Gain) loss on sale of properties
1,046

 
(92
)
 
1,138

 
*nm

Depreciation, depletion and amortization
152,106

 
119,409

 
32,697

 
27
 %
Unused commitments
13,684

 
13,687

 
(3
)
 
—
 %
General and administrative expense (1)
34,427

 
30,788

 
3,639

 
12
 %
Merger transaction expense
6,140

 
—

 
6,140

 
*nm

Other operating expenses, net
(716
)
 
(1,610
)
 
894

 
*nm

Total operating expenses
$
257,609

 
$
198,637

 
$
58,972

 
30
 %
Production Data:
 
 
 
 
 
 
 
Oil (MBbls)
4,360

 
2,929

 
1,431

 
49
 %
Natural gas (MMcf)
8,946

 
6,084

 
2,862

 
47
 %
NGLs (MBbls)
1,207

 
936

 
271

 
29
 %
Combined volumes (MBoe)
7,058

 
4,879

 
2,179

 
45
 %
Daily combined volumes (Boe/d)
25,853

 
17,872

 
7,981

 
45
 %
Average Realized Prices Before Hedging:
 
 
 
 
 
 
 
Oil (per Bbl)
$
64.61

 
$
46.52

 
$
18.09

 
39
 %
Natural gas (per Mcf)
1.59

 
2.48

 
(0.89
)
 
(36
)%
 NGLs (per Bbl)
22.04

 
18.40

 
3.64

 
20
 %
 Combined (per Boe)
45.70

 
34.54

 
11.16

 
32
 %
Average Realized Prices with Hedging:
 
 
 
 
 
 
 
Oil (per Bbl)
$
54.70

 
$
52.18

 
$
2.52

 
5
 %
Natural gas (per Mcf)
1.65

 
2.56

 
(0.91
)
 
(36
)%
NGLs (per Bbl)
22.04

 
18.40

 
3.64

 
20
 %
Combined (per Boe)
39.66

 
38.04

 
1.62

 
4
 %
Average Costs (per Boe):
 
 
 
 
 
 
 
Lease operating expense
$
2.99

 
$
3.54

 
$
(0.55
)
 
(16
)%
Gathering, transportation and processing expense
0.40

 
0.34

 
0.06

 
18
 %
Production tax expense
3.74

 
1.87

 
1.87

 
100
 %
Depreciation, depletion and amortization
21.55

 
24.81

 
(3.26
)
 
(13
)%
General and administrative expense (1)
4.88

 
6.31

 
(1.43
)
 
(23
)%

*
Not meaningful.
(1)
Included in general and administrative expense is long-term cash and equity incentive compensation of $5.9 million (or $0.84 per Boe) and $5.5 million (or $1.12 per Boe) for the nine months ended September 30, 2018 and 2017, respectively.


41

Production Revenues and Volumes. Production revenues increased to $322.5 million for the nine months ended September 30, 2018 from $168.5 million for the nine months ended September 30, 2017. The increase in production revenues was due to a 45% increase in production volumes and a 32% increase in average realized prices before hedging. The increase in production volumes increased production revenues by approximately $99.6 million, while average realized prices before hedging increased production revenues by approximately $54.4 million.

The 45% increase in total production from the nine months ended September 30, 2017 to the nine months ended September 30, 2018 was primarily due to a 64% increase in the DJ Basin as a result of new wells placed into production, along with wells acquired in the Merger, offset by the sale of our remaining assets in the Uinta Oil Program in December 2017. Additional information concerning production is set forth in the following table:

 
Nine Months Ended September 30, 2018
 
Nine Months Ended September 30, 2017
 
% 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
4,360

1,207

8,946

7,058

 
2,399

927

5,814

4,295

 
82
%
30
%
54
%
64
%
Other (1)
—

—

—

—

 
530

9

270

584

 
*nm

*nm

*nm

*nm

Total
4,360

1,207

8,946

7,058

 
2,929

936

6,084

4,879

 
49
%
29
%
47
%
45
%

*
Not meaningful.
(1)
Other includes 526 MBbls of oil, 9 MBbls of NGLs and 258 MMcf of natural gas production in the Uinta Oil Program for the nine months ended September 30, 2017.

