UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

☒  Quarterly report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934

 

For the quarterly period ended March 31,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: 000-02040

 

CARBON ENERGY CORPORATION
(Exact name of registrant as specified in its charter)

 

Delaware 26-0818050
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
   
1700 Broadway, Suite 1170, Denver, CO 80290
(Address of principal executive offices) (Zip Code)

 

Registrant’s telephone number, including area code:(720) 407-7030

 

 
(Former name, address and fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act:

Title of each classTrading symbol(s)Name of each exchange on which registered
None

 

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 Company 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 every Interactive Data File required to be submitted pursuant to rule 405 of Regulations 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, a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

 Large accelerated filerSmaller reporting company
 Accelerated filerEmerging growth company
 Non-accelerated filer  

 

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 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 ☒

 

Securities registered pursuant to Section 12(b) of the Act:

Title of each classTrading symbol(s)Name of each exchange on which registered
None

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

At May 13,November 8, 2019, there were 7,816,0307,856,864 issued and outstanding shares of the Company’s common stock, $0.01 par value.

 

 

 

 

   

Carbon Energy Corporation

 

TABLE OF CONTENTS

 

Part I – FINANCIAL INFORMATION
  
Item 1. Consolidated Financial Statements1
  
Condensed Consolidated Balance Sheets (unaudited)1
  
Condensed Consolidated Statements of Operations (unaudited)2
  
Condensed Consolidated Statements of Stockholders’ Equity (unaudited)3
  
Condensed Consolidated Statements of Cash Flows (unaudited)4
  
Notes to theCondensed Consolidated Financial Statements (unaudited)5
  
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations3122
  
Item 3. Quantitative and Qualitative Disclosures About Market Risk4533
  
Item 4. Controls and Procedures4533
  
Part II – OTHER INFORMATION
  
Item 1. Legal Proceedings4634
  
Item 1A. Risk Factors4634
  
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds6. Exhibits4634
  
Item 6. ExhibitsSignatures4635

  

i

 

PART I. FINANCIAL INFORMATION

 

ITEM 1.Financial Statements

 

CARBON ENERGY CORPORATION

Condensed Consolidated Balance Sheets

 

  March 31,  December 31, 
(in thousands) 2019  2018 
  (Unaudited)    
ASSETS      
Current assets:      
Cash and cash equivalents $11,016  $5,736 
Accounts receivable:        
Revenue  14,714   19,671 
Joint interest billings and other  1,158   1,770 
Insurance receivable (Note 2)  -   522 
Commodity derivative asset (Note 13)  -   3,517 
Prepaid expense, deposits and other current assets  1,519   1,894 
Inventory  625   900 
Total current assets  29,032   34,010 
         
Property and equipment (Note 5)        
Oil and gas properties, full cost method of accounting:        
Proved, net  245,321   248,455 
Unproved  5,385   5,416 
Other property and equipment, net  17,168   17,563 
 Total property and equipment, net  267,874   271,434 
         
Investments in affiliates (Note 6)  617   598 
Commodity derivative asset – non-current (Note 13)  147   3,505 
Right-of-use assets (Note 14)  7,256   - 
Other non-current assets  1,138   1,344 
   277,032   276,881 
Total assets $306,064  $310,891 
         
LIABILITIES AND STOCKHOLDERS’ EQUITY        
Current liabilities:        
Accounts payable and accrued liabilities (Note 11) $30,020  $34,816 
Firm transportation contract obligations (Note 15)  6,012   6,129 
Lease liability – current (Note 14)  1,616   - 
Commodity derivative liability (Note 13)  1,657   - 
Credit facilities and notes payable – current (Note 7)  

9,910

   11,910 
Total current liabilities  49,215   52,855 
         
Non-current liabilities:        
Firm transportation contract obligations (Note 15)  11,749   12,729 
Lease liability – non-current (Note 14)  5,645   - 
Commodity derivative liability – non-current (Note 13)  318   - 
Production and property taxes payable  3,103   2,914 
Asset retirement obligations (Note 3)  19,312   19,211 
Credit facilities and notes payable (Note 7)  97,168   97,228 
Notes payable – related party (Note 7)  49,964   49,919 
Total non-current liabilities  

187,259

   182,001 
         
Commitments and contingencies (Note 15)        
         
Stockholders’ equity:        
Preferred stock, $0.01 par value; liquidation preference of $299,000 at March 31, 2019 and $224,000 at December 31, 2018; authorized 1,000,000 shares, 50,000 shares issued and outstanding at March 31, 2019 and December 31, 2018  1   1 
Common stock, $0.01 par value; authorized 35,000,000 shares, 7,791,292 and 7,655,759 shares issued and outstanding at March 31, 2019 and December 31, 2018, respectively  79   77 
Additional paid-in capital  84,833   84,612 
Accumulated deficit  (41,039)  (36,939)
Total Carbon stockholders’ equity  43,874   47,751 
Non-controlling interests  25,716   28,284 
Total stockholders’ equity  69,590   76,035 
Total liabilities and stockholders’ equity $306,064  $310,891 

  September 30,  December 31, 
(in thousands, except share amounts) 2019  2018 
ASSETS (Unaudited)    
Current assets:      
Cash and cash equivalents $3,514  $5,736 
Accounts receivable:        
Revenue  11,632   19,671 
Joint interest billings and other  1,361   1,770 
Insurance receivable (Note 2)  -   522 
Commodity derivative asset (Note 14)  6,722   3,517 
Prepaid expense, deposits and other current assets  2,537   1,645 
Inventory  2,522   1,149 
Total current assets  28,288   34,010 
         
Non-current assets:        
Property and equipment (Note 4)        
Oil and gas properties, full cost method of accounting:        
Proved, net  243,593   248,455 
Unproved  5,004   5,416 
Other property and equipment, net  16,253   17,563 
 Total property and equipment, net  264,850   271,434 
         
Investments in affiliates  605   598 
Commodity derivative asset – non-current (Note 14)  3,072   3,505 
Right-of-use assets (Note 8)  6,523   - 
Other non-current assets  1,166   1,344 
Total non-current assets  276,216   276,881 
Total assets $304,504  $310,891 
         
LIABILITIES AND STOCKHOLDERS’ EQUITY        
Current liabilities:        
Accounts payable and accrued liabilities (Note 5) $30,786  $34,816 
Firm transportation contract obligations (Note 15)  5,824   6,129 
Lease liability – current (Note 8)  1,620   - 
Credit facilities and notes payable – current (Note 7)  8,266   11,910 
Total current liabilities  46,496   52,855 
         
Non-current liabilities:        
Firm transportation contract obligations (Note 15)  9,795   12,729 
Lease liability – non-current (Note 8)  4,793   - 
Production and property taxes payable  2,654   2,914 
Asset retirement obligations (Note 6)  18,788   19,211 
Credit facilities and notes payable (Note 7)  96,034   97,228 
Notes payable – related party (Note 7)  44,465   49,919 
Total non-current liabilities  176,529   182,001 
         
Commitments and contingencies (Note 15)        
         
Stockholders’ equity:        
Preferred stock, $0.01 par value; liquidation preference of $449 at September 30, 2019 and $224 at December 31, 2018; authorized 1,000,000 shares, 50,000 shares issued and outstanding at September 30, 2019 and December 31, 2018  1   1 
Common stock, $0.01 par value; authorized 35,000,000 shares, 7,856,030 and 7,655,759 shares issued and outstanding at September 30, 2019 and December 31, 2018, respectively  79   77 
Additional paid-in capital  85,261   84,612 
Accumulated deficit  (31,628)  (36,939)
Total Carbon stockholders’ equity  53,713   47,751 
Non-controlling interests  27,766   28,284 
Total stockholders’ equity  81,479   76,035 
Total liabilities and stockholders’ equity $304,504  $310,891 

 

See accompanying notes to Condensed Consolidated Financial Statements.

1

  

CARBON ENERGY CORPORATION

Condensed Consolidated Statements of Operations

(Unaudited)

 

 Three Months Ended
March 31,
  Three Months Ended
September 30,
 Nine Months Ended
September 30,
 
(in thousands, except per share amounts) 2019 2018  2019 2018 2019 2018 
     
Revenue:              
Natural gas sales $19,316  $3,939  $11,963  $4,372  $45,495  $11,835 
Natural gas liquids  247   163   10   406   451   1,119 
Oil sales  8,989   2,983   9,049   11,850   27,940   22,924 
Transportation and handling  734   -   304   -   1,361   - 
Marketing gas sales  4,944   -   3,491   -   11,656   - 
Commodity derivative loss  (9,306)  (626)
Commodity derivative gain (loss)  5,595   (3,902)  4,969   (10,550)
Other income  26   14   123   16   820   35 
Total revenue  24,950   6,473   30,535   12,742   92,692   25,363 
                        
Expenses:                        
Lease operating expenses  6,616   2,087   7,689   4,767   21,784   10,824 
Pipeline operating expenses  3,085   -   2,614   -   8,650   - 
Transportation and gathering costs  1,669   855   1,593   1,433   4,392   3,786 
Production and property taxes  2,010   433   16   743   3,692   1,792 
Marketing gas purchases  6,302   -   3,872   -   14,969   - 
General and administrative  4,689   2,948   2,852   3,517   11,489   9,007 
-General and administrative – related party reimbursement  -   (1,116)
General and administrative – related party reimbursement  -   (1,170)  -   (3,383)
Depreciation, depletion and amortization  3,980   1,492   4,112   2,731   11,973   6,202 
Accretion of asset retirement obligations  394   141   420   206   1,219   510 
Total expenses  28,745   6,840   23,168   12,227   78,168   28,738 
                        
Operating loss  (3,795)  (367)
Operating income (loss)  7,367   515   14,524   (3,375)
                        
Other income (expense):                        
Interest expense  (2,914)  (1,002)
Interest expense, net  (3,047)  (1,127)  (9,772)  (3,331)
Warrant derivative gain  -   225   -   -   -   225 
Gain on derecognized equity investment in affiliate – Carbon California  -   5,391   -   -   -   5,390 
Investment in affiliates  19   437 
Investments in affiliates  32   157   73   1,121 
Total other (expense) income  (2,895)  5,051   (3,015)  (970)  (9,699)  3,405 
                        
(Loss) income before income taxes  (6,690)  4,684 
Income (loss) before income taxes  4,352   (455)  4,825   30 
                        
Provision for income taxes  -   -   -   -   -   - 
                        
Net (loss) income before non-controlling interests and preferred shares  (6,690)  4,684 
Net income (loss) before non-controlling interests and preferred shares  4,352   (455)  4,825   30 
                        
Net (loss) income attributable to non-controlling interests  (2,590)  1,115 
Net income (loss) attributable to non-controlling interests  1,170   270   (486)  (2,234)
                        
Net (loss) income attributable to controlling interests before preferred shares  (4,100)  3,569 
Net income (loss) attributable to controlling interests before preferred shares  3,182   (725)  5,311   2,264 
                        
Net income attributable to preferred shares – preferred return  75   -   75   -   225   - 
                        
Net (loss) income attributable to common shares $(4,175) $3,569 
Net income (loss) attributable to common shares $3,107  $(725) $5,086  $2,264 
                        
Net (loss) income per common share:        
Net income (loss) per common share:                
Basic $(0.54) $0.51  $0.40  $(0.09) $0.65  $0.30 
Diluted $(0.54) $0.46  $0.38  $(0.10) $0.63  $0.10 
Weighted average common shares outstanding:                        
Basic  7,663   6,996   7,839   7,701   7,780   7,466 
Diluted  7,932   7,226   8,141   7,701   8,082   7,781 

  

See accompanying notes to Condensed Consolidated Financial Statements.


