Quarterly Report (10-q)

Date : 11/12/2019 @ 1:47PM
Source : Edgar (US Regulatory)
Stock : Chaparral Energy Inc (CHAP)
Quote : 0.9169  0.0042 (0.46%) @ 12:59AM
After Hours
Last Trade
Last $ 0.92 ▲ 0.00 (0.01%)

Quarterly Report (10-q)




 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2019
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from              to             
Commission file number: 001-38602
 
 
 
Chaparral Energy, Inc.
(Exact name of registrant as specified in its charter)
 
 
 
Delaware
 
73-1590941
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
 
701 Cedar Lake Boulevard
Oklahoma City, Oklahoma
 
73114
(Address of principal executive offices)
 
(Zip code)
(405) 478-8770
(Registrant’s telephone number, including area code)
 
 
 
Securities registered pursuant to Section 12(b) of the Act:
Title of class
Trading Symbol(s)
Name of each exchange on which registered
Class A common stock, par value, $0.01 per share
CHAP
The New York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☒    No  ☐
Indicate by check mark whether the registrant has submitted electronically, if any, every Interactive Data File required to be submitted 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 such files).    Yes  ☒    No  ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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
¨
Accelerated filer
x
Non-accelerated filer
¨
Smaller reporting company
¨
Emerging growth company
¨
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.      ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ☒
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.                  Yes  ☒    No  ☐
Number of shares outstanding of each of the issuer’s classes of common stock as of November 8, 2019:
Class
Number of Shares
Class A Common Stock, $0.01 par value
46,405,086






CHAPARRAL ENERGY, INC.
Index to Form 10-Q
 
 
Page
 
 
 
7
7
8
9
10
11
33
33
35
43
46
48
48
49
51
 
52
52
52
52
53
55






CAUTIONARY NOTE
REGARDING FORWARD-LOOKING STATEMENTS
This report includes statements that constitute forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties. These statements may relate to, but are not limited to, information or assumptions about us, our capital and other expenditures, dividends, financing plans, capital structure, cash flow, pending legal and regulatory proceedings and claims, including environmental matters, future economic performance, operating income, cost savings, and management’s plans, strategies, goals and objectives for future operations and growth. These forward-looking statements generally are accompanied by words such as “intend,” “anticipate,” “believe,” “estimate,” “expect,” “should,” “seek,” “project,” “plan” or similar expressions. Any statement that is not a historical fact is a forward-looking statement. It should be understood that these forward-looking statements are necessarily estimates reflecting the best judgment of senior management, not guarantees of future performance. They are subject to a number of assumptions, risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the forward-looking statements. Forward-looking statements in this report may include, for example, statements about:
fluctuations in demand or the prices received for oil and natural gas;
the amount, nature and timing of capital expenditures;
drilling, completion and performance of wells;
inventory of drillable locations;
competition;
government regulations;
timing and amount of future production of oil and natural gas;
costs of exploiting and developing properties and conducting other operations, in the aggregate and on a per-unit equivalent basis;
changes in proved reserves;
operating costs and other expenses;
our future financial condition, results of operations, revenue, cash flows and expenses;
estimates of proved reserves;
exploitation of property acquisitions; and
marketing of oil and natural gas.
These forward-looking statements represent intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors. Many of those factors are outside of our control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. In addition to the risk factors described in Part II, Item 1A. Risk Factors, of this report and Part I, Item 1A. Risk Factors, in our Annual Report on Form 10-K for the year ended December 31, 2018, the risks and uncertainties include or relate to:
worldwide supply of and demand for oil and natural gas;
volatility and declines in oil and natural gas prices;
geologic and reservoir complexity and variability;
drilling plans (including scheduled and budgeted wells);
the number, timing or results of any wells;
changes in wells operated and in reserve estimates;
future growth and expansion;
future exploration;
integration of existing and new technologies into operations;
future capital expenditures (or funding thereof) and working capital;
effectiveness and extent to our risk management activities;
availability and cost of equipment and services;
risks related to the concentration of our operations in the mid-continent geographic area;
borrowings and capital resources and liquidity;
covenant compliance under instruments governing any of our existing or future indebtedness;
changes in strategy and business discipline, including our post-emergence business strategy;
future tax matters;
legislation and regulatory initiatives;
loss of key personnel;
geopolitical events affecting oil and natural gas prices;
outcome, effects or timing of legal proceedings (including environmental litigation);

3




the ability to generate additional prospects; and
the ability to successfully complete merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture, and the success of the business following a merger, acquisition or divestiture.
Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions may change the schedule of any future production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.
Should one or more of these risks or uncertainties materialize, or should any of our assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements contained herein. We undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws. All forward-looking statements included herein are expressly qualified in their entirety by the cautionary statements contained or referred to in this section.


4




GLOSSARY OF CERTAIN DEFINED TERMS
The terms defined in this section are used throughout this Form 10-Q:
Bbl
One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate, or natural gas liquids.
 
 
BBtu
One billion British thermal units.
 
 
Boe
Barrels of oil equivalent using the ratio of six thousand cubic feet of natural gas to one barrel of oil.
 
 
Boe/d
Barrels of oil equivalent per day.
 
 
Btu
British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
 
 
Chapter 11 Cases
The voluntary petitions filed by Chaparral Energy, Inc. and its subsidiaries on May 9, 2016 seeking relief under Title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware commencing cases for relief under chapter 11 of the Bankruptcy Code.
 
 
Completion
The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned.
 
 
CO2
Carbon dioxide.
 
 
Credit Agreement
Tenth Restated Credit Agreement, as amended, by and among Chaparral Energy, Inc., Royal Bank of Canada as Administrative Agent and the Lenders thereto.
 
 
Dry well or dry hole
An exploratory, development or extension well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
 
 
Effective Date
Date of emergence from bankruptcy, or March 21, 2017.
 
 
Enhanced oil recovery (EOR)
The use of any improved recovery method, including injection of CO2 or polymer, to remove additional oil after Secondary Recovery.
 
 
Field
An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
 
 
MBbls
One thousand barrels of crude oil, condensate, or natural gas liquids.
 
 
MBoe
One thousand barrels of crude oil equivalent.
 
 
Mcf
One thousand cubic feet of natural gas.
 
 
MMBtu
One million British thermal units.
 
 
MMcf
One million cubic feet of natural gas.
 
 
Natural gas liquids (NGLs)
Those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, or other methods in gas processing or cycling plants. Natural gas liquids primarily include propane, butane, isobutane, pentane, hexane and natural gasoline.
 
 
NYMEX
The New York Mercantile Exchange.

5




Play
A term describing an area of land following the identification by geologists and geophysicists of reservoirs with potential oil and natural gas reserves.
 
 
Proved developed reserves
Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well.
 
 
Proved reserves
The quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.
 
 
Proved undeveloped reserves
Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
 
 
PV-10 value
When used with respect to oil and natural gas reserves, PV-10 value means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, excluding escalations of prices and costs based upon future conditions, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10%.
 
 
Reorganization Plan
First Amended Joint Plan of Reorganization for Chaparral Energy, Inc. and its Affiliate Debtors under Chapter 11 of the Bankruptcy Code.
 
 
SEC
The Securities and Exchange Commission.
 
 
Senior Notes
Our 8.75% senior notes due 2023.
 