Lease Operating Expense. LOE decreased to $2.99 per Boe for the nine months ended September 30, 2018 from $3.54 per Boe for the nine months ended September 30, 2017. The decrease per Boe for the nine months ended September 30, 2018 compared with the nine months ended September 30, 2017 is primarily related to operational efficiencies in our legacy DJ Basin assets and the sale of our remaining assets in the Uinta Oil Program in December 2017, which had relatively high LOE costs on a per Boe basis.

Gathering, Transportation and Processing Expense. GTP expense increased to $0.40 per Boe for the nine months ended September 30, 2018 from $0.34 per Boe for the nine months ended September 30, 2017.

Costs incurred to gather, transport and/or process our oil, gas and NGLs prior to the transfer of control to the customer are included in GTP expense. Costs incurred to gather, transport and/or process our oil, gas and NGLs after control has transferred to the customer are considered components of the consideration received from the customer and thus recorded in oil, gas and NGL production revenues. In general, based on specific contract arrangements, costs incurred in the Hereford Field in the DJ Basin, which was acquired in the Merger, are included in GTP expense and costs incurred in the Northeast Wattenberg Field in the DJ Basin are included in production revenues. See the "Revenue Recognition" section in Note 2 for additional information.

GTP expense for the nine months ended September 30, 2018 of $0.40 per Boe is primarily associated with the Hereford Field. We expect GTP expense per Boe to increase in the future as we further develop and increase our production mix from the Hereford Field under the existing contractual arrangements.

Production Tax Expense. Total production taxes increased to $26.4 million for the nine months ended September 30, 2018 from $9.1 million for the nine months ended September 30, 2017. The increase is attributable to the 45% increase in production and the 32% 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 were 8.2% and 7.2% for the nine months ended September 30, 2018 and 2017, respectively. The increase was due to an increase in the effective rate of Colorado severance taxes for the nine months ended September 30, 2018.

Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense for the nine months ended September 30, 2018 and 2017 are summarized below:


42

 
Nine Months Ended September 30,
 
2018
 
2017
 
(in thousands)
Impairment of unproved oil and gas properties (1)
$
—

 
$
8,010

Dry hole expense
—

 
—

Abandonment expense and lease expirations
609

 
326

Total impairment, dry hole costs and abandonment expense
$
609

 
$
8,336


(1)
We recognized an impairment related to unproved oil and gas properties in the Cottonwood Gulch area of the Piceance Basin. We had no current plan to develop this acreage.

Depreciation, Depletion and Amortization. DD&A increased to $152.1 million for the nine months ended September 30, 2018 compared with $119.4 million for the nine months ended September 30, 2017. The increase of $32.7 million was a result of a 45% increase in production, offset by an 13% decrease in the DD&A rate for the nine months ended September 30, 2018 compared with the nine months ended September 30, 2017. The increase in production accounted for a $54.1 million increase in DD&A expense while the decrease in the DD&A rate accounted for a $21.4 million decrease 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, 2018, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $21.55 per Boe compared with $24.81 per Boe for the nine months ended September 30, 2017. The decrease in the depletion rate of 13% is the result of adding proved developed producing reserves at lower costs.

Unused Commitments. Unused commitments expense for each of the nine months ended September 30, 2018 and 2017 consisted of $13.7 million related to gas transportation contracts. 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.

General and Administrative Expense. General and administrative expense increased to $34.4 million for the nine months ended September 30, 2018 from $30.8 million for the nine months ended September 30, 2017, primarily due to an increase in employee compensation and benefits associated with an increase in headcount.

Included in general and administrative expense is long-term cash and equity incentive compensation of $5.9 million and $5.5 million for the nine months ended September 30, 2018 and 2017, respectively. The components of long-term cash and equity incentive compensation for the nine months ended September 30, 2018 and 2017 are shown in the following table:

 
Nine Months Ended September 30,
 
2018
 
2017
 
(in thousands)
Nonvested common stock
$
4,504

 
$
4,437

Nonvested common stock units
791

 
516

Nonvested performance-based shares
—

 
558

Nonvested performance cash units (1)
635

 
(27
)
Total
$
5,930

 
$
5,484


(1)
The nonvested performance cash units are accounted for as liability awards and will be settled in cash for the performance metrics that are met. The expense for the period will increase or decrease based on updated fair values of these awards at each reporting date.