CARBON ENERGY CORPORATION

Condensed Consolidated Statements of Stockholders’ Equity

(Unaudited)

(in thousands)

  

        Additional  Non-     Total 
  Common Stock  Paid-in  Controlling  Accumulated  Stockholders’ 
  Shares  Amount  Capital  Interests  Deficit  Equity 
                   
Balances, December 31, 2017  6,006  $60  $58,813  $1,841  $(44,218) $16,496 
Stock based compensation  -   -   292   -   -   292 
Restricted stock vested  38   1   -   -   -   1 
CCC warrant exercise – share issuance  1,528   15   8,311   16,466   -   24,792 
CCC warrant exercise – liability extinguishment  -   -   1,792   -   -   1,792 
Non-controlling interest distributions, net  -   -   -   (24)  -   (24)
Net income  -   -   -   1,115   3,569   4,684 
                         
Balances, March 31, 2018  7,572  $76  $69,208  $19,398  $(40,649) $48,033 

              Additional  Non-     Total 
  Common Stock  Preferred Stock  Paid-in  Controlling  Accumulated  Stockholders’ 
  Shares  Amount  Shares  Amount  Capital  Interests  Deficit  Equity 
Balance as of December 31, 2017  6,006  $60   -  $-  $58,813  $1,841  $(44,218) $16,496 
Stock-based compensation  -   -   -   -   292   -   -   292 
Restricted stock vested  38   1   -   -   -   -   -   1 
CCC warrant exercise – share issuance  1,528   15   -   -   8,311   16,466   -   24,792 
CCC warrant exercise – liability extinguishment  -   -   -   -   1,792   -   -   1,792 
Non-controlling interests’ distributions, net  -   -   -   -   -   (24)  -   (24)
Net income  -   -   -   -   -   1,115   3,569   4,684 
Balance as of March 31, 2018  7,572  $76   -  $-  $69,208  $19,398  $(40,649) $48,033 
Stock-based compensation  -   -   -   -   192   -   -   192 
Restricted stock vested  21   -   -   -   -   -   -   - 
Performance units vested  108   1   -   -   (1)  -   -   - 
Preferred share issuance (Note 11)  -   -   50   1   4,999   -   -   5,000 
Beneficial conversion feature  -   -   -   -   1,125   -   (1,125)  - 
Deemed dividend  -   -   -   -   71   -   (71)  - 
Non-controlling interests’ contributions, net  -   -   -   -   -   5,498   -   5,498 
Net loss  -   -   -   -   -   (3,619)  (579)  (4,198)
Balance as of June 30, 2018  7,701  $77   50  $1  $75,594  $21,277  $(42,424) $54,525 
Stock-based compensation  -   -   -   -   187   -   -   187 
Deemed dividend  -   -   -   -   77   -   (77)  - 
Non-controlling interests’ contributions, net  -   -   -   -   -   4   -   4 
Net loss  -   -   -   -   -   270   (725)  (455)
Balance as of September 30, 2018  7,701  $77   50  $1  $75,858  $21,551  $(43,226) $54,261 

 

              Additional  Non-     Total 
  Common Stock  Preferred Stock  Paid-in  Controlling  Accumulated  Stockholders’ 
  Shares  Amount  Shares  Amount  Capital  Interests  Deficit  Equity 
                         
Balances, December 31, 2018  7,656  $77   50  $1  $84,612  $28,284  $(36,939) $76,035 
Stock-based compensation  -   -   -   -   222   -   -   222 
Restricted stock vested  40   1   -   -   -   -   -   1 
Performance units vested  95   1   -   -   (1)  -   -   - 
Non-controlling interests’ contributions, net  -   -   -��  -   -   22   -   22 
Net loss  -   -   -   -   -   (2,590)  (4,100)  (6,690)
                                 
Balances, March 31, 2019  7,791  $79   50  $1  $84,833  $25,716  $(41,039) $69,590 

              Additional  Non-     Total 
  Common Stock  Preferred Stock  Paid-in  Controlling  Accumulated  Stockholders’ 
  Shares  Amount  Shares  Amount  Capital  Interests  Deficit  Equity 
Balance as of December 31, 2018  7,656  $77   50  $1  $84,612  $28,284  $(36,939) $76,035 
Stock-based compensation  -   -   -   -   222   -   -   222 
Restricted stock vested  40   1   -   -   -   -   -   1 
Performance units vested  95   1   -   -   (1)  -   -   - 
Non-controlling interests’ contributions, net  -   -   -   -   -   22   -   22 
Net loss  -   -   -   -   -   (2,590)  (4,100)  (6,690)
Balance as of March 31, 2019  7,791  $79   50  $1  $84,833  $25,716  $(41,039) $69,590 
Stock-based compensation  -   -   -   -   224   -   -   224 
Restricted stock vested  25   -   -   -   -   -   -   - 
Non-controlling interests’ distributions, net  -   -   -   -   -   (16)  -   (16)
Net income  -   -   -   -   -   934   6,229   7,163 
Balance as of June 30, 2019  7,816  $79   50  $1  $85,057  $26,634  $(34,810) $76,961 
Stock-based compensation  -   -   -   -   204   -   -   204 
Restricted stock vested  40   -   -   -   -   -   -   - 
Non-controlling interests’ distributions, net  -   -   -   -   -   (38)  -   (38)
Net income  -   -   -   -   -   1,170   3,182   4,352 
Balance as of September 30, 2019  7,856  $79   50  $1  $85,261  $27,766  $(31,628) $81,479 

 

See accompanying notes to Condensed Consolidated Financial Statements.


3

  

CARBON ENERGY CORPORATION

Condensed Consolidated Statements of Cash Flows

(Unaudited)

  

 Three Months Ended  Nine Months Ended 
 March 31,  September 30, 
(in thousands) 2019 2018  2019 2018 
     
Cash flows from operating activities:          
Net (loss) income $(6,690) $4,684 
Net income $4,825  $30 
Items not involving cash:                
Depreciation, depletion and amortization  3,980   1,492   11,973   6,202 
Accretion of asset retirement obligations  394   141   1,219   510 
Unrealized commodity derivative loss  8,850   249 
Unrealized commodity derivative (gain) loss  (2,771)  8,381 
Warrant derivative gain  -   (225)  -   (225)
Stock-based compensation expense  222   292   650   672 
Investment in affiliates gain  (19)  (437)
Investments in affiliates  (57)  (1,121)
Gain on derecognized equity investment in affiliate – Carbon California  -   (5,391)  -   (5,390)
Amortization of debt costs  277   89   644   468 
Interest expense paid-in-kind  1,819   - 
Other  (56)  - 
Net change in:                
Accounts receivable  6,091   (1,611)  8,971   (2,975)
Prepaid expenses, deposits and other current assets  375   448   (982)  456 
Accounts payable, accrued liabilities and firm transportation contract obligations  (5,485)  907   (11,718)  (1,945)
Other non-current items  316   (543)  (395)  (1,751)
Net cash provided by operating activities  8,311   95   14,122   3,312 
                
Cash flows from investing activities:                
Development and acquisition of properties and equipment  (500)  (874)  (4,226)  (44,681)
Proceeds received – disposition of oil and gas properties  164   - 
Proceeds received – Carbon California Acquisition  -   275   -   275 
Distribution from affiliate  50   - 
Proceeds received – disposition of oil and gas properties and other property and equipment  314   - 
Net cash used in investing activities  (336)  (599)  (3,862)  (44,406)
                
Cash flows from financing activities:                
Proceeds from credit facility and notes payable  3,000   3,000 
Payments on credit facility and notes payable  (5,676)  (8)
Debt issuance costs  (41)  - 
Distributions to (contributions from) non-controlling interests  22   (24)
Proceeds from credit facilities and notes payable  4,000   34,529 
Proceeds from preferred shares  -   5,000 
Payments on credit facilities and notes payable  (16,396)  (14)
Payments of debt issuance costs  (54)  (586)
(Distributions to) contributions from non-controlling interests, net  (32)  4,992 
Net cash (used in) provided by financing activities  (2,695)  2,968   (12,482)  43,921 
                
Net increase in cash and cash equivalents  5,280   2,464 
Net (decrease) increase in cash and cash equivalents  (2,222)  2,827 
                
Cash and cash equivalents, beginning of period  5,736   1,650   5,736   1,650 
                
Cash and cash equivalents, end of period $11,016  $4,114  $3,514  $4,477 

   

See accompanying notes to Condensed Consolidated Financial Statements.


CARBON ENERGY CORPORATION

Notes to Condensed Consolidated Financial Statements

(Unaudited)

 

NoteNOTE 1 – OrganizationORGANIZATION

 

Carbon Energy Corporation (formerly known as Carbon Natural Gas Company) is an independent oil and its subsidiaries (referred to herein asnatural gas company engaged in the acquisition, exploration, development and production of oil, natural gas and natural gas liquids properties located in the United States. The terms “we”, “us”, “our”, the “Company” or “Carbon”) business refer to Carbon Energy Corporation and our consolidated subsidiaries (described below). The following is comprisedan organization chart of the assets and propertieskey subsidiaries as of us and our subsidiaries.September 30, 2019 discussed in this report:

 

An illustrative organizational chart as of March 31, 2019, is below:

 

 

Appalachian and Illinois Basin Operations

 

In the Appalachian and Illinois Basins, operations are conducted by Nytis Exploration Company, LLC (“Nytis LLC”). The following organizational chart illustrates this relationship as of March 31, 2019.September 30, 2019:

 

  

 


In December 2018, we completed the acquisition of all of the Class A Units of Carbon Appalachian Company, LLC, a Delaware limited liability company (“Carbon Appalachia”), owned by Old Ironside Fund II-A Portfolio Holding Company, LLC, a Delaware limited liability company, (“OIE II-A”), and Old Ironside Fund II-B Portfolio Holding Company, LLC, a Delaware limited liability company, (“OIE II-B”), collectively (“Old Ironsides”) for a purchase price of $58.1 million, subject to customary and standard purchase price adjustments (“OIE Membership Acquisition”). As a result of the OIE Membership Acquisition, we now hold all of the issued and outstanding ownership interests of Carbon Appalachia, along with its direct and indirect subsidiaries (Carbon Appalachia Group, LLC, Carbon Tennessee Mining Company, LLC, Carbon Appalachia Enterprises, LLC, Carbon West Virginia Company, LLC, Cranberry Pipeline Corporation, Knox Energy, LLC, Coalfield Pipeline Company and Appalachia Gas Services Company, LLC).

 


Ventura Basin Operations

 

In California, Carbon California Operating Company, LLC (“CCOC”) conducts operations on behalf of Carbon California Company, LLC’sLLC, a Delaware limited liability company (“Carbon California”) operations.. On February 1, 2018, Yorktown Energy Partners XI, L.P. (“Yorktown”) exercised the California Warrant,a warrant, collectively resulting in our aggregate sharing percentage in Carbon California increasing from 17.81% to 56.40%. On May 1, 2018, Carbon California closed the acquisition with Seneca Acquisition.Resources Corporation (the “Seneca Acquisition”). Following the exercise of the California Warrantwarrant by Yorktown and the Seneca Acquisition, we own 53.92% of the voting and profits interests and Prudential Legacy Insurance Company of New Jersey and Prudential Insurance Company of America or its affiliates (collectively, “Prudential”) owns 46.08% of the voting and profits interest in Carbon California. As of February 1, 2018, we consolidate Carbon California for financial reporting purposes. The following organizational chart illustrates this relationship as of March 31, 2019.September 30, 2019:

 

 

Collectively, references to “us” include Carbon California, CCOC, Nytis Exploration (USA) Inc. (“Nytis USA”), Nytis LLC, and Carbon Appalachia.6

 

NoteNOTE 2 – Summary of Significant Accounting PoliciesSUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

Basis of Presentation

 

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principlesthe rules and regulations of the Securities and Exchange Commission (“SEC”) and in accordance with U.S. generally accepted in the United Statesaccounting principles (“GAAP”) forapplicable to interim financial information. Accordingly, they do not include all the information and footnotes required by GAAP for complete financial statements. In the opinion of management, the accompanyingThese unaudited condensed consolidated financial statements includereflect all normal recurring adjustments consideredthat are, in the opinion of management, necessary to present fairly our financial position asfor a fair presentation of March 31, 2019, and ourthe results of operations and cash flows for the three months ended March 31, 2019 and 2018.interim period. Operating results for the three months ended March 31, 2019interim periods presented require management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes and are not necessarily indicative of the results that may be expected for the full year becauseyear. The condensed consolidated balance sheet data as of the impact of fluctuations in prices received for oil and natural gas, natural production declines, the uncertainty of exploration and development drilling results, seasonality, and other factors. TheDecember 31, 2018 was derived from audited financial statements but does not include all disclosures required by GAAP. These unaudited condensed consolidated financial statements and related notes included in this Quarterly Report on Form 10-Q should be read in conjunction with our consolidated financial statements and related notes included in our Annual Report on Form 10-K for the year ended December 31, 2018. Except as disclosed herein, there have been no material changes toThe Company follows the information disclosed in the notes to the consolidated financial statements included in our 2018 Annual Report on Form 10-K.same accounting policies for preparing quarterly and annual reports.