 
STACK
The STACK is a play in the Anadarko basin of Oklahoma in which we operate and derives its name from the acronym standing for Sooner Trend Anadarko Canadian Kingfisher. It is a horizontal drilling play in an area with multiple productive reservoirs which had previously been drilled with vertical wells. Our STACK areas encompass all or parts of Canadian, Garfield, Kingfisher, Major, Blaine, Dewey, Woodward, Logan and Grady counties in Oklahoma. Our STACK areas borders include the Nemaha Ridge (East), the Chester outcrop (North), and deep gas bearing characteristics (South and West). This thick column (500’+) includes multiple, stacked, and productive reservoirs, each with high oil saturations and includes the Woodford, Osage, Meramec, Oswego, and other intervals within the STACK Areas.
 
 
Unit
The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.


6

Chaparral Energy, Inc. and Subsidiaries
Consolidated Balance Sheets
(Unaudited) 


PART I — FINANCIAL INFORMATION
ITEM 1.
FINANCIAL STATEMENTS
(dollars in thousands, except share data)
 
September 30, 2019
 
December 31, 2018
Assets
 
 
 
 

Current assets:
 
 

 
 

Cash and cash equivalents
 
$
21,534

 
$
37,446

Accounts receivable, net
 
45,145

 
66,087

Inventories, net
 
3,915

 
4,059

Prepaid expenses
 
2,200

 
2,814

Derivative instruments
 
11,446

 
24,025

Total current assets
 
84,240

 
134,431

Property and equipment, net
 
14,265

 
43,096

Right of use assets from operating leases
 
5,853

 

Oil and natural gas properties, using the full cost method:
 
 

 
 

Proved
 
1,224,620

 
915,333

Unevaluated (excluded from the amortization base)
 
373,761

 
466,616

Accumulated depreciation, depletion, amortization and impairment
 
(558,339
)
 
(221,431
)
Total oil and natural gas properties
 
1,040,042

 
1,160,518

Derivative instruments
 
1,111

 
2,199

Other assets
 
393

 
425

Total assets
 
$
1,145,904

 
$
1,340,669

Liabilities and stockholders’ equity
 
 

 
 

Current liabilities:
 
 

 
 

Accounts payable and accrued liabilities
 
$
81,269

 
$
73,779

Accrued payroll and benefits payable
 
6,970

 
10,976

Accrued interest payable
 
5,673

 
13,359

Revenue distribution payable
 
16,275

 
26,225

Long-term debt and financing leases, classified as current
 
586

 
12,371

Derivative instruments
 
70

 

Total current liabilities
 
110,843

 
136,710

Long-term debt and financing leases, less current maturities
 
400,518

 
295,100

Derivative instruments
 
3,022

 
1,542

Noncurrent operating lease obligations
 
1,239

 

Deferred compensation
 
175

 
540

Asset retirement obligations
 
22,384

 
22,090

Commitments and contingencies (Note 10)
 


 


Stockholders’ equity:
 
 

 
 

Preferred stock, 5,000,000 shares authorized, none issued and outstanding
 

 

Common stock, $0.01 par value, 192,130,071 shares authorized; 46,876,041 issued and 46,408,285 outstanding at September 30, 2019 and 46,651,616 issued and 46,390,513 outstanding at December 31, 2018
 
469

 
467

Additional paid in capital
 
978,525

 
974,616

Treasury stock, at cost, 467,756 and 261,103 shares as of September 30, 2019 and December 31, 2018
 
(6,107
)
 
(4,936
)
Accumulated deficit
 
(365,164
)
 
(85,460
)
Total stockholders’ equity
 
607,723

 
884,687

Total liabilities and stockholders’ equity
 
$
1,145,904

 
$
1,340,669

 
The accompanying notes are an integral part of these consolidated financial statements.

7




Chaparral Energy, Inc. and Subsidiaries
Consolidated Statements of Operations
(Unaudited)
 
 
 
Three months ended
 
Nine months ended
(in thousands, except share and per share data)
 
September 30, 2019
 
September 30, 2018
 
September 30, 2019
 
September 30, 2018
Revenues:
 
 
 
 
 
 

 
 

Net commodity sales
 
$
51,838

 
$
65,519

 
$
167,164

 
$
181,835

Sublease revenue
 
799

 
1,199

 
3,195

 
3,595

Total revenues
 
52,637

 
66,718

 
170,359

 
185,430

Costs and expenses:
 
 
 
 
 
 

 
 

Lease operating
 
12,372

 
12,493

 
38,037

 
42,045

Production taxes
 
2,925

 
4,028

 
9,607

 
9,473

Depreciation, depletion and amortization
 
28,021

 
22,252

 
82,018

 
63,765

Impairment of oil and gas assets
 
147,686

 

 
261,001

 

Impairment of other assets
 

 

 
6,407

 

General and administrative
 
7,809

 
9,021

 
23,437

 
28,718

Cost reduction initiatives
 

 
210

 

 
1,034

Other
 
269

 
402

 
1,075

 
1,633

Total costs and expenses
 
199,082

 
48,406

 
421,582

 
146,668

Operating (loss) income
 
(146,445
)
 
18,312

 
(251,223
)
 
38,762

Non-operating income (expense):
 
 
 
 
 
 
 
 
Interest expense
 
(5,994
)
 
(4,205
)
 
(16,129
)
 
(7,315
)
Derivative gains (losses)
 
23,601

 
(23,677
)
 
(9,681
)
 
(72,464
)
Gain (loss) on sale of assets
 
141

 
(2,024
)
 
631

 
(2,599
)
Loss on extinguishment of debt
 
(1,624
)
 

 
(1,624
)
 

Other (expense) income, net
 
(84
)
 
19

 
(372
)
 
123

Net non-operating income (expense)
 
16,040

 
(29,887
)
 
(27,175
)
 
(82,255
)
Reorganization items, net
 
(530
)
 
(493
)
 
(1,306
)
 
(2,010
)
Loss before income taxes
 
(130,935
)
 
(12,068
)
 
(279,704
)
 
(45,503
)
Income tax expense
 

 

 

 

Net loss
 
$
(130,935
)
 
$
(12,068
)
 
$
(279,704
)
 
$
(45,503
)
Earnings per share:
 
 
 
 
 
 

 
 

Basic for Class A and Class B (1)
 
(2.86
)
 
(0.27
)
 
(6.13
)
 
(1.01
)
Diluted for Class A and Class B (1)
 
(2.86
)
 
(0.27
)
 
(6.13
)
 
(1.01
)
Weighted average shares used to compute earnings per share:
 
 
 
 
 
 

 
 

Basic for Class A and Class B (1)
 
45,716,522

 
45,333,745

 
45,605,798

 
45,272,595

Diluted for Class A and Class B (1)
 
45,716,522

 
45,333,745

 
45,605,798

 
45,272,595

 ____________________________________________________________
(1) See “Note 2: Earnings per share.”





The accompanying notes are an integral part of these consolidated financial statements.