43

Merger Transaction Expense. Merger transaction expense was $6.1 million for the nine months ended September 30, 2018. We entered into the Merger Agreement on December 4, 2017 and closed on March 19, 2018. Transaction expenses included severance, consulting, advisory, legal and other merger-related fees that were incurred during the nine months ended September 30, 2018 and were not capitalized as part of the Merger.

Commodity Derivative Gain (Loss). Commodity derivative gain (loss) was a loss of $128.2 million for the nine months ended September 30, 2018 compared with a gain of $19.7 million for the nine months ended September 30, 2017. The loss for the nine months ended September 30, 2018 is related to fluctuations of oil and natural gas future pricing compared to actual pricing of commodity hedges in place as of September 30, 2018.

The fair value of our open, but not yet settled derivative contracts is based on an income approach using various assumptions, such as quoted forward prices for commodities, risk-free discount rates, volatility factors and time value factors. The mark-to-market fair value of the open commodity derivative contracts will generally be inversely related to the price movement of the underlying commodity. If commodity price trends reverse from period to period, prior unrealized gains may become unrealized losses and vice versa. Higher underlying commodity price volatility will generally lead to higher volatility in our unrealized gains and losses and, by association, the fair value of our commodity derivative contracts. These unrealized gains and losses will impact our net income in the period reported. The mark-to-market fair value can create non-cash volatility in our reported earnings during periods of commodity price volatility. We have experienced such volatility in the past and are likely to experience it in the future. Gains on our derivatives generally indicate lower wellhead revenues in the future while losses indicate higher future wellhead revenues.

The table below summarizes our commodity derivative gains and losses that were recognized in the periods presented:

 
Nine Months Ended September 30,
 
2018
 
2017
 
(in thousands)
Realized gain (loss) on derivatives (1)
$
(42,628
)
 
$
17,062

Prior year unrealized (gain) loss transferred to realized (gain) loss (1)
20,940

 
(2,114
)
Unrealized gain (loss) on derivatives (1)
(106,478
)
 
4,706

Total commodity derivative gain (loss)
$
(128,166
)
 
$
19,654


(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, 2018, approximately 73% of our oil volumes and 15% of our natural gas volumes were subject to financial hedges, which resulted in decreased oil income of $43.2 million and increased natural gas income of $0.6 million after settlements. 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 increased natural gas income of $0.5 million after settlements.

Capital Resources and Liquidity

Our primary sources of liquidity since our formation 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 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 being available to us. 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 2018 and for 2019.

At September 30, 2018, we had cash and cash equivalents of $93.0 million and no amounts outstanding under our Amended Credit Facility. At December 31, 2017, we had cash and cash equivalents of $314.5 million and no amounts

44

outstanding under the credit facility then in place. On September 14, 2018, we entered into the Amended Credit Facility to incorporate the proved reserves and assets acquired in the Merger. The Amended Credit Facility provides for a maximum credit amount of $1.5 billion, an initial elected commitment amount of $500 million, and an initial borrowing base of $500 million, with interest rates and commitment fees unchanged. Our effective borrowing capacity as of September 30, 2018 was reduced by $26.0 million to $474.0 million due to an outstanding irrevocable letter of credit related to a firm transportation agreement.

On March 19, 2018, we completed the Merger, which was effected through the issuance of 100,000,000 shares of our common stock, with a fair value of $484.0 million, and the repayment of $53.9 million of Fifth Creek debt. See Note 4 for additional information related to the Merger.

Cash Flow from Operating Activities

Net cash provided by operating activities for the nine months ended September 30, 2018 and 2017 was $160.2 million and $95.4 million, respectively. The increase in net cash provided by operating activities was primarily due to an increase in production revenues, offset by a decrease in cash from derivative settlements.