 

Principles of Consolidation

 

The unaudited condensed consolidated financial statements include the accounts of our consolidated subsidiaries. Upon the closing of the OIE Membership Acquisition on December 31, 2018, we own 100% of Carbon Appalachia. In addition, we own 100% of Nytis USA, which owns approximately 98.1%98.11% of Nytis LLC. Nytis LLC holds interests in various oil and gas partnerships.


 

Partnerships and subsidiaries in which we have a controlling interest are consolidated. We are currently consolidating 46 partnerships, Carbon Appalachia, and Carbon California, and we reflect the non-controlling ownership interest in partnerships and subsidiaries as non-controlling interests on our unaudited condensed consolidated statements of operations and also reflect the non-controlling ownership interest in the net assets of the partnerships as non-controlling interests within stockholders’ equity on our unaudited condensed consolidated balance sheets. All significant intercompany accounts and transactions have been eliminated.

 

In accordance with established practice in the oil and gas industry, our unaudited condensed consolidated financial statements also include our pro-rata share of assets, liabilities, income, lease operating costs and general and administrative expenses of the oil and gas partnerships in which we have a non-controlling interest.

 

Non-majority owned investments that do not meet the criteria for pro-rata consolidation are accounted for using the equity method when we have the ability to significantly influence the operating decisions of the investee. When we do not have the ability to significantly influence the operating decisions of an investee, the cost method is used. All transactions, if any, with investees have been eliminated in the accompanying unaudited condensed consolidated financial statements.

 

Reclassifications

 

Certain prior period balances in the consolidated balance sheets and statements of operations have been reclassified to conform to the current year presentation.  Specifically, a portion of credit facilities and notes payable balances as of December 31, 2018 were reclassified from non-current liabilities to current liabilities. This reclassification had no impact on net income, cash flows or shareholders’stockholders’ equity previously reported.

 

Insurance Receivable

 

Insurance receivable is comprised of insurance claims for the loss of property as a result of wildfires that impacted Carbon California in December 2017. The Company filed claims with its insurance provider. In January 2019, we reached a settlement agreement and received an $800,000 final settlement payment from our insurance provider related to the damage caused by the California wildfires. As of March 31,September 30, 2019, we arewere in receipt of all funds associated with the claims.

 

Accounting for Oil and Gas OperationsRevenue

 

We use the full cost method of accounting for oil and gas properties. Accordingly, all costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Overhead costs incurred that are directly identified with acquisition, exploration and development activities undertaken by the Company for its own account, and which are not related to production, general corporate overhead or similar activities, are also capitalized.

Unproved properties are excluded from amortized capitalized costs until it is determined if proved reserves can be assigned to such properties. We assess our unproved properties for impairment at least annually. Significant unproved properties are assessed individually.

Capitalized costs are depleted by an equivalent unit-of-production method, converting oil to gas at the ratio of one barrel of oil to six thousand cubic feet of natural gas. Depletion is calculated using capitalized costs, including estimated asset retirement costs, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values.

No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves. All costs related to production activities, including work-over costs incurred solely to maintain or increase levels of production from an existingUpon completion interval, are charged to expense as incurred.

We perform a ceiling test quarterly. The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is not a fair value based measurement, rather it is a standardized mathematical calculation. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using the un-weighted arithmetic average of the first-day-of-the month priceOIE Membership Acquisition, our revenue recognition policy was amended to account for the previous twelve month period, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the bookadditional revenue we receive for transportation and tax basis of oilhandling and gas properties. Should the net capitalized costs exceed the sum of the components noted above, a ceiling test write-down would be recognized to the extent of the excess capitalized costs. Such impairments are permanent and cannot be recovered in future periods even if the sum of the components noted above exceeds the capitalized costs in future periods.


For the three months ended March 31, 2019 and 2018, we did not recognize a ceiling test impairment as our full cost pool did not exceed the ceiling limitations. Future declines in oil and natural gas prices could result in impairments of our oil and gas properties in future periods. The effect of price declines will impact the ceiling test value until such time commodity prices stabilize or improve. Impairments are a non-cash charge and accordingly would not affect cash flows but would adversely affect our results of operations and members’ equity.

We capitalize the portion of general and administrative costs that is attributable to our acquisition, exploration and development activities.

Revenue

We recognize revenues for sales and services when persuasive evidence of an arrangement exists, when custody is transferred, or services are rendered, fees are fixed or determinable and collectability is reasonably assured.

Oil, Natural Gas and Natural Gas Liquid Sales

Oil, natural gas and natural gas liquid sales are recognized when production volumes are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred, and collectability is reasonably assured. Revenues are recognized based on our net revenue interest.

Marketing Gas Sales

We sell production purchased from third parties as well as production from our own oil and gas producing properties. Marketingmarketing gas sales, are recognized on a gross basis as we purchase and take control of the gas prior to sale and are the principal in the transaction.described below.

Storage

Under fee-based arrangements, we receive a fee for storing natural gas. The revenues earned are directly related to the volume of natural gas that flows through our systems and are not directly dependent on commodity prices.

Transportation gathering, and compressionHandling

 

We generally purchase natural gas from producers at the wellhead or other receipt points, gather the wellhead natural gas through our gathering systems, and then sell the natural gas based on published index market prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of natural gas or an agreed-upon percentage of the proceeds based on index related prices for the natural gas, regardless of the actual amount of the sales proceeds we receive. Our revenues under percent-of-proceeds/index arrangements generally correlate to the price of natural gas. Under fee-based arrangements, we receive a fee for storing natural gas. The storage revenues earned are directly related to the volume of natural gas that flows through our systems and are not directly dependent on commodity prices.


Marketing Gas Sales

 

Investments in Affiliates

Investments in non-consolidated affiliates are accounted for under either the cost or equity method of accounting,We sell production purchased from third parties as appropriate. The cost method of accounting is generally used for investments in affiliates in which we have less than 20% of the voting interests of a corporate affiliate (or less than a 3% to 5% interest of a partnership or limited liability company) and do not have significant influence. Investments in non-consolidated affiliates, accounted for using the cost method of accounting, are recorded at cost and impairment assessments for each investment are made annually to determine if a decline in the fair value of the investment, other than temporary, has occurred. A permanent impairment is recognized if a decline in the fair value occurs.

If we hold between 20% and 50% of the voting interest in non-consolidated corporate affiliates or generally greater than a 3% to 5% interest of a partnership or limited liability company and can exert significant influence or control (e.g., throughwell as production from our influence with a seat on the board of directors or management of operations), the equity method of accounting is generally used to account for the investment. Equity method investments will increase or decrease by our share of the affiliate’s profits or losses and such profits or losses are recognized in our unaudited consolidated statements of operations. We review equity method investments for impairment whenever events or changes in circumstances indicate that an other than temporary decline in value has occurred. Upon the exercise of the California Warrant on February 1, 2018 and the closing of the OIE Membership Acquisition on December 31, 2018, we consolidate Carbon California and Carbon Appalachia for financial reporting purposes and no longer account for these investments under the equity method.


Related Party Transactions

Management Reimbursements

In our role as manager of Carbon California and Carbon Appalachia we receive reimbursements for management services. Prior to consolidation of Carbon California and Carbon Appalachia effective February 1, 2018 and December 31, 2018, respectively, these management service reimbursements were included in general and administrative – related party reimbursement on our unaudited consolidated statements of operations. As we now consolidate both Carbon California and Carbon Appalachia, these reimbursements are eliminated upon consolidation.

We received approximately $753,000 and $50,000 for the three months ended March 31, 2018, and for the one month ended January 31, 2018, from Carbon Appalachia and Carbon California, respectively. These reimbursements are included in general and administrative – related party reimbursement on our unaudited consolidated statements of operations. Effective February 1, 2018, the management reimbursements received from Carbon California were eliminated at consolidation. This elimination included $100,000 for the period February 1, 2018, through March 31, 2018.

In addition to the management reimbursements, approximately $299,000 and $14,000 in general and administrative expenses were reimbursed for the three months ended March 31, 2018, and for the one month ended January 31, 2018, by Carbon Appalachia and Carbon California, respectively. The elimination of Carbon California in consolidation includes approximately $28,000 for the period February 1, 2018, through March 31, 2018.

Operating Reimbursements

In our role as operator of Carbon California and Carbon Appalachia, we receive reimbursements of operating expenses. Prior to consolidation of Carbon California and Carbon Appalachia effective February 1, 2018 and December 31, 2018, respectively, these operating reimbursements were included in operating expenses on our unaudited consolidated statements of operations. As we now consolidate both Carbon California and Carbon Appalachia, any intercompany receivable and payable balances associated with these reimbursements are eliminated upon consolidation.

Carbon California Credit Facilities

The credit facilities of Carbon California, including the Senior Revolving Notes, Carbon California Notes and Carbon California 2018 Subordinated Notes (all defined below), are held by Prudential (see Note 7).

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities and expenses and disclosure of contingent assets and liabilities. Significant items subject to such estimates and assumptions include the carrying value ofown oil and gas properties, estimatesproducing properties. Marketing gas sales are recognized on a gross basis as we purchase and take control of proved oilthe gas prior to sale and gas reserve volumes andare the related depletion and present value of estimated future net cash flows and the ceiling test applied to capitalized oil and gas properties, determining the amounts recorded for fair value of commodity derivative instruments, fair value of assets acquired and liabilities assumed qualifying as business combinations or asset acquisitions, estimated lives of other property and equipment, asset retirement obligations, fair value of Class B issuances and accrued liabilities and revenues. There have been no changes in our critical accounting estimates from those that were disclosedprincipal in the 2018 Annual Report on Form 10-K. Actual results could differ from these estimates.


Earnings (Loss) Per Common Sharetransaction.

 

Basic earnings per common share is computed by dividing the net income or loss attributable to common stockholders for the period by the weighted average number of common shares outstanding during the period. The shares of restricted common stock granted to our officers, directors and employees are included in the computation of basic net income per share only after the shares become fully vested. Diluted earnings per common share includes both the vested and unvested shares of restricted stock and the potential dilution that could occur upon exercise of options and warrants to acquire common stock computed using the treasury stock method, which assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by us with the proceeds from the exercise of options and warrants (which were assumed to have been made at the average market price of the common shares during the reporting period).

In periods when we report a net loss, all shares of restricted stock are excluded from the calculation of diluted weighted average shares outstanding because of its anti-dilutive effect on loss per share. As a result, approximately 269,000 potentially dilutive restricted stock awards are excluded from the calculation of diluted earnings per common share for the three months ended March 31, 2019. In addition, approximately 200,000 restricted performance units subject to future contingencies were excluded in the basic and diluted income per share calculations.

For the three months ended March 31, 2018, we had net income and the diluted income per common share calculation includes the dilutive effects of approximately 230,000 non-vested shares of restricted stock. In addition, approximately 254 ,000 restricted performance units subject to future contingencies were excluded in the basic and diluted income per share calculations.

The following table sets forth the calculation of basic and diluted (loss) income per share:

  Three months ended
March 31,
 
(in thousands except per share amounts) 2019  2018 
       
Net (loss) income attributable to common shareholders $(4,175) $3,569 
Less:  warrant derivative gain  -   (225)
Diluted net income  (4,175)  3,344 
         
Basic weighted-average common shares outstanding during the period  7,663   6,996 
         
Add dilutive effects of warrants and non-vested shares of restricted stock  269   230 
         
Diluted weighted-average common shares outstanding during the period  7,932   7,226 
         
Basic net (loss) income per common share $(0.54) $0.51 
Diluted net (loss) income per common share $(0.54) $0.46 

Recently Adopted Accounting Pronouncement

 

In February 2016, the FASB issuedOn January 1, 2019, we adopted Accounting Standards Update No. 2016-02, Leases(“ASUTopic 842”) 2016-02,Leases (Topic 842)(ASU 2016-02), as amended, which establishes a comprehensive newsupersedes the lease standard designedaccounting guidance under Topic 840, and generally requires lessees to increase transparencyrecognize operating and comparability among organizations by recognizing lease assets andfinancing lease liabilities and corresponding right-of-use assets on the balance sheet and disclosing key information aboutto provide enhanced disclosures surrounding the amount, timing and uncertainty of cash flows arising from leasing arrangements. The FASB subsequently issued various ASUs which provided additional implementationWe adopted the new guidance and these ASUs collectively make up FASB Accounting Standards Codification (“ASC”) Topic 842 – Leases (“ASC 842”). ASC 842 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. The standard permits retrospective application through recognition of a cumulative-effect adjustment at the beginning of either the earliest reporting period presented or the period of adoption. The Company adopted ASC 842 effective January 1, 2019 using the modified retrospective method astransition approach by applying the new standard to all leases existing at the date of the adoption date. Adoption of the standard resulted ininitial application and not restating comparative periods. The most significant impact was the recognition of additional leaseright-of-use assets and lease liabilities on our unaudited consolidated balance sheet as well as additional disclosures. The adoption did not have a material impact to our unaudited consolidated statement of operations. Refer tofor operating leases. See Note 148 for further information on our implementation of this standard.