8




Chaparral Energy, Inc. and Subsidiaries
Consolidated Statement of Stockholders’ Equity
(Unaudited)
 
 
 
Common stock
 
 
 
 
 
 
 
 
(dollars in thousands)
 
Shares
outstanding
 
Amount
 
Additional
paid in capital
 
Treasury
stock
 
Accumulated
deficit
 
Total
As of December 31, 2017
 
46,827,762

 
$
468

 
$
961,200

 
$

 
$
(118,902
)
 
$
842,766

Stock-based compensation
 

 

 
5,581

 

 

 
5,581

Restricted stock forfeited
 
(83,770
)
 
(1
)
 

 

 

 
(1
)
Repurchase of common stock
 
(63,919
)
 

 

 
(1,422
)
 

 
(1,422
)
Net loss
 

 

 

 

 
(11,442
)
 
(11,442
)
Balance at March 31, 2018
 
46,680,073

 
467

 
966,781

 
(1,422
)
 
(130,344
)
 
835,482

Stock-based compensation
 
55,000

 

 
2,336

 

 

 
2,336

Restricted stock forfeited
 
(81,683
)
 

 

 

 

 

Repurchase of common stock
 
(192,976
)
 

 

 
(3,450
)
 

 
(3,450
)
Net loss
 

 

 

 

 
(21,993
)
 
(21,993
)
Balance at June 30, 2018
 
46,460,414

 
467

 
969,117

 
(4,872
)
 
(152,337
)
 
812,375

Stock-based compensation
 

 

 
3,112

 

 

 
3,112

Restricted stock forfeited
 

 

 

 

 

 

Repurchase of common stock
 

 

 

 

 

 

Net loss
 

 

 

 

 
(12,068
)
 
(12,068
)
Balance at September 30, 2018
 
46,460,414

 
$
467

 
$
972,229

 
$
(4,872
)
 
$
(164,405
)
 
$
803,419


 
 
Common stock
 
 
 
 
 
 
 
 
(dollars in thousands)
 
Shares
outstanding
 
Amount
 
Additional
paid in capital
 
Treasury
stock
 
Accumulated
deficit
 
Total
As of December 31, 2018
 
46,390,513

 
$
467

 
$
974,616

 
$
(4,936
)
 
$
(85,460
)
 
$
884,687

Stock-based compensation
 
94,078

 
1

 
1,423

 

 

 
1,424

Restricted stock forfeited
 
(97,113
)
 
(1
)
 

 

 

 
(1
)
Repurchase of common stock
 
(80,422
)
 

 

 
(463
)
 

 
(463
)
Net loss
 

 

 

 

 
(103,540
)
 
(103,540
)
Balance at March 31, 2019
 
46,307,056

 
467

 
976,039

 
(5,399
)
 
(189,000
)
 
782,107

Stock-based compensation
 
160,400

 
1

 
1,249

 

 

 
1,250

Restricted stock forfeited
 

 

 

 

 

 

Repurchase of common stock
 
(126,231
)
 

 

 
(708
)
 

 
(708
)
Issuance of common stock - litigation settlement
 
76,217

 
1

 
323

 

 

 
324

Net loss
 

 

 

 

 
(45,229
)
 
(45,229
)
Balance at June 30, 2019
 
46,417,442

 
469

 
977,611

 
(6,107
)
 
(234,229
)
 
737,744

Stock-based compensation
 
17,512

 

 
924

 

 

 
924

Restricted stock forfeited
 
(26,669
)
 

 

 

 

 

Cash settlement of stock based awards
 

 

 
(10
)
 

 

 
(10
)
Net loss
 

 

 

 

 
(130,935
)
 
(130,935
)
Balance at September 30, 2019
 
46,408,285

 
$
469

 
$
978,525

 
$
(6,107
)
 
$
(365,164
)
 
$
607,723

 

The accompanying notes are an integral part of these consolidated financial statements.

9




Chaparral Energy, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(Unaudited)
 
 
 
Nine months ended
(in thousands)
 
September 30, 2019
 
September 30, 2018
Cash flows from operating activities
 
 
 
 

Net loss
 
$
(279,704
)
 
$
(45,503
)
Adjustments to reconcile net loss to net cash provided by operating activities
 
 
 
 

Depreciation, depletion and amortization
 
82,018

 
63,765

Derivative losses
 
9,681

 
72,464

Impairment of oil and gas assets
 
261,001

 

Impairment of other assets
 
6,407

 

(Gain) loss on sale of assets
 
(631
)
 
2,599

Other
 
3,630

 
4,376

Change in assets and liabilities
 
 

 
 

Accounts receivable
 
20,446

 
(6,743
)
Inventories
 
144

 
(1,415
)
Prepaid expenses and other assets
 
645

 
322

Accounts payable and accrued liabilities
 
(24,685
)
 
(12,383
)
Revenue distribution payable
 
(9,950
)
 
10,895

Deferred compensation
 
1,534

 
7,890

Net cash provided by operating activities
 
70,536

 
96,267

Cash flows from investing activities
 
 

 
 

Expenditures for property, plant, and equipment and oil and natural gas properties
 
(202,830
)
 
(252,731
)
Proceeds from asset dispositions
 
14,333

 
36,335

Proceeds from (payments on) derivative instruments, net
 
5,536

 
(16,642
)
Net cash used in investing activities
 
(182,961
)
 
(233,038
)
Cash flows from financing activities
 
 

 
 

Proceeds from long-term debt
 
110,000

 
116,000

Repayment of long-term debt
 
(8,682
)
 
(243,554
)
Proceeds from Senior Notes
 

 
300,000

Principal payments under financing lease obligations
 
(2,002
)
 
(2,003
)
Payment of debt issuance costs and other financing fees
 
(20
)
 
(7,572
)
Debt extinguishment costs
 
(1,602
)
 

Cash settlements of stock based awards
 
(10
)
 

Treasury stock purchased
 
(1,171
)
 
(4,872
)
Net cash provided by financing activities
 
96,513

 
157,999

Net (decrease) increase in cash and cash equivalents
 
(15,912
)
 
21,228

Cash and cash equivalents, at beginning of period
 
37,446

 
27,732

Cash and cash equivalents, at end of period
 
$
21,534

 
$
48,960




The accompanying notes are an integral part of these consolidated financial statements.

10

Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited)
(dollars in thousands, except per share amounts)



Note 1: Nature of operations and summary of significant accounting policies

Nature of operations

Chaparral Energy, Inc. and its subsidiaries (collectively, “we”, “our”, “us”, or the “Company”) are involved in the exploration, development, production, operation and acquisition of oil and natural gas properties. Our properties are located primarily in Oklahoma and our commodity products include crude oil, natural gas and natural gas liquids.

Interim financial statements

The accompanying unaudited consolidated interim financial statements of the Company have been prepared in accordance with the rules and regulations of the SEC and do not include all of the financial information and disclosures required by accounting principles generally accepted in the United States of America (“GAAP”) for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2018, as amended.

The financial information as of September 30, 2019, and for the three and nine months ended September 30, 2019 and 2018, is unaudited. The financial information as of December 31, 2018 has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2018. In management’s opinion, such information contains all adjustments considered necessary for a fair presentation of the results of the interim periods. The results of operations for the three and nine months ended September 30, 2019 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2019.

Certain reclassifications have been made to prior period financial statements to conform to current period presentation. The reclassifications had no effect on our previously reported results of operations.

Cash and cash equivalents

We maintain cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. As of September 30, 2019, cash with a recorded balance totaling approximately $20,379 was held at JP Morgan Chase Bank, N.A. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk on such accounts.