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 and cashless collars to receive fixed prices for a portion of our production. At September 30, 2018, we had in place crude oil swaps covering portions of our 2018, 2019 and 2020 production, natural gas swaps covering portions of our 2018 and 2019 production and crude oil cashless collars covering portions of our 2018 and 2019 production.

At September 30, 2018, the estimated fair value of all of our commodity derivative instruments, summarized in the following table, was a net liability of $118.0 million, comprised of current and noncurrent liabilities. We did not enter into any hedges subsequent to September 30, 2018 through October 17, 2018.

Contract
 
Total
Hedged
Volumes
 
Quantity
Type
 
Weighted
Average
Fixed
Price
 
Weighted
Average
Floor
Price
 
Weighted
Average
Ceiling
Price
 
Index
Price (1)
 
Fair Market
Value
(in thousands)
Swap Contracts:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil
 
1,270,140

 
Bbls
 
$
54.63

 
 
 
 
 
WTI
 
$
(23,257
)
Natural gas
 
460,000

 
MMBtu
 
$
2.68

 
 
 
 
 
NWPL
 
105

2019
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil
 
6,704,184

 
Bbls
 
$
58.85

 
 
 
 
 
WTI
 
(80,941
)
Natural gas
 
1,825,000

 
MMBtu
 
$
2.05

 
 
 
 
 
NWPL
 
(162
)
2020
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil
 
2,286,000

 
Bbls
 
$
61.32

 
 
 
 
 
WTI
 
(12,713
)
Cashless Collars:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil
 
184,000

 
Bbls
 
 
 
$
60.00

 
$
77.27

 
WTI
 
(148
)
2019
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil
 
552,000

 
Bbls
 
 
 
$
55.00

 
$
77.56

 
WTI
 
(904
)
Total
 
 
 
 
 
 
 
 
 
 
 
 
 
$
(118,020
)


45

(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.

By removing the price volatility from a portion of our oil and natural gas revenue, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for the relevant period. 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. ("ISDA") 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 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
2018
 
2017
 
(in millions)
DJ Basin
$
380.6

 
$
165.4

Other
0.5

 
9.1

Total
$
381.1

 
$
174.5


 
Nine Months Ended September 30,
 
2018
 
2017
 
(in millions)
Acquisitions of proved and unproved properties and other real estate
$
8.3

 
$
20.2

Drilling, development, exploration and exploitation of oil and natural gas properties
342.8

 
150.1

Gathering and compression facilities
29.1

 
3.9

Geologic and geophysical costs
0.4

 
—

Furniture, fixtures and equipment
0.5

 
0.3

Total
$
381.1

 
$
174.5


Our current estimated capital expenditure budget for 2018 is $500.0 million to $510.0 million. The full year 2018 capital budget takes into account the expanded scope of our operations due to the completion of the Merger. The budget includes facilities costs and excludes acquisitions. We may adjust capital expenditures as business conditions and operating results warrant. The amount, timing and allocation of capital expenditures is generally discretionary and within our control. If oil, natural gas and NGL prices decline to 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, cash under the Amended Credit Facility and cash flow from operations to fund our 2018 and 2019 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 operations and other capital resources will provide sufficient amounts of cash flow to maintain planned levels of

46

capital expenditures.

Financing Activities

Merger Financing. On March 19, 2018, we completed the Merger with Fifth Creek. The Merger was effected through the issuance of 100,000,000 shares of our common stock, with a fair value of $484.0 million, and the repayment of $53.9 million of Fifth Creek debt.

Amended Credit Facility. There have been no borrowings under the Amended Credit Facility (or, as applicable, the facility then in place) to date in 2018 and there were no such borrowings in 2017. On September 14, 2018, we entered into the Amended Credit Facility to incorporate the proved reserves and assets acquired in the Merger. The Amended Credit Facility provides for a maximum credit amount of $1.5 billion, an initial elected commitment amount of $500 million, and an initial borrowing base of $500 million, with interest rates and commitment fees unchanged. The Amended Credit Facility extended the maturity date of the facility to September 14, 2023. Borrowing bases are 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.