Recently Issued Accounting Pronouncements

 

There were various updates recently issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on our reported financial position, results of operations, or cash flows.NOTE 3 – ACQUISITIONS

 

Note 3 – Acquisitions and Divestitures

Majority Control of Carbon Appalachia

 

On December 16, 2016, Carbon Appalachia was formed by us, entities managed by Yorktown and entities managed by31, 2018, we acquired all of Old Ironsides to acquire producing assets in the Appalachian Basin in Kentucky, Tennessee, Virginia and West Virginia. Carbon Appalachia began substantial operations on April 3, 2017 and is engaged primarily in acquiring, developing, exploiting, producing, processing, marketing, and transporting oil and natural gas in the Appalachian Basin.

On April 3, 2017, Carbon, Yorktown and Old Ironsides entered in to a limited liability company agreement (the “Carbon Appalachia LLC Agreement”), with an initial equity commitment of $100.0 million, of which $37.0 million had been contributed as of December 31, 2018. Carbon Appalachia (i) issued Class A Units to us, Yorktown and Old Ironsides for an aggregate cash consideration of $12.0 million, (ii) issued Class B Units to us, and (iii) issued Class C Units to us. Additionally, Carbon Appalachia Enterprises, LLC, formerly known as Carbon Tennessee Company, LLC (“Carbon Appalachia Enterprises”), a subsidiary of Carbon Appalachian Company, LLC, entered into a 4-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank (the“Revolver”) with an initial borrowing base of $10.0 million.

In connection with Carbon entering into the Carbon Appalachia LLC Agreement, and Carbon Appalachia engaging in the transactions described above, Carbon received 1,000 Class B Units and issued to Yorktown a warrant to purchase approximately 408,000 shares of our common stock at an exercise price dictated by the warrant agreement (the“Appalachia Warrant”). The Appalachia Warrant was payable exclusively withIronsides’ Class A Units of Carbon Appalachia held by Yorktown. On November 1, 2017, Yorktown exercisedfor approximately $58.1 million. We paid $33.0 million in cash and delivered promissory notes in the Appalachia Warrant, resulting in us acquiring 2,940 Class A Units from Yorktown. 

On August 15, 2017, the Carbon Appalachia LLC Agreement was amended and, as a result, we agreedaggregate original principal amount of approximately $25.1 million to contribute an initial commitment of future capital contributions as well as Yorktown’s, and Yorktown will not participate in future capital contributions. Carbon Appalachia issued Class A Units to us and Old Ironsides for an aggregate cash consideration of $14.0 million. The borrowing base of the Revolver increased to $22.0 million and Carbon Appalachia Enterprises borrowed $8.0 million under the Revolver.


On September 29, 2017, Carbon Appalachia issued Class A Units to us and (theOld Ironsides Notes”). See Note 7 for an aggregate cash consideration of $11.0 million.additional information.

 

Prior to the closing of the OIE Membership Acquisition, Old Ironsides held 27,195 Class A Units, which equated to a 72.76% aggregate share ownership of Carbon Appalachia and we held (i) 9,805 Class A Units, (ii) 1,000 Class B Units and (iii) 121 Class C Units, which equated to a 27.24% aggregate share ownership of Carbon Appalachia.

 

On December 31, 2018, we acquired all of Old Ironsides’ Class A Units of Carbon Appalachia for approximately $58.1 million, subject to customary and standard closing adjustments. We paid $33.0 million in cash and delivered promissory notes in the aggregate original principal amount of approximately $25.1 million to Old Ironsides (the“Old Ironsides Notes”). The Old Ironsides Notes bear interest at 10% per annum and have a term of five years, the first three of which require interest-only payments at the end of each calendar quarter beginning with the quarter ending March 31, 2019. At the end of the three-year interest-only period, the then current outstanding principal balance and interest is to be paid in 24 equal monthly payments. The Old Ironsides Notes also provide for mandatory prepayments upon the occurrence of certain subsequent liquidity events. A mandatory, one-time principal reduction payment in the aggregate amount of $2.0 million was made to Old Ironsides on February 1, 2019.

The OIE Membership Acquisition iswas accounted for as a business combination in accordance with ASC 805, Business Combinations (“ASC 805”). We recognized 100% of the identifiable assets acquired and liabilities assumed at their respective fair value as of the date of the acquisition. The $58.1 million purchase price, consisting of $33.0 million in cash and $25.1 million of Old Ironsides Notes, was paid for Old Ironsides’ outstanding interest, representing approximately 72.76% interest in Carbon Appalachia.

The Company, utilizing the assistance of third-party valuation specialists, considered various factors in its estimate of fair value of the acquired assets and liabilities including (i) reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices, including price differentials, (v) future cash flows, (vi) a market participant-based weighted average cost of capital, and (vii) real estate market conditions.

We followed the fair value method to allocate the consideration transferred to the identifiable net assets acquired on a preliminary basis as follows:

  Amount 
(in thousands)
 
Cash consideration $33,000 
Old Ironsides Notes  25,065 
Fair value of previously held equity interest  14,158 
Fair value of business acquired $72,223 

Assets acquired and liabilities assumed are as follows:

  Amount
(in thousands)
 
Cash $12,283 
Accounts receivable:    
Revenue  12,834 
Trade receivable  1,941 
Commodity derivative asset  198 
Inventory  900 
Prepaid expenses, deposits, and other current assets  456 
Oil and gas properties:    
Proved  107,499 
Unproved  1,869 
Other property, plant and equipment, net  15,626 
Other non-current assets  514 
Accounts payable and accrued liabilities  (19,114)
Due to related parties  (458)
Firm transportation contract obligations  (18,724)
Asset retirement obligations  (5,626)
Notes payable  (37,975)
Total net assets acquired $72,223 

The preliminary fair value of the assets acquired and liabilities assumed were determined using various valuation techniques, including an income approach.


On the date of the acquisition, we derecognized our equity investment in Carbon Appalachia and recognized a gain of approximately $1.3 million based on the fair value of our previously held interest compared to its carrying value.

For assets and liabilities accounted for as business combinations, including the OIE Membership Acquisition, we utilized the assistance of third-party valuation specialists to determine the fair value of the assets acquired, the Companyand liabilities acquired. We primarily used the income approach and made market assumptions as to projections of estimated quantities of oil and natural gas reserves, future production rates, future commodity prices including price differentials as of the date of closing, future operating and development costs, a market participant weighted average cost of capital, and the condition of vehicles and equipment. The CompanyWe used the income approach and made market assumptions as to projections of utilization, future operating costs and a market participant weighted average costscost of capital to determine the fair value of the firm transportation obligations as well as the plant facilities. The determination of the fair value of accounts payable and accrued liabilities assumed required significant judgement, including estimates relating to production assets.

 

The following summarizes the estimated fair values of the identifiable assets acquired and liabilities assumed in the acquisition based on their relative fair values at the acquisition date. These estimates of fair value of identifiable assets acquired and liabilities assumed are preliminary, pending final evaluation of certain assets and liabilities, and therefore are subject to revisions that may result in adjustments to the values presented below:

  Amount 
(in thousands)
 
Cash consideration $33,000 
Old Ironsides Notes  25,030 
Fair value of previously held equity interest  14,158 
Fair value of business acquired $72,188 


Assets acquired and liabilities assumed are as follows:

  Amount
(in thousands)
 
Cash $12,283 
Accounts receivable:    
Revenue  12,834 
Trade receivable  1,941 
Commodity derivative asset  198 
Inventory  2,022 
Prepaid expenses, deposits, and other current assets  456 
Oil and gas properties:    
Proved  107,879 
Unproved  1,869 
Other property, plant and equipment, net  15,441 
Other non-current assets  514 
Accounts payable and accrued liabilities  (20,466)
Due to related parties  (458)
Firm transportation contract obligations  (18,724)
Asset retirement obligations  (5,626)
Notes payable  (37,975)
Total net assets acquired $72,188 

On the date of the acquisition, we derecognized our equity investment in Carbon Appalachia and recognized a gain of approximately $1.3 million based on the fair value of our previously held interest compared to its carrying value.

Consolidation of Carbon Appalachia and OIE Membership Acquisition Unaudited Pro Forma Results of Operations

 

Below are unaudited pro forma consolidated results of operations for the three and nine months ended March 31, 2019 andSeptember 30, 2018 as though the OIE Membership Acquisition had been completed as of January 1, 2018. Results for the three and nine months ended September 30, 2019 are reflected in the unaudited condensed consolidated statements of operations.

 

  Three Months Ended March 31,  Three Months Ended March 31, 
(in thousands, except per share amounts) 2019  2018 
Revenue $24,950  $32,316 
Net (loss) income before non-controlling interests 

$

(6,690) 

$

6,912 
Net (loss) income attributable to non-controlling interests $(2,590) $1,115 
Net (loss) income attributable to common shareholders $(4,175) $5,797 
Net (loss) income per share (basic) $(0.54) $0.83 
Net (loss) income per share (diluted) $(0.54) $0.77 
  Three Months Ended
September 30,
  Nine Months Ended
September 30,
 
(in thousands, except per share amounts) 2018  2018 
Revenue $27,681  $82,521 
Net income before non-controlling interests $1,729  $4,495 
Net income (loss) attributable to non-controlling interests $270  $(2,234)
Net income attributable to controlling interests before preferred shares $1,459  $6,729 
Net income per share, basic $0.19  $0.90 
Net income per share, diluted $0.18  $0.70 

 

Consolidation of Carbon California Unaudited Pro Forma Results of Operations

On February 1, 2018, Yorktown exercised the California Warrant resulting in the issuance of 1,527,778 shares of our common stock in exchange for Yorktown’s Class A Units of Carbon California representing approximately 46.96% of the outstanding Class A Units of Carbon California (a profits interest of approximately 38.59%). After giving effect to the exercise on February 1, 2018, we owned 56.4% of the voting and profits interests of Carbon California.

  

Below are unaudited pro forma consolidated results of operations for the three and nine months ended March 31, 2019 andSeptember 30, 2018 as though the Carbon California Acquisition had been completed as ofoccurred on January 1, 2018. The Carbon California Acquisition closed February 1, 2018,Results for the three and accordingly,nine months ended September 30, 2019 are reflected in the Company’s unaudited condensed consolidated statements of operations for the quarter ended March 31, 2018, includes the results of operations for the period February 1, 2018, through March 31, 2018.operations.