Accounts receivable

We have receivables from joint interest owners and oil and natural gas purchasers which are generally uncollateralized. Accounts receivable consisted of the following:
 
 
September 30,
2019
 
December 31,
2018
Joint interests
 
$
18,605

 
$
31,573

Accrued commodity sales
 
23,408

 
30,287

Derivative settlements
 
2,820

 
2,092

Other
 
1,412

 
3,375

Allowance for doubtful accounts
 
(1,100
)
 
(1,240
)
 
 
$
45,145

 
$
66,087

 
Inventories

Inventories consisted of the following:
 
 
September 30,
2019
 
December 31,
2018
Equipment inventory
 
$
3,573

 
$
3,663

Commodities
 
521

 
574

Inventory valuation allowance
 
(179
)
 
(178
)
 
 
$
3,915

 
$
4,059


11

Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited)
(dollars in thousands, except per share amounts)



Property and equipment, net

Major classes of property and equipment are shown in the following table:
 
 
September 30,
2019
 
December 31,
2018
Machinery and equipment
 
$
7,249

 
$
21,482

Office and computer equipment
 
6,951

 
6,183

Automobiles and trucks
 
4,911

 
3,548

Building and improvements
 
1,899

 
18,693

Furniture and fixtures
 
8

 
520

 
 
21,018

 
50,426

Less accumulated depreciation, amortization and impairment
 
9,271

 
12,449

 
 
11,747

 
37,977

Land
 
2,518

 
5,119

 
 
$
14,265

 
$
43,096


Impairment of headquarters building and subsequent sales. During the second quarter of 2019, we commenced efforts to locate a buyer for our headquarters building. In conjunction with these efforts, we obtained a third party valuation on the fair value of the property. The valuation appraised the property at an amount lower than its net book value at the time. Based on this market appraisal and our expectations that, more likely than not, the headquarters building would be sold before the end of its useful life, we determined that the net book value of the property would not be recoverable. As a result, we recorded an impairment of $6,407 in June 2019 to write-down the net book value of the property to its fair value based on its market appraisal.

On August 5, 2019, we entered into a real estate purchase and sale agreement for the sale of the building housing our headquarters along with adjacent land, furniture and fixtures. We closed the sale on August 29, 2019, for net proceeds of $11,494 while recognizing an immaterial loss on disposal. The proceeds from the sale were utilized to pay off the outstanding balance of the real estate mortgage note on the property. We incurred a prepayment penalty of $1,624 on the mortgage early payoff which we recorded as a “Loss on extinguishment of debt” on our consolidated statements of operations. Conditioned upon closing of this sale, we entered into a leaseback agreement with the buyer for a portion of the office space, which we discuss in “Note 5: Leases.”

Our property and equipment balance as of December 31, 2018, included CO2 compressors that were held under finance leases and simultaneously subleased to the buyer of our former EOR oil and natural gas properties (the “Sublessee”). In September 2019, U.S. Bank, the originating lessor, entered into agreements with the Sublessee which resulted in the discharge of all our obligations with respect to these compressor leases and the removal of the associated assets and elimination of associated debt from our consolidated balance sheet. 

Oil and natural gas properties

Capitalized Costs. We use the full cost method of accounting for oil and natural gas properties and activities. Accordingly, we capitalize all costs incurred in connection with the exploration for and development of oil and natural gas reserves. Proceeds from the disposition of oil and natural gas properties are accounted for as a reduction in capitalized costs, with no gain or loss generally recognized unless such dispositions involve a significant alteration in the depletion rate. We capitalize internal costs that can be directly identified with exploration and development activities, but do not include any costs related to production, general corporate overhead or similar activities. Capitalized costs include geological and geophysical work, 3D seismic, delay rentals, and drilling completing and equipping oil and natural gas wells, including salaries, benefits, and other internal costs directly attributable to these activities.

Costs associated with unevaluated oil and natural gas properties are excluded from the amortizable base until a determination has been made as to the existence of proved reserves. Unevaluated leasehold costs are transferred to the amortization base with the costs of drilling the related well upon proving up reserves of a successful well or upon determination of a dry or uneconomic well under a process that is conducted each quarter. Furthermore, unevaluated oil and natural gas properties are reviewed for impairment if events and circumstances exist that indicate a possible decline in the recoverability of the carrying amount of such property. The impairment assessment is conducted at least once annually and whenever there are indicators that impairment has occurred. In assessing whether impairment has occurred, we consider factors such as intent to drill; remaining lease term; geological and geophysical evaluations;

12

Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited)
(dollars in thousands, except per share amounts)


drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. Upon determination of impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. The processes above are applied to unevaluated oil and natural gas properties on an individual basis or as a group if properties are individually insignificant. Our future depreciation, depletion and amortization rate would increase or we may incur ceiling test write-downs if costs are transferred to the amortization base without any associated reserves.

In the past, the costs associated with unevaluated properties typically related to acquisition costs of unproved acreage. As a result of the application of fresh start accounting on the Effective Date, a substantial portion of the carrying value of our unevaluated properties are the result of a fair value increase to reflect the value of our acreage in our STACK play.

The costs of unevaluated oil and natural gas properties consisted of the following:
 
 
September 30,
2019
 
December 31,
2018
Leasehold acreage
 
$
338,892

 
$
427,206

Capitalized interest
 
15,469

 
11,377

Wells and facilities in progress of completion
 
19,400

 
28,033

Total unevaluated oil and natural gas properties excluded from amortization
 
$
373,761

 
$
466,616

 
Ceiling Test. In accordance with the full cost method of accounting, the net capitalized costs of oil and natural gas properties are not to exceed their related PV-10 value, net of tax considerations, plus the cost of unproved properties not being amortized.

Our estimates of oil and natural gas reserves as of September 30, 2019, and the related PV-10 value, were prepared using an average price for oil and natural gas on the first day of each month for the prior twelve months as required by the SEC. We recorded ceiling test write-downs to our oil and natural gas properties of $147,686 and $261,001 for the three and nine months ended September 30, 2019, respectively. These losses are reflected in “Impairment of oil and gas assets” in our consolidated statements of operations.

Producer imbalances. We recognize revenue on all natural gas sold to our customers regardless of our proportionate working interest in a well. Liabilities are recorded for imbalances greater than our proportionate share of remaining estimated natural gas reserves. Our aggregate imbalance positions at September 30, 2019, and December 31, 2018, were immaterial.

Revenue recognition

In May 2014, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance that supersedes previous revenue recognition requirements which has been codified as Accounting Standards Codification 606: Revenue from Contracts with Customers (“ASC 606”) and adopted by us in 2018. ASC 606 requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.

The following table displays the revenue disaggregated and reconciles the disaggregated revenue to the revenue reported:
 
 
Three months ended September 30,
 
Nine months ended September 30,
 
 
2019
 
2018
 
2019
 
2018
Revenues:
 
 

 
 
 
 
 
 
Oil
 
$
40,459

 
$
46,576

 
$
124,251

 
$
132,378

Natural gas
 
8,745

 
9,458

 
30,427

 
26,584

Natural gas liquids
 
8,801

 
14,078

 
29,043

 
34,789

Gross commodity sales
 
58,005

 
70,112

 
183,721

 
193,751

Transportation and processing
 
(6,167
)
 
(4,593
)
 
(16,557
)
 
(11,916
)
Net commodity sales
 
$
51,838

 
$
65,519

 
$
167,164

 
$
181,835

 

Please see “Note 16: Revenue recognition” in “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2018, for a discussion of our revenue recognition policy including a description of products and revenue disaggregation criteria, performance obligations, pricing , measurement and contract assets and liabilities.

13

Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited)
(dollars in thousands, except per share amounts)



Income taxes

The provision for income taxes is based on a current estimate of the annual effective income tax rate adjusted to reflect the impact of permanent differences and discrete items. Management judgment is required in estimating operating income in order to determine our effective income tax rate. Our effective income tax rate was 0% and 0% for the three and nine months ended September 30, 2019 and 2018, respectively. The consistent effective tax rate for the nine months ended September 30, 2019, is a result of maintaining a valuation allowance against substantially all of our net deferred tax asset.