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 2018 budget at current commodity prices.

Our outstanding debt is summarized below:

 
 
As of September 30, 2018
 
As of December 31, 2017
 
Maturity Date
Principal
 
Unamortized
Discount
 
Carrying
Amount
 
Principal
 
Unamortized
Discount
 
Carrying
Amount
 
 
(in thousands)
Amended Credit Facility
September 14, 2023
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

7.0% Senior Notes
October 15, 2022
350,000

 
(3,419
)
 
346,581

 
350,000

 
(4,033
)
 
345,967

8.75% Senior Notes
June 15, 2025
275,000

 
(4,575
)
 
270,425

 
275,000

 
(5,080
)
 
269,920

Lease Financing Obligation
August 10, 2020
1,978

 
—

 
1,978

 
2,328

 
(2
)
 
2,326

Total Debt
 
$
626,978

 
$
(7,994
)
 
$
618,984

 
$
627,328

 
$
(9,115
)
 
$
618,213

Less: Current Portion of Long-Term Debt
 
1,978

 
—

 
1,978

 
469

 
—

 
469

Total Long-Term Debt (1)
 
$
625,000

 
$
(7,994
)
 
$
617,006

 
$
626,859

 
$
(9,115
)
 
$
617,744


(1)
See Note 5 for additional information.

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 could 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, 2018 is provided in the following table:


47

 
Payments Due by Year
Year 1
 
Year 2
 
Year 3
 
Year 4
 
Year 5
 
Thereafter
 
Total
 
Twelve Months Ended September 30, 2019
 
Twelve Months Ended September 30, 2020
 
Twelve Months Ended September 30, 2021
 
Twelve Months Ended September 30, 2022
 
Twelve Months Ended September 30, 2023
 
After
September 30, 2023
 
 
 
(in thousands)
Notes payable (1)
$
553

 
$
184

 
$
—

 
$
—

 
$
—

 
$
—

 
$
737

7.0% Senior Notes (2)
24,500

 
24,500

 
24,500

 
24,500

 
362,250

 
—

 
460,250

8.75% Senior Notes (3)
24,063

 
24,063

 
24,063

 
24,063

 
24,063

 
323,123

 
443,438

Lease Financing Obligation (4)
2,003

 
—

 
—

 
—

 
—

 
—

 
2,003

Office and office equipment leases and other (5)
6,674

 
2,096

 
2,909

 
2,752

 
2,641

 
11,140

 
28,212

Firm transportation agreements (6)
18,490

 
18,691

 
15,575

 
—

 
—

 
—

 
52,756

Gas gathering and processing agreements (7)(8)
12,260

 
2,216

 
2,039

 
500

 
—

 
—

 
17,015

Asset retirement obligations (9)
1,357

 
1,140

 
1,238

 
1,160

 
1,351

 
22,147

 
28,393

Derivative liability (10)
87,470

 
28,126

 
2,424

 
—

 
—

 
—

 
118,020

Total
$
177,370

 
$
101,016

 
$
72,748

 
$
52,975

 
$
390,305

 
$
356,410

 
$
1,150,824


(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 January 31, 2020. There is currently no balance outstanding under the Amended Credit Facility due September 14, 2023.
(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 $12.3 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.
(4)
The Lease Financing Obligation is calculated based on the aggregate undiscounted minimum future lease payments, which include both an interest and principal component. We have elected to exercise the early buyout option pursuant to which we will purchase the equipment for $1.8 million on February 10, 2019.
(5)
The lease for our principal office in Denver, Colorado expires in March 2019. Due to the Merger, we acquired the office lease of Fifth Creek in Greenwood Village, Colorado, which extends through July 2023. In addition, we entered into a new lease for office space in Denver, Colorado which will serve as our principal office starting in April 2019 through April 2028.
(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)
We have entered into gas gathering and processing contracts which require us to deliver a minimum volume of natural gas to midstream entities for gathering and processing on a monthly basis. The contracts require us to pay a fee associated with the contracted volumes regardless of the amount delivered.
(8)
Includes a reimbursement obligation of $6.9 million in the twelve months ended September 30, 2019. The reimbursement obligation requires us to pay a monthly gathering and processing fee per Mcf of production over a one year period to reimburse a midstream entity for its costs to construct gas gathering and processing facilities. If the costs are not reimbursed by us via the monthly gathering and processing fees through August 2019, we must pay the difference.
(9)
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 Bill Barrett's Annual Report on Form 10-K for the year ended December 31, 2017 for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.
(10)
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, 2018. 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 Bill Barrett's Annual Report on Form 10-K for the year ended December 31, 2017 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, 2018.