 

  Three Months Ended March 31,  Three Months Ended March 31, 
(in thousands, except per share amounts) 2019  2018 
Revenue $24,950  $6,672 
Net (loss) income before non-controlling interests $(6,690) 

$

3,543 
Net (loss) income attributable to non-controlling interests $(2,590) 

$

1,115 
Net (loss) income attributable to common shareholders $(4,175) 

$

2,428 
Net (loss) income per share (basic) $(0.54) 

$

0.35 
Net (loss) income per share (diluted) $(0.54) 

$

0.30 
  Three Months Ended
September 30,
  Nine Months Ended
September 30,
 
(in thousands, except per share amounts) 2018  2018 
Revenue $12,742  $33,256 
Net (loss) income before non-controlling interests $(455) $5,232 
Net income (loss) attributable to non-controlling interests $270  $(2,334)
Net (loss) income attributable to controlling interests before preferred shares $(725) $7,566 
Net (loss) income per share, basic $(0.09) $1.00 
Net (loss) income per share, diluted $(0.10) $0.96 

 


NoteNOTE 4 – Property and EquipmentPROPERTY AND EQUIPMENT

 

Net propertyProperty and equipment, as of March 31, 2019 and December 31, 2018net consists of the following:

 

(in thousands) March 31,
2019
  December 31,
2018
 
       
Oil and gas properties:      
Proved oil and gas properties $344,147  $343,736 
Unproved properties not subject to depletion  5,385   5,416 
Accumulated depreciation, depletion, amortization and impairment  (98,826)  (95,281)
Net oil and gas properties  250,706   253,871 
Pipeline facilities and equipment  12,714   12,714 
Base gas  2,122   2,122 
Furniture and fixtures, computer hardware and software, and other equipment  6,688   6,649 
Accumulated depreciation and amortization  (4,356)  (3,922)
Net other property and equipment  17,168   17,563 
         
Total net property and equipment $267,874  $271,434 

(in thousands) September 30,
2019
  December 31,
2018
 
       
Oil and gas properties:      
Proved oil and gas properties $349,550  $343,736 
Unproved properties not subject to depletion  5,004   5,416 
Accumulated depreciation, depletion, amortization and impairment  (105,957)  (95,281)
Net oil and gas properties  248,597   253,871 
Pipeline facilities and equipment  12,714   12,714 
Base gas  1,937   2,122 
Furniture and fixtures, computer hardware and software, and other equipment  6,733   6,649 
Accumulated depreciation and amortization  (5,131)  (3,922)
Net other property and equipment  16,253   17,563 
         
Property and equipment, net $264,850  $271,434 

 

As of March 31,September 30, 2019, and December 31, 2018, the Company had approximately $5.0 million and $5.4 million, respectively, of unproved oil and gas properties not subject to depletion. TheSuch costs not subject to depletion relate to unproved properties that are excluded from amortized capital coststhe full cost pool until it is determined if proved reserves can be assigned to suchthe related properties. The excluded properties are assessed for impairment at least annually. Subject to industry conditions, evaluation of most of these properties and the inclusion of their costs in amortized capital coststhe full cost pool is expected to be completed within five years.

During the three months ended March 31, 2019 and 2018, there were no expiring leasehold costs that were reclassified into proved property. The excluded Unproved properties are assessed for impairment at least annually. Subject to industry conditions, evaluationsDuring the three and nine months ended September 30, 2019, approximately $513,000 and $719,000 of most of these propertiesexpiring leasehold costs were reclassified into proved property. There were no expiring leasehold costs during the three and the inclusion of their costs in amortized capital costs is expected to be completed within five years.nine months ended September 30, 2018.

 

We capitalized overhead applicable to acquisition, development and exploration activities of approximately $68,000$167,000 and $71,000$540,000 for the three and nine months ended March 31,September 30, 2019, respectively. For the three and nine months ended September 30, 2018, we capitalized overhead applicable to acquisition, development, and exploration activities of approximately $106,000 and $306,000, respectively.

  

Depletion expense related to oil and gas properties for the three and nine months ended March 31,September 30, 2019 was approximately $3.7 million and $10.7 million, respectively. Depletion expense related to oil and gas properties for the three and nine months ended September 30, 2018 was approximately $3.5$2.4 million or $0.54 per Mcfe, and $1.3$5.6 million, or $0.82 per Mcfe, respectively.

Note 5 – Asset Retirement Obligation

Asset Retirement Obligations

The Company’s asset retirement obligations (“ARO”) relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an ARO is recorded in the period in which it is incurred and the cost of such liability is recorded as an increase in the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period and the capitalized cost is depleted on a units-of-production basis as part of the full cost pool. Revisions to estimated AROs result in adjustments to the related capitalized asset and corresponding liability.

The estimated ARO liability is based on estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or increased as a result of a reassessment of expected cash flows and assumptions inherent in the estimation of the liability. Upward revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells. AROs are valued utilizing Level 3 fair value measurement inputs.

15 

The following table is a reconciliation of the ARO for the three months ended March 31, 2019 and 2018:

(in thousands) Three Months Ended
March 31,
 
  2019  2018 
Balance at beginning of period $22,310  $7,737 
Accretion expense  394   141 
Additions during period  -   2,921 
   22,704   10,799 
Less: ARO recognized as a current liability  (3,392)  (767)
         
Balance at end of period $19,312  $10,032 

Note 6 – Investments in Affiliates

Carbon Appalachia

For the period April 3, 2017 (inception) through December 31, 2018, based on our 27.24% combined Class A, Class B and Class C interest (and our ability as of December 31, 2018 to earn up to an additional 14.7%) in Carbon Appalachia, our ability to appoint a member to the board of directors and our role of manager of Carbon Appalachia, we accounted for our investment in Carbon Appalachia under the equity method of accounting as we believed we exerted significant influence. We used the HLBV to determine our share of profits or losses in Carbon Appalachia and adjusted the carrying value of our investment accordingly. Our investment in Carbon Appalachia is represented by our Class A and C interests, which we acquired by contributing approximately $6.9 million in cash and unevaluated property. In the event of liquidation of Carbon Appalachia, available proceeds are first distributed to members holding Class C Units then to holders of Class A Units until their contributed capital is recovered with an internal rate of return of 10%. Any additional distributions would then be shared between holders of Class A, Class B and Class C Units.

On December 31, 2018, we acquired all of Old Ironsides’ Class A Units of Carbon Appalachia for approximately $58.1 million, subject to customary and standard closing adjustments. We paid $ 33.0 million in cash and issued the Old Ironsides Notes in the aggregate original principal amount of approximately $25.1 million to Old Ironsides.

Effective December 31, 2018, upon the closing of the OlE Membership Acquisition, we consolidate Carbon Appalachia in our consolidated financial statements.

Carbon California

 

For the period February 15, 2017 (inception) through January 31,three and nine months ended September 30, 2019 and 2018, based onwe did not recognize any ceiling test impairments as our 17.81% interest in Carbon California, our ability to appoint a member tofull cost pool did not exceed the board of directors and our role of manager of Carbon California, we accounted for our investment in Carbon California under the equity method of accounting as we believed we exerted significant influence. We used the Hypothetical Liquidation at Book Value Method (“HLBV”) to determine our share of profits or losses in Carbon California and adjusted the carrying value of our investment accordingly. The HLBV is a balance-sheet approach that calculates the amount each member of Carbon California would have received if Carbon California were liquidated at book value at the end of each measurement period. The change in the allocated amount to each member during the period represents the income or loss allocated to that member. In the event of liquidation of Carbon California, to the extent that Carbon California has net income, available proceeds are first distributed to members holding Class B Units and any remaining proceeds are then distributed to members holding Class A Units.ceiling limitations.

 

Effective February 1, 2018, upon the exercise of the California Warrant, we consolidate Carbon California in our consolidated financial statements.NOTE 5 – ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

Other Affiliates

At March 31,Accounts payable and accrued liabilities at September 30, 2019 and December 31, 2018 we retained interests in two equity method investments associated withconsist of the development and transportation of oil and gas.following:

(in thousands) September 30,
2019
  December 31,
2018
 
       
Accounts payable $5,787  $7,670 
Oil and gas revenue suspense  3,044   2,675 
Gathering and transportation payables  1,239   1,774 
Production taxes payable  2,838   1,860 
Accrued operating costs  681   3,155 
Accrued ad valorem taxes – current  5,501   3,474 
Accrued general and administrative expenses  2,285   3,111 
Accrued asset retirement obligation – current  5,035   3,099 
Accrued interest  1,455   955 
Accrued gas purchases  2,035   5,440 
Other liabilities  886   1,603 
         
Total accounts payable and accrued liabilities $30,786  $34,816 


NOTE 6 – ASSET RETIREMENT OBLIGATION

  

The Company’s asset retirement obligations (“Note 7 – Credit FacilitiesARO”) relate to future costs associated with the plugging and Notes Payableabandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an ARO is recorded in the period in which it is incurred, and the cost of such liability is recorded as an increase in the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period and the capitalized cost is depleted on a units-of-production basis as part of the full cost pool. Revisions to the estimated ARO liability result in adjustments to the related capitalized asset and corresponding liability.

The ARO liability is based on estimated economic lives, estimates of the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or adjusted as a result of a reassessment of expected cash flows and assumptions inherent in the estimation of the liability. Revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells. 

The following table is a reconciliation of ARO:

  

  Nine Months Ended
September 30,
 
(in thousands) 2019  2018 
Balance at beginning of period $22,310  $7,737 
Accretion expense  1,219   510 
Additions and revisions  294   3,590 
Balance at end of period $23,823  $11,837 
Less:  Current portion  (5,035)  (902)
Non-current portion $18,788  $10,935 

Carbon AppalachiaNOTE 7 – CREDIT FACILITIES AND NOTES PAYABLE

 

The table below summarizes the outstanding credit facilities and notes payable:

        

(in thousands) March 31, 2019 December 31, 2018  September 30,
2019
 December 31,
2018
 
2018 Credit Facility – revolver $70,150  $69,150  $71,150 $69,150 
2018 Credit Facility – term note  13,333   15,000  8,333 15,000 
Old Ironsides Notes  23,659   25,065  24,826 25,065 
Other debt  48   57   58  57 
Total principal  107,190   109,272 
Total debt 104,367 109,272 
Less: unamortized debt discount  (112)  (134)  (67)  (134)
Total credit facilities and notes payable $107,078  $109,138  104,300 109,138 
Current portion of credit facilities and notes payable  (8,266)  (11,910)
Non-current debt, net of current portion and unamortized debt discount $96,034 $97,228 

 

Carbon Appalachia

The current portion of the outstanding credit facilities and notes payable was approximately $9.9 million as of March 31, 2019 and $11.9 million as of December 31, 2018.

2018 Credit Facility

 

In connection with and concurrently with the closing of the OIE Membership Acquisition, the Company and its subsidiaries amended and restated our prior credit facilities forand entered into a new $500.0 million senior secured asset-based revolving credit facility maturing December 31, 2022 and a $15.0 million term loan which maturesmaturing in 2020 (the“2018 Credit Facility”). The 2018 Credit Facility includes a sublimit of $1.5 million for letters of credit. The borrowers under the 2018 Credit Facility are Carbon Appalachia Enterprises, LLC (“CAE”) and various other subsidiaries of the Company (including Nytis USA, together with CAE, the“Borrowers”). Under the 2018 Credit Facility, Carbon Energy Corporation is neither a borrower nor a guarantor. The initial borrowing base under the 2018 Credit Facility was $75.0 million and remained so as of March 31,September 30, 2019.

 

The 2018 Credit Facility is guaranteed by each existing and future direct or indirect subsidiary of the Borrowers and certain other subsidiaries of the Company (subject to various exceptions) and the obligations under the 2018 Credit Facility are secured by essentially all tangible, intangible and real property (subject to certain exclusions).

 

Interest accrues on borrowings under the 2018 Credit Facility at a rate per annum equal to either (i) the base rate plus an applicablea margin equal to 0.25% - 0.75% depending on the utilization percentage or (ii) the Adjusted LIBORLondon interbank offered rate (“LIBOR”) plus an applicablea margin equal to 2.75% - 3.75% depending on the utilization percentage, at the Borrowers’ option. The Borrowers are obligated to pay certain fees and expenses in connection with the 2018 Credit Facility, including a commitment fee for any unused amounts of 0.50% and an origination fee of 0.50%. Loans under the 2018 Credit Facility may be prepaid without premium or penalty.


The 2018 Credit Facility also provides for a $15.0 million term loan which bears interest at a rate of 6.25% and is payable in 18 equal monthly installments beginning February 1, 2019 with the last payment due on June 30,July 1, 2020.

 

The 2018 Credit Facility contains certain affirmative and negative covenants that, among other things, limit the Company’sBorrowers’ ability to (i) incur additional debt; (ii) incur additional liens; (iii) sell, transfer or dispose of assets; (iv) merge or consolidate, wind-up, dissolve or liquidate; (v) make dividends and distribution on, or repurchase of, equity; (vi) make certain investments; (vii) enter into certain transactions with their affiliates; (viii) enter in sale-leaseback transactions; (ix) make optional or voluntary payment of debt other than obligations under the 2018 Credit Facility; (x) change the nature of their business; (xi) change their fiscal year or make changes to the accounting treatment or reporting practices; (xii) amend their constituent documents; and (xiii) enter into certain hedging transactions.

 


The affirmative and negative covenants are subject to various exceptions, including certain basket amounts and acceptable transaction levels. In addition, the 2018 Credit Facility requires the Borrowers’ compliance, on a consolidated basis, with a maximum Net Debt (all debt of the Borrowing Parties minus all unencumbered cash and cash equivalents of the Borrowers not to exceed $3.0 million) / EBITDAX (as defined) ratio of 3.50 to 1.00 and a current ratio, as defined, minimum of 1.00 to 1.00, tested quarterly, commencing with the quarter ending March 31, 2019. We are in compliance with our financial covenants as of March 31,

In August 2019, and expectwe amended the 2018 Credit Facility, effective October 1, 2019, to be in compliance with these covenants throughoutrestrict the next twelve month period. We are currently engaged in discussions with LegacyTexas Bank to decrease the required hedging periodaging of our expected future production from 30 monthsaccounts payable to 24 months.90 days or less, maintain minimum liquidity of $3.0 million and require the sale of certain non-core assets by December 31, 2019. 