Despite the Company’s net loss for the three and nine month period ended September 30, 2019, we did not record any net deferred tax benefit, as any deferred tax asset arising from the benefit is reduced by a valuation allowance as utilization of the loss carryforwards and realization of other deferred tax assets cannot be reasonably assured.

A valuation allowance for deferred tax assets, including net operating losses (“NOLs”), is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry.

We will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until we can determine that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead us to conclude that it is more likely than not that some or all of our net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in oil prices, and taxable events that could result from one or more transactions. The valuation allowance does not prevent future utilization of the tax attributes if we recognize taxable income. As long as we conclude that the valuation allowance against our net deferred tax asset is necessary, we likely will not have any additional deferred income tax expense or benefit.

The benefit of an uncertain tax position taken or expected to be taken on an income tax return is recognized in the consolidated financial statements at the largest amount that is more likely than not to be sustained upon examination by the relevant taxing authority. Interest and penalties, if any, related to uncertain tax positions would be recorded in interest expense and other expense, respectively. There were no uncertain tax positions at September 30, 2019, or December 31, 2018.

As a result of the Chapter 11 reorganization and related transactions, the Company experienced an ownership change within the meaning of Internal Revenue Code (“IRC”) Section 382 on March 21, 2017. This ownership change subjected certain of the Company’s tax attributes, including $760,067 of federal net operating loss carryforwards, to an IRC Section 382 limitation. This limitation has not resulted in a current tax liability for the nine month period ended September 30, 2019, or any intervening period since March 21, 2017. If we were to experience an additional “ownership change,” as determined under IRC Section 382, our ability to offset taxable income arising after the ownership change with NOLs generated prior to the ownership change would be limited, possibly substantially. In general, an ownership change will occur if there is a cumulative increase in our ownership of more than 50 percentage points by one or more “5% stockholders” at any time during a rolling three-year period. In the event of an ownership change, IRC Section 382 imposes an annual limitation on the amount of the Company’s taxable income that can be offset by these carryforwards after an ownership change. The limitation is generally equal to the product of (a) the fair market value of the equity of the Company multiplied by (b) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are net unrealized built-in gains in the Company’s assets at the time of the ownership change, and those net unrealized built-in gains are recognized during the 60 month recognition period following the ownership change. Future ownership changes or future regulatory changes could limit our ability to utilize our NOLs. To the extent we are not able to offset our future income with our NOLs, this could adversely affect our operating results and cash flows once we attain profitability.

Cost reduction initiatives

We incur expenses related to our efforts to reduce our capital, operating and administrative costs in response to industry conditions. The expenses consist of costs for one-time severance and termination benefits in connection with our reductions in force.

14

Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited)
(dollars in thousands, except per share amounts)


Other expense

Other expense consisted of the following:


Three months ended September 30,

Nine months ended September 30,
 

2019

2018

2019

2018
Restructuring

$


$


$


$
425

Subleases

269


402


1,075


1,208

Total other expense

$
269


$
402


$
1,075


$
1,633


Restructuring. We previously incurred exit costs in conjunction with our EOR asset divestiture, which predominantly consist of one-time severance and termination benefits for the affected employees. The expense recorded in 2018 is a result of termination benefits for the final group of employees terminated as a result of the divestiture.  

Subleases. Our subleases consist of CO2 compressors that were utilized in our former EOR operations and leased as both financing and operating leases from U.S. Bank but subsequently subleased to the purchaser of our EOR assets. Minimum payments under the subleases were equal to the original leases. All payments received from the Sublessee were reflected as “Sublease revenue” on our statement of operations. Minimum payments made to U.S. Bank on the original operating leases were reflected as “Other” expense on our statement of operations. With respect to the financing leases, upon executing the subleases, we reclassified the amount associated with these leases from the full cost amortization base to “Property and equipment, net” on our balance sheet and amortized the asset on a straight line basis prospectively while continuing to incur interest expense. Please see “Note 5: Leases” for our disclosure on leases. In September 2019, U.S. Bank entered into agreements with the Sublessee which resulted in the discharge of all our obligations with respect to the originating leases and to the subleases including a $9,832 reduction in debt.

Joint development agreement

On September 25, 2017, we entered into a joint development agreement (“JDA”) with BCE Roadrunner LLC, a wholly-owned subsidiary of Bayou City Energy Management, LLC (“BCE”), pursuant to which BCE funded 100 percent of our drilling, completion and equipping costs associated with 30 joint venture STACK wells, subject to average well cost caps that vary by well-type across location and targeted formations, approximately between $3,400 and $4,000 per gross well. The JDA wells, which were drilled and operated by us, include 17 wells in Canadian County and 13 wells in Garfield County. The JDA provided us with a means to accelerate the delineation of our position within our Garfield and Canadian County acreage, realizing further efficiencies and holding additional acreage by production, and adding reserves. In exchange for funding, BCE received wellbore-only interest in each well totaling an 85% carve-out working interest from our original working interest (and we retained 15%) until the program reaches a 14% internal rate of return. Once achieved, a portion of BCEs ownership interest in all JDA wells will revert to us such that we will own a 75% working interest and BCE will retain a 25% working interest. We retained all acreage and reserves outside of the wellbore, with both parties entitled to revenues and paying lease operating expenses based on their working interest.

Our drilling and completion costs to date have exceeded the well cost caps specified under the JDA primarily due to inflation in the cost of oilfield services subsequent to our negotiations in mid-2017 that culminated in our entering into the JDA. In our negotiation with BCE to cover the inflationary cost increases, BCE had indicated willingness to increase the per well cost caps on remaining wells in exchange for adding more wells to the current program. Since we have achieved our goals to utilize the JDA as a means to delineate our acreage in Garfield and Canadian counties, Oklahoma, we do not currently plan for any expansion of the JDA. For the nine months ended September 30, 2019, we have therefore recorded additions to oil and natural gas properties of $3,986 in drilling and completion costs on JDA wells that have exceeded the well cost caps specified under the JDA. We have drilled and completed all wells under the JDA.
 
Reorganization items

Reorganization items reflect, where applicable, expenses, gains and losses incurred that are incremental and a direct result of the reorganization of the business. As a result of our emergence from bankruptcy in March 2017, we have also recorded gains on the settlement of liabilities subject to compromise and gains from restating our balance sheet to fair values under fresh start accounting. “Professional fees” in the table below for periods subsequent to the emergence from bankruptcy consist of legal fees for continuing work to resolve outstanding bankruptcy claims and fees to the U.S. Bankruptcy Trustee, which we will continue to incur until our bankruptcy case is closed. Reorganization items are as follows:

15

Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited)
(dollars in thousands, except per share amounts)


 
 
Three months ended September 30,
 
Nine months ended September 30,
 
 
2019
 
2018
 
2019
 
2018
Loss on the settlement of liabilities subject to compromise
 
$

 
$

 
$

 
$
48

Professional fees
 
530

 
493

 
1,306

 
1,962

Total reorganization items
 
$
530

 
$
493

 
$
1,306

 
$
2,010

 
Recently adopted accounting pronouncements

In February 2016, the FASB issued authoritative guidance that supersedes previous lease recognition requirements and requires entities to recognize leases on-balance sheet and disclose key information about leasing arrangements. Please see “Note 5: Leases” for our disclosure regarding adoption of this update.