Trends and Uncertainties

48


We refer you to the corresponding section in Part II, Item 7 of Bill Barrett's Annual Report on Form 10-K for the year ended December 31, 2017 for a discussion of trends and uncertainties that may affect our financial condition or liquidity. Also see "-Overview" above and "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 Bill Barrett's Annual Report on Form 10-K for the year ended December 31, 2017 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.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in oil, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our primary market risk exposure is to the prices we receive for our production. Commodity pricing is primarily driven by the prevailing worldwide price for crude oil and spot regional market prices applicable to our U.S. oil and natural gas production. Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for future production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price. Based on our average daily production and our derivative contracts in place for the nine months ended September 30, 2018, our income before income taxes would have decreased by approximately $0.8 million for each $1.00 per barrel decrease in crude oil prices, approximately $0.8 million for each $0.10 decrease per MMBtu in natural gas prices and approximately $1.1 million for each $1.00 per barrel decrease in NGL prices.

We routinely enter into commodity hedges relating to a portion of our projected production revenue through various financial transactions that hedge future prices received. These transactions may include financial price swaps whereby we will receive a fixed price and pay a variable market price to the contract counterparty. These commodity hedging activities are intended to support oil, natural gas and NGL prices at targeted levels that provide an acceptable rate of return and to manage our exposure to oil, natural gas and NGL price fluctuations. We do not enter into any market risk sensitive instruments for trading purposes.

As of October 17, 2018, we have swap contracts related to oil and natural gas volumes in place for the following periods indicated:
 
October – December 2018
 
For the year 2019
 
For the year 2020
 
Derivative
Volumes
 
Weighted Average Price
 
Derivative Volumes
 
Weighted Average Price
 
Derivative Volumes
 
Weighted Average Price
Oil (Bbls)
1,270,140

 
$
54.63

 
6,704,184

 
$
58.85

 
2,286,000

 
$
61.32

Natural Gas (MMbtu)
460,000

 
$
2.68

 
1,825,000

 
$
2.05

 
—

 
$
—


As of October 17, 2018, we have cashless collars related to oil volumes in place for the following periods indicated:
 
October – December 2018
 
For the year 2019
 
Derivative
Volumes
 
Weighted Average Floor Price
 
Weighted Average Ceiling Price
 
Derivative
Volumes
 
Weighted Average Floor Price
 
Weighted Average Ceiling Price
Oil (Bbls)
184,000

 
$
60.00

 
$
77.27

 
552,000

 
$
55.00

 
$
77.56


Further detail of these hedges is summarized in the table presented under "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations— Capital Resources and Liquidity— Commodity Hedging Activities."


49


Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures. As of September 30, 2018, we carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective as of September 30, 2018.

Changes in Internal Controls. There was no change in our internal control over financial reporting during the third fiscal quarter of 2018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

We are not a party to any material pending legal or governmental proceedings other than ordinary routine litigation incidental to our business. While the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management does not believe that the resolution of any currently pending proceeding will have a material effect on our financial condition or results of operations.

Item 1A. Risk Factors.

Other than the risk factor discussed below, as of the date of this filing, there have been no material changes or updates to the risk factors previously disclosed in the "Risk Factors" section of Bill Barrett's Annual Report on Form 10-K for the year ended December 31, 2017. An investment in our securities involves various risks. When considering an investment in our Company, you should carefully consider all of the risk factors described in Bill Barrett's Annual Report on Form 10-K for the year ended December 31, 2017 and subsequent reports filed with the SEC. These risks and uncertainties are not the only ones facing us, and there may be additional matters that we are unaware of or that we currently consider immaterial. All of these could adversely affect our business, financial condition, results of operations and cash flows and, thus, the value of an investment in our Company.