 

As of March 31,September 30, 2019, there was approximately $70.2$71.2 million in outstanding borrowings and $4.8$3.8 million of additional borrowing capacity under the 2018 Credit Facility. As of September 30, 2019, we were in compliance with our financial covenants.

 

The terms of the 2018 Credit Facility require us to enter into derivative contracts at fixed pricing for a certain percentage of our production. We are party to an International Swaps and Derivatives Association Master Agreements (“ISDA Master AgreementAgreements”) with BP Energy Company that establishes standard terms for the derivative contracts and an inter-creditor agreement with LegacyTexas Bank and BP Energy Company whereby any credit exposure related to the derivative contracts entered into by us and BP Energy Company is secured by the collateral and backed by the guarantees supporting the 2018 Credit Facility.

 

Fees paid in connection with the 2018 Credit Facility totaled approximately $779,000, of which $134,000 was associated with the term loan. The current portion of unamortized fees associated with the credit facility is included in prepaid expense, deposits and other current assets and the non-current portion is included in other non-current assets. The unamortized portion associated with the term loan was $112,000$67,000 as of March 31,September 30, 2019 and is directly offset against the loan in non-currentcurrent liabilities. As of March 31,September 30, 2019, we had unamortized deferred issuance costs of $604,000approximately $524,000 associated with the 2018 Credit Facility. During the three and nine months ended March 31,September 30, 2019, we amortized approximately $63,000 and $188,000, respectively, as interest expense associated with the 2018 Credit Facility.

 

Old Ironsides Notes

 

On December 31, 2018, as part of the OIE Membership Acquisition, we delivered unsecured, promissory notes in the aggregate original principal amount of approximately $25.1 million to Old Ironsides (the “Old Ironsides Notes”). The Old Ironsides Notes bear interest at 10%10.0% per annum and have a term of five years, the first three of which require interest-only payments at the end of each calendar quarter beginning with the quarter ending March 31, 2019. At the end of the three-year interest-only period, the then current outstanding principal balance and interest is to be paid in 24 equal monthly payments. The Old Ironsides Notes also require mandatory prepayments upon the occurrence of certain subsequent liquidity events. A mandatory, one-time principal reduction payment in the aggregate amount of $2.0 million was made to Old Ironsides on February 1, 2019. Subsequent to the closing of the OIE Membership Acquisition, Old Ironsides ceased to be a related party.

 

The interest payable under the Old Ironsides Notes can be paid-in-kind at the election of the Company. This provision allows the Company to increase the principal balance associated with the Old Ironsides Notes. This election creates a second tranche of principal, which bears interest at 12%12.0% per annum. On March 31,For the nine months ended September 30, 2019, the Company elected to pay-in-kindpayment-in-kind interest of approximately $594,000.$1.8 million.

 


Carbon California

  

The table below summarizes the outstanding notes payable – related party:

 

(in thousands) March 31, 2019  December 31, 2018 
Senior Revolving Notes, related party, due February 15, 2022 $38,500  $38,500 
Subordinated Notes, related party, due February 15, 2024  13,000   13,000 
   Total principal  51,500   51,500 
Less: Deferred notes costs  (255)  (235)
Less: unamortized debt discount  (1,281)  (1,346)
   Total notes payable – related party $49,964  $49,919 

(in thousands) September 30,
2019
  December 31,
2018
 
Senior Revolving Notes, related party, due February 15, 2022 $32,800  $38,500 
Subordinated Notes, related party, due February 15, 2024  13,000   13,000 
Total principal  45,800   51,500 
Less: Deferred notes costs  (185)  (235)
Less: unamortized debt discount  (1,150)  (1,346)
Total notes payable – related party $44,465  $49,919 

 

Senior Revolving Notes, Related Party

 

On February 15, 2017, Carbon California entered into a Note Purchase Agreement (the “Note Purchase Agreement) for the issuance and sale of Senior Secured Revolving Notes to Prudential with an initial revolving borrowing capacity of $25.0 million which mature on February 15, 2022 (the “Senior Revolving Notes”). Carbon Energy Corporation is not a guarantor of the Senior Revolving Notes. The closing of the Note Purchase Agreement on February 15, 2017 resulted in the sale and issuance by Carbon California of Senior Revolving Notes in the principal amount of $10.0 million. The maximum principal amount available under the Senior Revolving Notes is based upon the borrowing base attributable to Carbon California’s proved oil and gas reserves which is to be determined at least semi-annually. As of March 31,September 30, 2019, the borrowing base was $41.0$45.0 million, of which $38.5$32.8 million was outstanding.

 


Carbon California may elect to incur interest at either (i) 5.50% plus the London interbank offered rate (“LIBOR”) or (ii) 4.50% plus the Prime Rate (which is defined as the interest rate published daily by JPMorgan Chase Bank, N.A.). As of March 31,September 30, 2019, the effective borrowing rate for the Senior Revolving Notes was 7.80%7.60%. In addition, the Senior Revolving Notes include a commitment fee for any unused amounts at 0.50% as well as an annual administrative fee of $75,000, payable on February 15 each year.

 

The Senior Revolving Notes are secured by all the assets of Carbon California. The Senior Revolving Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated proved developed production at such time for year one, two and three at a rate of 75%, 65% and 50%, respectively. Carbon California may make principal payments in minimum installments of $500,000. Distributions to equity members are generally restricted.

 

Carbon California incurred fees directly associated with the issuance of the Senior Revolving Notes and amortizes these fees over the life of the Senior Revolving Notes. The current portion of these fees are included in prepaid expense and deposits and the long-term portion is included in other non-current assets for a combined value of approximately $939,000.$669,000. For the three and nine months ended March 31,September 30, 2019, Carbon California amortized fees of $74,000.$70,000 and $202,000, respectively.

 

Carbon California may at any time repay the Senior Revolving Notes, in whole or in part, without penalty. Carbon California must pay down Senior Revolving Notes or provide mortgages of additional oil and natural gas properties to the extent that outstanding loans and letters of credit exceed the borrowing base.   

 

Subordinated Notes, Related Party

 

On February 15, 2017, Carbon California entered into a Securities Purchase Agreement (the “Securities Purchase Agreement”) with Prudential Capital Energy Partners, L.P. for the issuance and sale of Subordinated Notes due February 15, 2024, bearing interest of 12%12.0% per annum (the “Subordinated Notes”). Carbon Energy Corporation is not a guarantor of the Subordinated Notes. The closing of the Securities Purchase Agreement on February 15, 2017 resulted in the sale and issuance by Carbon California of Subordinated Notes in the original principal amount of $10.0 million, all of which remains outstanding as of March 31,September 30, 2019.

  

Prudential received an additional 1,425 Class A Units, representing 5%5.0% of the total sharing percentage, for the issuance of the Subordinated Notes. Carbon California valued this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating the amount with the outstanding Subordinated Notes of $10.0 million. The Company then allocated the non-cash value of the units of approximately $1.3 million, which was recorded as a discount to the Subordinated Notes. As of March 31,September 30, 2019, Carbon California has an outstanding discount of approximately $869,000,$780,000, which is presented net of the Subordinated Notes within Credit facility-relatedNotes payable-related party on the unaudited condensed consolidated balance sheets. During the three and nine months ended March 31,September 30, 2019, Carbon California amortized $45,000 and $134,000, respectively, associated with the Subordinated Notes.

 

The Subordinated Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated production at such time for year one, two and three at a rate of 67.5%, 58.5% and 45%45.0%, respectively.

 

Prepayment of the Subordinated Notes is allowed at 100%, subject to a 3.0% fee of outstanding principal. Prepayment is not subject to a prepayment fee after February 17, 2020.Distributions to equity members are generally restricted.

 


2018 Subordinated Notes, Related Party

 

On May 1, 2018, Carbon California entered into an agreement with Prudential for the issuance and sale of $3.0 million in Subordinated Notessubordinated notes due February 15, 2024, bearing interest of 12%12.0% per annum (the “2018 Subordinated Notes”), of which $3.0 million remains outstanding as of March 31,September 30, 2019.

 

Prudential received 585 Class A Units, representing an approximate 2%2.0% additional sharing percentage, for the issuance of the Carbon California 2018 Subordinated Notes. Carbon California valued this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating the amount with the outstanding 2018 Subordinated Notes of $3.0 million. The Company then allocated the non-cash value of the units of approximately $490,000, which was recorded as a discount to the 2018 Subordinated Notes. As of March 31,September 30, 2019, Carbon California had an outstanding discount of $412,000$370,000 associated with these notes, which is presented net of the 2018 Subordinated Notes within Credit facilityNotes payable - related party on the unaudited condensed consolidated balance sheets. During the three and nine months ended March 31,September 30, 2019, Carbon California amortized $21,000 and $63,000, respectively, associated with the 2018 Subordinated Notes.

 

The 2018 Subordinated Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated production at such time for year one, two and three at a rate of 67.5%, 58.5% and 45%45.0%, respectively.

 

Prepayment of the 2018 Subordinated Notes is allowed at 100%, subject to a 3.0% fee of outstanding principal. Prepayment is not subject to a prepayment fee after February 17, 2020.Distributions to equity members are generally restricted.

 

Restrictions and Covenants

 

The Senior Revolving Notes, Subordinated Notes and 2018 Subordinated Notes contain affirmative and negative covenants that, among other things, limit Carbon California’s ability to (i) incur additional debt; (ii) incur additional liens; (iii) sell, transfer or dispose of assets; (iv) merge or consolidate, wind-up, dissolve or liquidate; (v) make dividends and distributions on, or repurchases of, equity; (vi) make certain investments; (vii) enter into certain transactions with our affiliates; (viii) enter into sales-leaseback transactions; (ix) make optional or voluntary payments of debt; (x) change the nature of our business; (xi) change our fiscal year to make changes to the accounting treatment or reporting practices; (xii) amend constituent documents; and (xiii) enter into certain hedging transactions.

 

The affirmative and negative covenants are subject to various exceptions, including basket amounts and acceptable transaction levels. In addition, (i) the Senior Revolving Notes require Carbon California’s compliance on a consolidated basis, with (A) a maximum Debt/EBITDA ratio of 4.0 to 1.0 stepping down to 3.5 to 1.0 starting with the quarter ending June 30, 2018, (B) a maximum Senior Revolving Notes/EBITDA ratio of 2.5 to 1.0, (C) a minimum interest coverage ratio of 3.02.0 to 1.0 and (D) a minimum current ratio of 1.0 to 1.0 and (ii) the Subordinated Notes require Carbon California’s compliance on a consolidated basis, with (A) a maximum Debt/EBITDA ratio of 4.54.75 to 1.0, stepping down to 4.0 to 1.0 starting with the quarter ending June 30, 2018, (B) a maximum Senior Revolving Notes/EBITDA ratio of 3.0 to 1.0, (C) a minimum interest coverage ratio of 2.51.6 to 1.0, (D) an asset coverage test whereby indebtedness may not exceed the product of 0.65 times Adjusted PV-10 set forth in the most recent reserve report, (E) maintenance of a minimum borrowing base of $10,000,000$10.0 million under the Senior Revolving Notes and (F) a minimum current ratio of 0.85 to 1.00.

 

Note 8 – Income Taxes

We recognize deferred income tax assets and liabilities for the estimated future tax consequences attributable to temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. We have net operating loss carryforwards available in certain jurisdictions to reduce future taxable income. Future tax benefits for net operating loss carryforwards are recognized to the extent that realization of these benefits is considered more likely than not. To the extent that available evidence raises doubt about the realization of a deferred income tax asset, a valuation allowance is established.

At March 31, 2019 the Company has established a full valuation allowance against the balance of net deferred tax assets.

Note 9 – Stockholders’ Equity

Authorized and Issued Capital Stock

Effective March 15, 2017 and pursuant to a reverse stock split approved by the shareholders and Board of Directors, each 20 shares of issued and outstanding common stock became one share of common stock and no fractional shares were issued. References to the number of shares and price per share give retroactive effect to the reverse stock split for all periods presented. On June 1, 2018, we amended our charter to increase the number of authorized shares of our common stock from 10.0 million to 35.0 million.