Recently issued accounting pronouncements

In June 2016, the FASB issued authoritative guidance which modifies the measurement of expected credit losses of certain financial instruments. The guidance is effective for fiscal years beginning after December 15, 2020, however early adoption is permitted for fiscal years beginning after December 15, 2018. The updated guidance impacts our financial statements primarily due to its effect on our accounts receivables. Our history of accounts receivable credit losses almost entirely relates to receivables from joint interest owners in our operated oil and natural gas wells. Based on this history and on mitigating actions, we are permitted to take to offset potential losses such as netting past due amounts against revenue and assuming title to the working interest. We do not expect this guidance to materially impact our financial statements or results of operations.

Note 2: Earnings per share

Although we previously had both Class A and Class B common stock outstanding, where both classes of common stock shared equally in voting power, dividends and undistributed earnings, on December 19, 2018, all outstanding shares of our Class B common stock automatically converted into the same number of shares of Class A common stock.

A reconciliation of the components of basic and diluted EPS is presented below:
 
 
Three months ended September 30,
 
Nine months ended September 30,
(in thousands, except share and per share data)
 
2019
 
2018
 
2019
 
2018
Numerator for basic and diluted earnings per share
 
 

 
 

 
 
 
 
Net loss
 
$
(130,935
)
 
$
(12,068
)
 
$
(279,704
)
 
$
(45,503
)
Denominator for basic earnings per share
 
 

 
 

 
 
 
 
Weighted average common shares - Basic for Class A and Class B (1)
 
45,716,522

 
45,333,745

 
45,605,798

 
45,272,595

Denominator for diluted earnings per share
 
 

 
 

 
 
 
 
Weighted average common shares - Diluted for Class A and Class B (1)
 
45,716,522

 
45,333,745

 
45,605,798

 
45,272,595

Earnings per share
 
 

 
 

 
 
 
 
Basic for Class A and Class B (1)
 
$
(2.86
)
 
$
(0.27
)
 
$
(6.13
)
 
$
(1.01
)
Diluted for Class A and Class B (1)
 
$
(2.86
)
 
$
(0.27
)
 
$
(6.13
)
 
$
(1.01
)
Participating securities excluded from earnings per share calculations
 
 

 
 

 
 
 
 
Unvested restricted stock units - stock settled
 
838,552

 

 
838,552

 

Unvested restricted stock awards
 
680,152

 
1,126,669

 
680,152

 
1,126,669

________________________________
(1)
Effective December 19, 2018, all our outstanding Class B shares were converted to Class A shares and subsequently, all our outstanding common stock consisted only of Class A common stock. Earnings per share for the three and nine months ended September 30, 2018 reflects earnings per share for Class A and Class B common stock in aggregate whereas earnings per share for the three and nine months ended September 30, 2019 reflects earnings per share for Class A common stock.


16

Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited)
(dollars in thousands, except per share amounts)


Note 3: Supplemental disclosures to the consolidated statements of cash flows
 
 
Nine months ended September 30,
 
 
2019
 
2018
Net cash provided by operating activities included:
 
 
 
 

Cash payments for interest
 
$
30,896

 
$
5,755

Interest capitalized
 
(9,431
)
 
(7,155
)
Cash payments for reorganization items
 
1,244

 
2,161

Non-cash investing activities included:
 
 
 
 

Asset retirement obligation additions and revisions
 
629

 
1,234

Leasing right of use asset additions (see Note 5: Leases)
 
1,643

 

Change in accrued oil and gas capital expenditures
 
17,272

 
7,222

Non-cash financing activities included:
 
 
 
 
Discharge of financing lease obligations (See Note 5: Leases)
 
9,832

 

Note 4: Debt
As of the dates indicated, long-term debt and financing leases consisted of the following:
 
 
September 30,
2019
 
December 31,
2018
8.75% Senior Notes due 2023
 
$
300,000

 
$
300,000

Credit facility
 
110,000

 

Real estate mortgage note
 

 
8,588

Installment note payable
 
433

 
354

Financing lease obligations
 
1,487

 
11,677

Unamortized debt issuance costs
 
(10,816
)
 
(13,148
)
Total debt, net
 
401,104

 
307,471

Less current portion
 
586

 
12,371

Total long-term debt, net
 
$
400,518

 
$
295,100

 
As discussed in “Note 1: Nature of operations and summary of significant accounting policies,” upon the divestiture of our headquarters building in August 2019, we utilized the sale proceeds to pay off the outstanding balance of our real estate mortgage note which was $8,176 at the time of the repayment.

Our financing lease obligations as of December 31, 2018, included leases on CO2 compressors that were subleased to the buyer of our former EOR oil and natural gas properties. In September 2019, U.S. Bank entered into agreements with the Sublessee which resulted in the discharge of all our obligations with respect to these compressor leases and the removal of the associated debt from our consolidated balance sheet in the amount of $9,832. Our remaining finance leases consist entirely of leases on our fleet vehicles.

Credit Agreement

Pursuant to our Credit Agreement (the “Credit Agreement”) with Royal Bank of Canada, as administrative agent and issuing bank, and the additional lenders party thereto, we have a $750,000 credit facility collateralized by our oil and natural gas properties and is scheduled to mature on December 21, 2022. Availability under our credit facility is subject to the financial covenants discussed below and a borrowing base based on the value of our oil and natural gas properties and set by the banks semi-annually on or around May 1 and November 1 of each year. Our borrowing base under the credit facility as of September 30, 2019, was $325,000.

As of September 30, 2019, our outstanding borrowings were accruing interest at the Adjusted LIBO Rate (as defined in the Credit Agreement, as defined below), plus the Applicable Margin (as defined in the Credit Agreement), which resulted in a weighted average interest rate of 4.34%.


17

Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited)
(dollars in thousands, except per share amounts)


The Credit Agreement contains financial covenants that require, for each fiscal quarter, we maintain: (1) a Current Ratio (as defined in the Credit Agreement) of no less than 1.00 to 1.00, and (2) a Ratio of Total Debt to EBITDAX (as defined in the Credit Agreement) of no greater than 4.0 to 1.0 calculated on a trailing four-quarter basis. We were in compliance with these financial covenants as of September 30, 2019.

The Credit Agreement contains covenants and events of default customary for oil and natural gas reserve-based lending facilities. Please see “Note 8: Debt” in “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2018, for a discussion of the material provisions of our Credit Agreement.

On May 2, 2019, we entered into the Third Amendment to the Tenth Restated Credit Agreement (the “Credit Agreement”), among the Company and its subsidiaries, as borrowers, certain financial institutions party thereto, as lenders, and Royal Bank of Canada, as administrative agent (the “Third Amendment”). The Third Amendment, which was effective March 31, 2019, reaffirmed our borrowing base at the same level as it was at the beginning of 2019, at $325,000.

On September 27, 2019, we entered into the Fourth Amendment (the “Amendment”) to the Credit Agreement. The Amendment, among other things, (i) reaffirmed the borrowing base at $325,000; (ii) amended the definition of EBITDAX to, among other things, (a) added back losses related to or resulting from the full or partial extinguishment of debt, (b) expanded the add-back of amounts associated with retirements, severance or departure to apply to all employees or former employees, and (c) clarified that gains related to or resulting from the full or partial extinguishment of debt are excluded; and (iii) revised certain negative covenants to provide that the Company, under certain circumstances, may prepay or otherwise redeem certain Permitted Senior Additional Debt (as defined in the Credit Agreement) in an aggregate amount not to exceed $30,000.