Proposition 112 could have a variety of adverse effects on our business and operations.

As discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operation-Overview”, in November 2018, voters in Colorado will vote on a setback initiative, Proposition 112. Proposition 112 would amend the Oil and Gas Conservation Act by prohibiting the Colorado Oil and Gas Conservation Commission (and perhaps other government entities) from permitting new oil and gas development closer than 2,500 feet from occupied structures or vulnerable areas such as playgrounds, parks, public open space and water bodies, including irrigation canals, perennial or intermittent streams and creeks. Development on federal land is excluded from the prohibition. The state and local governments are also empowered to expand the list of vulnerable areas and to increase the “buffer zone” to more than 2,500 feet. If adopted, Proposition 112 would impact our development activities on more than two-thirds of the well pads located on our currently configured drilling units, and this would have an adverse impact on our drilling inventory, future growth opportunities and costs. In addition, the passage of Proposition 112 would add risk for all oil and gas companies operating in Colorado with respect to capital availability, midstream investment, availability of oil field services, the ability to attract and retain qualified personnel and the ability to satisfy volume commitments. Moreover, even if Proposition 112 is defeated, legislation may be introduced to address public concerns about oil and gas development through setbacks of less than 2,500 feet, increased local control, emission limits or other means.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

Unregistered Sales of Securities

There were no sales of unregistered equity securities during the period covered by this report.

Issuer Purchases of Equity Securities

The following table contains information about our acquisitions of equity securities during the three months ended September 30, 2018:

50


Period
 
Total
Number of
Shares (1)
 
Weighted
Average Price
Paid Per
Share
 
Total Number of 
Shares (or Units)
Purchased as
Part of Publicly
Announced Plans
or Programs
 
Maximum Number 
(or Approximate 
Dollar Value)
of Shares (or
Units) that May
Yet Be Purchased
Under the Plans or
Programs
July 1 – 31, 2018
 
1,764

 
$
6.51

 
—

 
—

August 1 – 31, 2018
 
4,848

 
5.82

 
—

 
—

September 1 – 30, 2018
 
769

 
5.05

 
—

 
—

Total
 
7,381

 
5.90

 
—

 
—


(1)
Represents shares delivered by employees to satisfy tax withholding obligations resulting from the vesting of restricted shares of common stock issued pursuant to our employee incentive plans.

Item 3. Defaults upon Senior Securities.

Not applicable.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

Not applicable.

Item 6. Exhibits.

Exhibit
Number
 
Description of Exhibits
10.1
 
 
 
 
31.1
  
 
 
 
31.2
  
 
 
 
32.1
  
 
 
 
32.2
  
 
 
 
101.INS
  
XBRL Instance Document
 
 
 
101.SCH
 
XBRL Taxonomy Extension Schema Document
 
 
 
101.CAL
 
XBRL Taxonomy Extension Calculation Linkbase Document
 
 
 
101.DEF
 
XBRL Taxonomy Extension Definition Linkbase Document
 
 
 
101.LAB
 
XBRL Taxonomy Extension Label Linkbase Document

51

Exhibit
Number
 
Description of Exhibits
 
 
 
101.PRE
 
XBRL Taxonomy Extension Presentation Linkbase Document


52

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 
 
 
 
 
 
 
HIGHPOINT RESOURCES CORPORATION
 
 
 
 
Date:
October 31, 2018
By:
 
/s/ R. Scot Woodall
 
 
 
 
R. Scot Woodall
 
 
 
 
Chief Executive Officer and President
 
 
 
 
(Principal Executive Officer)
 
 
 
 
Date:
October 31, 2018
By:
 
/s/ David R. Macosko
 
 
 
 
David R. Macosko
 
 
 
 
Senior Vice President-Accounting
 
 
 
 
(Principal Accounting Officer)

53

HighPoint Resources Corp Reports