As of March 31,September 30, 2019, Carbon California was not in compliance with its Senior Revolving Notes/EBITDA ratio. We are currently negotiating an amendment to the covenant requirements with Prudential, a 46.08% owner of Carbon California, and are confident we will be successful in amending the covenants. While we have historically been successful in renegotiating covenant requirements with our lenders, there can be no assurance that we will be able to do so successfully in the future.

NOTE 8 – LEASES

On January 1, 2019, we had 35.0adopted Topic 842. Results for reporting periods beginning January 1, 2019 are presented in accordance with Topic 842, while prior period amounts are reported in accordance with Topic 840 – Leases. On January 1, 2019, we recognized approximately $7.7 million sharesin right-of-use assets and approximately $7.7 million in lease liabilities, representing the present value of common stock authorizedminimum payment obligations associated with compressor, vehicle, and office space operating leases with non-cancellable lease terms in excess of one year. We do not have any finance leases, nor are we the lessor in any leasing arrangements. We have elected certain practical expedients available under Topic 842 including those that permit us to (i) account for lease and non-lease components in our contracts as a single lease component for all asset classes; (ii) not evaluate existing and expired land easements; (iii) not apply the recognition requirements of Topic 842 to leases with a par valuelease term of $0.01 pertwelve months or less; and (iv) retain our existing lease assessment and classification. As such, there was no cumulative-effect adjustment to retained earnings required at January 1, 2019.

The lease amounts disclosed herein are presented on a gross basis. A portion of these costs may have been or will be billed to other working interest owners, and our net share of these costs, once paid, are included in lease operating expenses, pipeline operating expenses or general and administrative expenses, as applicable.

Our right-of-use assets and lease liabilities are recognized at their discounted present value on the balance sheet. All leases recognized on our unaudited condensed consolidated balance sheet are classified as operating leases, which approximately 7.8 million were issued and outstanding, and 1.0 million shares of preferred stock authorized with a par value of $0.01 per share. Duringinclude leases related to the first three months of 2019, the increaseasset classes reflected in the Company’s issued and outstanding common stock was a result of restricted stock and performance units that vested during the period.table below:

(in thousands) Right-of-Use Assets  Lease
Liability
 
Compressors $3,459  $3,459 
Corporate leases  2,225   2,239 
Vehicles  839   715 
Total $6,523  $6,413 

 


We recognize lease expense on a straight-line basis excluding short-term and variable lease payments which are recognized as incurred. Short-term lease cost represents payments for leases with a lease term of twelve months or less, excluding leases with a term of one month or less. Short-term leases include certain compressors and vehicles that have a non-cancellable lease term of less than one year.

Carbon Stock Incentive Plans

The following table summarizes the components of our gross operating lease costs incurred during the three and nine months ended September 30, 2019:

(in thousands) Three Months Ended
September 30,
2019
  Nine Months Ended
September 30,
2019
 
Operating lease cost $530  $1,598 
Short-term lease cost  156   473 
Total lease cost $686  $2,071 

  

We do not have twoany leases with an implicit interest rate that can be readily determined. As a result, we calculate collateralized incremental borrowing rates to use as discount rates. We utilize the benchmark rates defined in our credit facilities, and adjust for facility utilization and term considerations, to establish collateralized incremental borrowing rates. See Note 7 for additional information on our credit facilities.

Our weighted-average lease term and discount rate used are as follows:

September 30,
2019
Weighted-average lease term (years)3.82
Weighted-average discount rate6.36%

The following table summarizes supplemental cash flow information related to operating leases: 

(in thousands) Nine Months Ended
September 30,
2019
 
Cash paid for operating leases $1,707 
Right-of-use assets obtained in exchange for operating lease obligations $465 

Minimum future commitments by year for our long-term operating leases as of September 30, 2019 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet as follows:

(in thousands) Amount 
Remainder of 2019 $505 
2020  1,960 
2021  1,902 
2022  1,704 
2023  1,157 
Thereafter  10 
Total future minimum lease payments $7,238 
Less: imputed interest  (825)
Total lease liabilities $6,413 


NOTE 9 – REVENUE

The following tables present our disaggregated revenue by primary region within the United States and major product line:

For the three months ended September 30, 2019 and 2018 (in thousands):

  Appalachian and Illinois Basins  Ventura Basin  Total 
  Three Months Ended
September 30,
  Three Months Ended
September 30,
  Three Months Ended
September 30,
 
  2019  2018  2019  2018  2019  2018 
                   
Natural gas sales $11,962  $3,856  $1  $516  $11,963  $4,372 
Natural gas liquids sales  -   -   10   406   10   406 
Oil sales  1,327   3,327   7,722   8,523   9,049   11,850 
Transportation and handling  304   -   -   -   304   - 
Marketing gas sales  3,491   -   -   -   3,491   - 
Total $17,084  $7,183  $7,733  $9,445  $24,817  $16,628 

For the nine months ended September 30, 2019 and 2018 (in thousands):

  Appalachian and Illinois Basins  Ventura Basin  Total 
  Nine Months Ended
September 30,
  Nine Months Ended
September 30,
  Nine Months Ended
September 30,
 
  2019  2018  2019  2018  2019  2018 
                   
Natural gas sales $44,633  $10,776  $862  $1,059  $45,495  $11,835 
Natural gas liquids sales  -   -   451   1,119   451   1,119 
Oil sales  4,422   5,952   23,518   16,972   27,940   22,924 
Transportation and handling  1,361   -   -   -   1,361   - 
Marketing gas sales  11,656   -   -   -   11,656   - 
Total $62,072  $16,728  $24,831  $19,150  $86,903  $35,878 

We record revenue in the month production is delivered to the purchaser, but settlement statements may not be received until 30 to 90 days after the month of production. As such, we estimate the production delivered and the related pricing. The estimated revenue is recorded within Accounts receivable – Revenue on the unaudited condensed consolidated balance sheets. Any differences between our initial estimates and actuals are recorded in the month payment is received from the customer. These differences have not historically been material. Revenue recognized for the nine months ended September 30, 2019, that related to performance obligations satisfied in prior reporting periods was immaterial.

NOTE 10 – STOCK-BASED COMPENSATION PLANS

We have three stock plans, the Carbon 2011 Stock Incentive Plan, and the Carbon 2015 Stock Incentive Plan and the Carbon 2019 Long Term Incentive Plan (collectively the “Carbon Plans”). The Carbon Plans were2019 Long Term Incentive Plan was approved by our shareholders andthe Company’s stockholders in the aggregateMay 2019. The Carbon Plans provide for the issuance of approximately 1.11.6 million shares of common stock to our officers, directors, employees or consultants eligible to receive the awards under the Carbon Plans.

 

The Carbon Plans provide for the granting of incentive stock options, non-qualified stock options, restricted stock awards, performance awards and phantom stock awards, or a combination of the foregoing, to employees, officers, directors or consultants, provided that only employees may be granted incentive stock options and directors may only be granted restricted stock awards and phantom stock awards.

 

Restricted Stock

 

As of March 31,September 30, 2019, approximately 649,000748,000 shares of restricted stock have been granted under the terms of the Carbon Plans. Restricted stock awards for employees vest ratably over a three-year service period or cliff vest at the end of a three-year service period. For non-employee directors, the awards vest upon the earlier of a change in control of us or the date their membership on the Board of Directors is terminated other than for cause. During the threenine months ended March 31,September 30, 2019, approximately 40,000105,000 restricted stock units vested.

 

Compensation costs recognized for these restricted stock grants were approximately $179,000$204,000 and $607,000 for the three and nine months ended March 31, 2019. ForSeptember 30, 2019, respectively, and approximately $187,000 and $537,000 for the three and nine months ended March 31,September 30, 2018, we recognized compensation expense of approximately $158,000.respectively. As of March 31,September 30, 2019, there was approximately $1.2$1.5 million unrecognized compensation costs related to these restricted stock grants which we expect to be recognized over the next six6.5 years.

 


Restricted Performance Units

 

As of March 31,September 30, 2019, approximately 621,000699,000 shares of performance units have been granted under the terms of the Carbon Plans. Performance units represent a contractual right to receive one share of our common stock subject to the terms and conditions of the agreements, including the achievement of certain performance measures relative to a defined peer group or the growth of certain performance measures over a defined period of time as well as, in some cases, continued service requirements. During the nine months ended September 30, 2019, approximately 95,000 performance units vested.

 

We account for the performance units granted during 20152017 through 20182019 at their fair value determined at the date of grant, which were $8.00, $5.40, $7.20, $9.80 and $9.80$10.00 per share, respectively. The final measurement of compensation cost will be based on the number of performance units that ultimately vest. At March 31,September 30, 2019, we estimated that none of the performance units granted in 2017 and 2018through 2019 would vest, and, accordingly, no compensation cost has been recorded for these performance units. We estimated that it was probable that the performance units granted in 2015 and 2016 would vest and therefore compensation costs of approximately $43,000 and $135,000 related to these performance units were recognized for the threenine months ended March 31,September 30, 2019 and 2018, respectively. As of March 31,September 30, 2019, compensation costs related to the performance units granted in 2015 and 2016 have been fully recognized. As of March 31,September 30, 2019, if change in control and other performance provisions pursuant to the terms and conditions of these award agreements are met in full, the estimated unrecognized compensation cost related to theoutstanding performance units granted in 2012, 2017 and 2018 would be approximately $2.7$3.8 million.

 

Preferred StockNOTE 11 – EARNINGS (LOSS) PER COMMON SHARE

Basic earnings (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders for the period by the basic weighted average number of common shares outstanding during the period. Diluted earnings (loss) per common share includes potentially issuable shares consisting primarily of non-vested restricted stock and contingent restricted performance units, using the treasury stock method. In periods when we report a net loss, all common stock equivalents are excluded from the calculation of diluted weighted average shares outstanding because they would have an anti-dilutive effect, meaning the loss per share would be reduced.

For the three months ended September 30, 2019 and 2018, approximately 275,000 and 497,000 shares, respectively, and for the nine months ended September 30, 2019 and 2018, approximately 275,000 and 280,000 shares, respectively, were considered anti-dilutive and were excluded from the computation of diluted earnings per share.

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,
 
(in thousands, except per share amounts) 2019  2018  2019  2018 
             
Net income (loss) attributable to controlling interests before preferred shares $3,182  $(725) $5,311  $2,264 
Less: net income attributable to preferred shares – preferred return  75   -   225   - 
Net income (loss) attributable to common stockholders, basic  3,107   (725)  5,086   2,264 
Less: warrant derivative gain  -   -   -   (225)
Less: beneficial conversion feature  -   -   -   (1,125)
Less: deemed dividend for convertible preferred shares  -   (77)  -   (147)
Net income (loss) attributable to common stockholders, diluted  3,107   (802)  5,086   767 
                 
Weighted-average number of common shares outstanding, basic  7,839   7,701   7,780   7,466 
                 
Add dilutive effects of non-vested shares of restricted stock and restricted performance units  302   -   302   315 
                 
Weighted-average number of common shares outstanding, diluted  8,141   7,701   8,082   7,781 
                 
Net income (loss) per common share, basic $0.40  $(0.09) $0.65  $0.30 
Net income (loss) per common share, diluted $0.38  $(0.10) $0.63  $0.10 

17

Series B Convertible Preferred Stock - Related Party

 

In connection with the closing of the Seneca Acquisition, we raised $5.0 million through the issuance of 50,000 shares of Series B Convertible Preferred Stock, par value $0.01 per share (“Preferred Stock”) to Yorktown. The Preferred Stock converts into common stock at the election of the holder or will automatically convert into shares of our common stock upon completion of a qualifying equity financing event. The number of shares of common stock issuable upon conversion is dependent upon the price per share of common stock issued in connection with any such qualifying equity financing but has a floor conversion price equal to $8.00 per share. The conversion ratio at which the Preferred Stock will convert into common stock is equal to an amount per share of $100 plus all accrued but unpaid dividends payable in respect thereof divided by the greater of (i) $8.00 per share or (ii) the price that is 15%15.0% less than the lowest price per share of shares sold to the public in the next equity financing. Using the floor of $8.00 per share would yield 12.5 shares of common stock for every unit of Preferred Stock. The conversion price will be proportionately increased or decreased to reflect changes to the outstanding shares of common stock, such as the result of a combination, reclassification, subdivision, stock split, stock dividend or other similar transaction involving the common stock. Additionally, after the third anniversary of the issuance of the Preferred Stock, we have the option to redeem the shares for cash.