Senior Notes

On June 29, 2018, we completed the issuance and sale at par of $300,000 in aggregate principal amount of our Senior Notes in a private placement under Rule 144A and Regulation S under the Securities Act of 1933, as amended. The Senior Notes bear interest at a rate of 8.75% per year beginning June 29, 2018 (payable semi-annually in arrears on January 15 and July 15 of each year, beginning on January 15, 2019) and will mature on July 15, 2023.

The Senior Notes are the Company’s senior unsecured obligations and rank equal in right of payment with all of the Company’s existing and future senior indebtedness, senior to all of the Company’s existing and future subordinated indebtedness and effectively subordinated to all of the Company’s existing and future secured indebtedness, to the extent of the value of the collateral securing such indebtedness.

The Senior Notes contain customary covenants, certain callable provisions and events of default. Please see “Note 8: Debt” in “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2018, for a discussion of the material provisions of our Senior Notes.

Note 5: Leases

In February 2016, the FASB established Accounting Standards Codification (“ASC”) Topic 842, Leases (“ASC 842”) which requires lessees to recognize leases on-balance sheet and disclose key information about leasing arrangements. ASC 842 was subsequently amended by Accounting Standards Update (“ASU”) No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842; ASU No. 2018-10, Codification Improvements to Topic 842, Leases, ASU No. 2018-11, Targeted Improvements and ASU No 2019-01, Codification Improvements. The new standard establishes a right-of-use (“ROU”) model that requires a lessee to recognize a ROU asset and lease liability on the balance sheet for all leases except those with a term of 12 months or less. Leases will be classified as finance or operating, with classification affecting the pattern and classification of expense recognition in the income statement. We adopted the new standard on its effective date of January 1, 2019, which is also our date of initial application. Consequently, we have not updated financial information nor provided disclosures required under the new standard for dates and periods before January 1, 2019. Our disclosures for dates and periods before January 1, 2019, are provided in accordance with the requirements of ASC Topic 840, Leases (“ASC 840”).

We have elected the package of transition practical expedients, which permits us not to reassess under the new standard our prior conclusions about lease identification, lease classification and initial direct costs. Additionally, we have elected not to apply the recognition requirements of ASC Topic 842 to leases with durations of 12 months or less. Upon adoption of ASC 842, we carried over

18

Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited)
(dollars in thousands, except per share amounts)


our existing capital lease obligations (now “financing leases” under ASC 842) and capital lease asset (now “right of use asset” under ASC 842) at their previous carrying value.

Financing leases

We previously had lease financing agreements which were entered into during 2013 with U.S. Bank for $24,500 through the sale and subsequent leaseback of existing CO2 compressors owned by us. The lease financing obligations were for terms of 84 months and included the option to purchase the equipment for a specified price at 72 months as well as an option to purchase the equipment at the end of the lease term for its then-current fair market value. There were no residual value guarantees and nonlease components under these leases. At the inception of the lease, our measurement of the lease liability assumed that the mid-term purchase option would be exercised. Since the lease contract had not been modified and there were no triggering events subsequent to our adoption of ASC 842, we did not perform any reassessment of the lease prior to its termination discussed below. Lease payments related to the equipment were recognized as principal and interest expense based on a weighted average implicit interest rate of 3.8%. Minimum lease payments were approximately $3,181 annually. In conjunction with the sale of our EOR assets in November 2017, these compressors were subleased to the buyer of those assets while we remained the primary obligor in relation to U.S. Bank. In September 2019, U.S. Bank entered into agreements with the sublessee which resulted in the discharge of the remaining obligations with respect to these compressor leases in the amount of $9,832.

During 2019, we entered into lease financing agreements for our fleet trucks for $1,643. The lease financing obligations are for 48-month terms with the option for us to purchase the vehicle at any time during the lease term by paying the lessors remaining unamortized cost in the vehicle. At the end of the lease term, the lessors remaining unamortized cost in the vehicle will be a de minimis amount and hence ownership of the vehicle can be transferred to us at minimal cost. There are no residual value guarantees or nonlease components under these leases.

Operating leases

We previously also had operating leases for CO2 compressors deployed in our former EOR operations. The operating lease obligations, which we entered into in 2014 and 2016, were for terms of 84 months without any specified purchase options. There were no residual value guarantees or nonlease components under these leases. In conjunction with the sale of our EOR assets in November 2017, these compressors were subleased to the buyer of those assets although we remained the primary obligor in relation to U.S. Bank. Similar to the financing leases discussed above, all our obligations under these compressor leases were discharged by U.S. Bank in September 2019.

During the fourth quarter of 2018, we entered into 15-month leasing arrangements for two drilling rigs. These agreements specify a minimum daily rate on the rigs that we utilize to measure the lease liability upon adoption of ASC 842. The actual daily rate may vary from the minimum rate depending on whether the rig is being mobilized, demobilized, engaged in drilling or on standby. The daily rate includes a non-lease labor component that we have elected not to separate from the lease component for this asset class.

On August 30, 2019, in conjunction with the sale of the building housing our headquarters, we entered into a leaseback agreement with the buyer for a portion of the office space in the building for a period of two years with a renewal option that includes one-year extensions for up to two years. The office space lease includes typical non-lease components such as utilities, maintenance and janitorial services for that we have elected not to separate from the lease component.

Short term leases

Our short term leases are those with lease terms of 12 months or less and generally consist of wellhead compressors, generators and drilling rigs with terms ranging from one month to six months. As discussed above, we have elected not to recognize right of use assets or lease liabilities for leases with durations of 12 months or less.

Subleases

As discussed above, we previously had subleases consisting of CO2 compressors that were utilized in our former EOR operations and leased as both financing and operating leases from U.S. Bank but subsequently subleased to the purchaser of our EOR assets (the “Sublessee”). Minimum payments under the subleases were equal to the original leases and as such we did not record any losses upon initiation of the subleases. All the subleases were classified as operating leases from a lessor’s standpoint. All payments received from the Sublessee were reflected as “Sublease revenue” on our statement of operations. Minimum payments made to U.S. Bank on the original operating leases were reflected as “Other” expense on our statement of operations. With respect to the financing leases, upon

19

Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited)
(dollars in thousands, except per share amounts)


executing the subleases, we reclassified the amount associated with these leases from the full cost amortization base to “Property and equipment, net” on our balance sheet, amortized the asset on a straight line basis prospectively while continuing to incur interest expense. In September 2019, U.S. Bank entered into agreements with the sublessee which resulted in the discharge of all our obligations with respect to the originating leases and to the subleases.

Lease assets and liabilities

Our operating lease and financing lease assets and liabilities are recorded on our balance sheet as of September 30, 2019 as follows:
 
 
As of September 30, 2019
 
 
Operating leases
 
Financing leases
Right of use asset:
 
 

 
 

Right of use assets from operating leases (1)
 
$
5,853

 
$

Plant, property and equipment, net (2)
 

 
1,478

Total lease assets
 
$
5,853

 
$
1,478

Lease liability:
 
 
 
 
Account payable and accrued liabilities
 
$
4,301

 
$

Long-term debt and financing leases, classified as current
 

 
381

Long-term debt and financing leases, less current maturities
 

 
1,106

Noncurrent operating lease obligations
 
1,239

 

Total lease liabilities
 
$
5,540

 
$
1,487

________________________________
(1) Consisted of leases on office space and drilling rigs.
(2) Consisted of leased fleet vehicles.

20

Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited)
(dollars in thousands, except per share amounts)



Our income, expenses and cash flows related to our leases is as follows for the three and nine months ended September 30, 2019:
 
 
Three months ended
 
Nine months ended
 
 
September 30, 2019
 
September 30, 2019
Lease cost
 

 
 
Finance lease cost:
 

 
 
Amortization of right-of-use assets
 
$
544

 
$
1,986

Interest on lease liabilities
 
87

 
317

Operating lease cost
 
205

 
821

Short-term lease cost
 
180

 
463

Variable lease cost
 
63

 
253

Sublease income
 
(799
)
 
(3,195
)
Total lease cost
 
$
280

 
$
645

 
 
 
 
 
Capitalized operating lease cost (1)
 
$
3,409

 
$
10,115

 
 
 
 
 
Other information
 

 
 
Cash paid for amounts included in the measurement of lease liabilities
 
 
 
 
Operating cash flows for finance leases
 
$
(87
)
 
$
(317
)
Operating cash flows for operating leases
 
(205
)
 
(821
)
Investing cash flows for operating leases
 
(3,510
)
 
(7,498
)
Financing cash flows for finance leases
 
(557
)
 
(2,002
)
Right-of-use assets obtained in exchange for new finance lease liabilities
 
256

 
1,643

________________________________
(1)
The operating lease cost are related to drilling rigs and are capitalized as part of oil and natural gas properties on our balance sheets.

 
 
As of
 
 
September 30, 2019
Weighted-average remaining lease term - finance leases
 
3.6 years

Weighted-average remaining lease term - operating leases
 
1.0 year

Weighted-average discount rate - finance leases
 
6.29
%
Weighted-average discount rate - operating leases
 
10.97
%

Our rent expense for the three months and nine months ended September 30, 2018, was $918 and $2,984, respectively.

Discount rate

Whenever possible, we utilize the implied rate in our lease agreements to measure our lease liabilities. In the absence of a readily available implied rate, we utilize our incremental borrowing rate. The incremental borrowing rate is the rate of interest that a lessee would have to pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. The lease liabilities we recorded on our balance sheet on the effective date of ASC 842 were measured utilizing an incremental borrowing rate derived from the yield on our unsecured Senior Notes and adjusted to a collateralized basis utilizing a recovery rate model that uses observed recovery rates on defaulted debt instruments.


21

Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited)
(dollars in thousands, except per share amounts)


Lease maturities

Our lease payments for each of the next five years and thereafter are as follows:
 
 
As of September 30, 2019
 
As of December 31, 2018 (1)
 
 
Operating leases
Financing leases
 
Operating leases
Financing leases
2019
 
$
3,475

$
116

 
$
13,890

$
12,332

2020
 
1,389

464

 
1,330


2021
 
941

464

 
1,297


2022
 

464

 
278


2023
 

160

 
205


Thereafter
 


 


Total minimum lease payments
 
5,805

1,668

 
17,000

12,332

Less: imputed interest
 
265

181

 
*
*
Total lease liability
 
5,540

1,487

 
*
*
Less: current maturities of lease obligations
 
4,301

381

 
*
*
Noncurrent lease obligations
 
$
1,239

$
1,106

 
*
*
________________________________
(1)
Represents undiscounted firm commitments as of December 31, 2018
* Disclosure not required under ASC 840.

Method of adoption

We adopted ASC 842 effective January 1, 2019, using the modified retrospective approach. Based on an assessment of our leasing contracts, we did not record a cumulative effect adjustment to the opening balance of accumulated deficit.

Reconciliation of Balance Sheet Statement

In accordance with ASC 842, the disclosure of the impact of adoption on our balance statement is as follows:
 
 
As of January 1, 2019
 
 
Balances upon adoption
 
Balances without adoption of ASC 842
 
Effect of change
Assets
 
 
 
 
 
 
Right of use asset from operating leases, net
 
$
14,999

 
$

 
$
14,999

Liabilities
 
 
 
 
 
 
Accounts payable and accrued liabilities
 
12,467

 

 
12,467

Noncurrent operating lease obligation
 
2,532

 

 
2,532


Note 6: Derivative instruments

Overview

Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil, natural gas and natural gas liquids. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, we enter into various types of derivative instruments, including commodity price swaps, collars, and basis protection swaps.


22

Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited)
(dollars in thousands, except per share amounts)


The following table summarizes our crude oil derivatives outstanding as of September 30, 2019:
 
 
 
 
Weighted average fixed price per Bbl
Period and type of contract
 
Volume
MBbls
 
Swaps
 
Purchased Puts
 
Sold Calls
2019
 
 

 
 

 
 
 
 
Oil swaps
 
688

 
$
55.90

 
$

 
$

Oil roll swaps
 
120

 
$
0.46

 
$

 
$

2020
 
 
 
 
 
 
 
 
Oil swaps
 
2,274

 
$
51.01

 
$

 
$

Oil roll swaps
 
410

 
$
0.38

 
$

 
$

Oil collars
 
195

 
$

 
$
55.00

 
$
66.42

2021
 
 
 
 
 
 
 
 
Oil swaps
 
689

 
$
46.24

 
$

 
$

Oil roll swaps
 
150

 
$
0.30

 
$

 
$

The following table summarizes our natural gas derivatives outstanding as of September 30, 2019:
Period and type of contract
 
Volume
BBtu
 
Weighted average fixed price per MMBtu
2019
 
 

 
 

Natural gas swaps
 
3,977

 
$
2.85

Natural gas basis swaps
 
3,977

 
$
(0.51
)
2020
 
 
 
 
Natural gas swaps
 
7,680

 
$
2.70

Natural gas basis swaps
 
7,080

 
$
(0.46
)
The following table summarizes our natural gas liquid derivatives outstanding as of September 30, 2019:
Period and type of contract
 
Volume
Thousands of Gallons
 
Weighted average fixed price per gallon
2019
 
 

 
 

Natural gasoline swaps
 
4,200

 
$
1.13

Propane swaps
 
9,156

 
$
0.61

Butane swaps
 
2,394

 
$
0.71

2020
 
 
 
 
Natural gasoline swaps
 
6,508

 
$
1.15

Propane swaps
 
14,872

 
$
0.57

Butane swaps
 
2,849

 
$
0.68



23

Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited)
(dollars in thousands, except per share amounts)


Effect of derivative instruments on the consolidated balance sheets

All derivative financial instruments are recorded on the balance sheet at fair value. See “Note 7: Fair value measurements” for additional information regarding fair value measurements. The estimated fair values of derivative instruments are provided below. The carrying amounts of these instruments are equal to the estimated fair values.
 
 
As of September 30, 2019
 
As of December 31, 2018
 
 
Assets
 
Liabilities
 
Net value
 
Assets
 
Liabilities
 
Net value
Natural gas derivative contracts
 
$
5,055

 
$
(40
)
 
$
5,015

 
$
833

 
$
(488
)
 
$
345

Crude oil derivative contracts
 
5,174

 
(6,164
)
 
(990
)
 
24,208

 
(4,452
)
 
19,756

NGL derivative contracts
 
5,871

 
(431
)
 
5,440

 
4,581

 

 
4,581

Total derivative instruments
 
16,100

 
(6,635
)
 
9,465

 
29,622

 
(4,940
)
 
24,682

Less:
 
 
 
 
 
 
 
 
 
 
 
 
Netting adjustments (1)
 
(3,543
)
 
3,543