 

The Preferred Stock accrues cash dividends at a rate of six percent (6%)6.0% of the initial issue price of $100 per share per annum. The holders of the Preferred Stock are entitled to the same number of votes of common stock that such share of Preferred Stock would represent on an as converted basis. The holders of the Preferred Stock receive liquidation preference based on the initial issue price of $100 per share plus a preferred return over common stock holdersstockholders and the holders of any junior ranking stock. As of March 31, 2019, theThe preferred return was approximately $299,000.$449,000 as of September 30, 2019 and increased by $225,000 during the nine months ended September 30, 2019.

NOTE 12 – INCOME TAXES

 

We applyrecognize deferred income tax assets and liabilities for the guidanceestimated future tax consequences attributable to temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. We have net operating loss carryforwards available in ASC 480 “Distinguishing Liabilitiescertain jurisdictions to reduce future taxable income. Future tax benefits from Equity” when determiningnet operating loss carryforwards are recognized to the classification and measurementextent that realization of these benefits is considered more likely than not. To the Preferred Stock. The Preferred Stock does not feature any redemption rights withinextent that available evidence raises doubt about the holders’ control or conditional redemption features not within our control asrealization of March 31, 2019. Accordingly, the Preferred Stocka deferred income tax asset, a valuation allowance is presented as a component of consolidated stockholders’ equity.established.

 

We have evaluatedAt September 30, 2019, the Preferred Stock in accordance with ASC 815, “Derivatives and Hedging”, including considerationCompany has established a full valuation allowance against the balance of embedded derivatives requiring bifurcation. The issuance of the Preferred Stock could generate a beneficial conversion feature (“BCF”), which arises when a debt or equity security is issued with an embedded conversion option that is beneficial to the investor or in the money at inception because the conversion option has an effective strike price that is less than the market price of the underlying stock at the commitment date. Based on the conversion terms and the price at the commitment date, we determined that a BCF was required to be recorded related to the voluntary conversion option by the holder as of March 31, 2019. We recorded the BCF as a reduction of retained earnings and an increase to Additional Paid in Capital (“APIC”) of $1.1 million, which is based on the difference between the floor price of $8.00 and our stock price as of the commitment date multiplied by the number of shares to be issued. We are also required to evaluate a contingent BCF for the automatic conversion feature, but in accordance with ASC 470, “Debt”, we will not record the effect of the BCF until the contingency is resolved.

Note 10 – Revenue Recognition

Revenue from Contracts with Customers

The Company recognizes revenue in accordance with FASB ASC Topic 606 – Revenue Recognition (“ASC 606”).  Revenue is recognized when it satisfies a performance obligation by transferring control over a product to a customer. Revenue is measured based on the consideration we expect to receive in exchange for those products. Revenues from contracts with customers are recorded on the unaudited consolidated statements of operations based on the type of product being sold.

Performance Obligations and Significant Judgments

We sell oil and natural gas products in the United States through a single reportable segment. We primarily sell products within two regions of the United States: Appalachian Basin and Ventura Basin. We enter into contracts that generally include one type of distinct product in variable quantities and priced based on a specific index related to the type of product. Most of our contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions.

The oil and natural gas is typically sold in an unprocessed state to third party purchasers. We recognize revenue based on the net proceeds received from the purchaser when control of the oil or natural gas passes to the purchaser. For oil sales, control is typically transferred to the purchaser upon receipt at the wellhead or a contractually agreed upon delivery point. Under our natural gas contracts with purchasers, control transfers upon delivery at the wellhead or the inlet of the purchaser’s system. For our other natural gas contracts, control transfers upon delivery to the inlet or to a contractually agreed upon delivery point.deferred tax assets.


Transfer of control drives the presentation of transportation and gathering costs within the accompanying unaudited consolidated statements of operations. Transportation and gathering costs incurred prior to control transfer are recorded within the transportation and gathering expense line item on the accompanying unaudited consolidated statements of operations, while transportation and gathering costs incurred subsequent to control transfer are recognized as a reduction to the related revenue.

A portion of our product sales are short-term in nature. For those contracts, we use the practical expedient in ASC 606 exempting us from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606 which states we are not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to an unsatisfied performance obligation. Under these sales contracts, each unit of product represents a separate performance obligation; therefore, future volumes are unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. We have no unsatisfied performance obligations at the end of each reporting period.

We do not believe that significant judgments are required with respect to the determination of the transaction price, including any variable consideration identified. There is a low level of uncertainty due to the precision of measurement and use of index-based pricing with predictable differentials. Additionally, any variable consideration identified is not constrained.

Disaggregation of Revenues

In the following tables, revenue for the three months ended March 31, 2019, is disaggregated by primary region within the United States and major product line. As noted above, we operate as one reportable segment.

For the three months ended March 31, 2019:

(in thousands)         
Type Appalachian Basin  Ventura Basin  Total 
Natural gas sales $18,792  $524  $19,316 
Natural gas liquids sales  -   247   247 
Oil sales  1,537   7,452   8,989 
Transportation and handling  734   -   734 
Marketing gas sales  4,944   -   4,944 
Total revenue $26,007  $8,223  $34,230 

Contract Balances

Under our product sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not typically give rise to contract assets or liabilities under ASC 606.

Prior Period Performance Obligations

We record revenue in the month production is delivered to the purchaser, but settlement statements may not be received until 30 to 90 days after the month of production. As such, we estimate the production delivered and the related pricing. Any differences between our initial estimates and actuals are recorded in the month payment is received from the customer. These differences have not historically been material. For the three months ended March 31, 2019, revenue recognized in the reporting period related to prior period performance obligations is immaterial.

The estimated revenue is recorded within Accounts receivable – Revenue on the unaudited consolidated balance sheets.


Note 11 – Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities at March 31, 2019 and December 31, 2018 consist of the following:

(in thousands) March 31,
2019
  December 31,
2018
 
       
Accounts payable $6,064  $7,670 
Oil and gas revenue suspense  2,766   2,675 
Gathering and transportation payables  1,228   1,774 
Production taxes payable  2,411   1,860 
Accrued operating costs  2,431   3,155 
Accrued ad valorem taxes – current  3,731   3,474 
Accrued general and administrative expenses  2,217   3,111 
Accrued asset retirement obligation – current  3,392   3,099 
Accrued interest  1,543   955 
Accrued gas purchases  2,959   5,440 
Other liabilities  1,278   1,603 
         
Total accounts payable and accrued liabilities $30,020  $34,816 

Note 12 – Fair Value Measurements

 

Authoritative guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of us. Unobservable inputs are inputs that reflect our assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

Level 1:Quoted prices are available in active markets for identical assets or liabilities;

Level 2:Quoted prices in active markets for similar assets or liabilities that are observable for the asset or liability; or

Level 3:Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our policy is to recognize transfers in and/or out of fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. We have consistently applied the valuation techniques discussed below for all periods presented.NOTE 13 – FAIR VALUE MEASUREMENTS

 

The following table presents our financial assets and liabilities that were accounted for at fair value on a recurring basis by level within the fair value hierarchy:level:

 

(in thousands) Fair Value Measurements Using 
  Level 1  Level 2  Level 3  Total 
March 31, 2019            
Assets:            
Commodity derivatives $     -  $147  $     -  $147 
Liabilities:                
Commodity derivatives $-  $1,975  $-  $1,975 
                 
December 31, 2018                
Asset:                
Commodity derivatives $-  $7,022  $-  $7,022 


(in thousands) Fair Value Measurements Using 
  Level 1  Level 2  Level 3  Total 
September 30, 2019            
Assets:            
Commodity derivatives $-  $9,794  $-  $9,794 
                 
December 31, 2018                
Assets:                
Commodity derivatives $-  $7,022  $-  $7,022 

  

Commodity Derivative

 

As of March 31,September 30, 2019, our commodity derivative financial instruments are comprised of natural gas and oil swaps and costless collars. The fair values of these agreements are determined under an income valuation technique. The valuation model requires a variety of inputs, including contractual terms, published forward prices, volatilities for options and discount rates, as appropriate. Our estimates of fair value of derivatives include consideration of the counterparty’s credit worthiness, our credit worthiness and the time value of money. The consideration of these factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view. All the significant inputs are observable, either directly or indirectly; therefore, our derivative instruments are included within the Level 2 fair value hierarchy. The counterparty for all our outstanding commodity derivative financial instruments as of March 31, 2019, is BP Energy Company.

 


Assets and Liabilities Measured and Recorded at Fair Value on a Non-Recurring Basis

 

The fair value of each of the following assets and liabilities measured and recorded at fair value on a non-recurring basis are based on unobservable pricing inputs and therefore, are included within the Level 3 fair value hierarchy.

 

The fair value of the non-controlling interestinterests in the partnerships we are required to consolidate was determined based on the net discounted cash flows of the proved developed producing properties attributable to the non-controlling interests in these partnerships.

 

We assume, at times, certain firm transportation contracts as part of our acquisitions of oil and natural gas properties. The fair value of the firm transportation contract obligations was determined based upon the contractual obligations assumed by us and discounted based upon our effective borrowing rate. These contractual obligations are reduced on a monthly basis as we pay these firm transportation obligations in the future.

 

The fair value measurements associated with the assets acquired and liabilities assumed in the business combination for the OIE Membership Acquisition of Carbon Appalachia are outlined within Note 3.

 

Debt Discount

 

The fair value of the debt discount from the 1,425 and 585 additional Class A Units issued in connection with the Subordinated Notes and 2018 Subordinated Notes was $1.3 million and $490,000, respectively. The debt discount was a Level 3 fair value assessment and was based on the relative fair value of Class A Units. Class A Units were issued contemporaneously at $1,000 per Class A Unit.

 

Asset Retirement Obligation

 

The fair value of our asset retirement obligation liability is recorded in the period in which it is incurred or assumed by taking into account the cost of abandoning oil and gas wells ranging from $20,000 to $45,000, which is based on our historical experience and industry expectations for similar work; the estimated timing of reclamation ranging from one to 75 years based on estimates from reserve engineers; an inflation rate between 1.52% to 2.79%; and a credit adjusted risk-free rate between 3.28% to 8.27%, which takes into account our credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs (see Note 3).inputs. During the three month periodnine months ended March 31,September 30, 2019, we did not record any additions to asset retirement obligations. We use the income valuation technique to estimate the fair value of asset retirement obligations using the amounts and timing of expected future dismantlement costs, credit-adjusted risk-free rates and time value of money.

 


Class B Units

 

We received Class B units from Carbon California and Carbon Appalachia as part of the entry into the Carbon California LLC Agreement and Carbon Appalachia LLC Agreement, respectively. We estimated the fair value of the Class B units, in each case, by utilizing the assistance of third-party valuation specialists. The fair values were based upon enterprise values derived from inputs including estimated future production rates, future commodity prices including price differentials as of the dates of closing, future operating and development costs and comparable market participants.

 

Note 13NOTE 14Commodity DerivativesCOMMODITY DERIVATIVES

 

We historically use commodity-based derivative contracts to manage exposures to commodity price on a portion of our oil and natural gas production. We do not hold or issue derivative financial instruments for speculative or trading purposes. We also have entered into, on occasion, oil and natural gas physical delivery contracts to effectively provide commodity price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. These contracts are not recorded at fair value in the unaudited condensed consolidated financial statements.

 

Pursuant to the terms of our credit facilities with LegacyTexas Bank and Prudential, weWe have entered into swap and costless collar derivative agreements to hedge a portion of our oil and natural gas production through 2021.2022. As of March 31,September 30, 2019, these derivative agreements consisted of the following:

 

 Natural Gas Swaps Natural Gas Collars  Natural Gas Swaps* Natural Gas Collars* 
   Weighted
Average
   Weighted
Average Price
    Weighted
Average
   Weighted
Average Price
 
Year MMBtu Price (a) MMBtu Range (a)  MMBtu Price (a) MMBtu Range (a) 
                  
2019 11,762,000, $2.82 374,000 $2.60 – $3.03  3,735,000 $2.83 92,000 $2.60 – $3.03 
2020 12,433,000 $2.73 1,018,000 $2.50 – $2.70  12,433,000 $2.73 1,128,0000 $2.40 – $2.75 
2021 6,448,000 $2.58 - $-  6,448,000 $2.58 65,000 $2.40 – $2.75 

 

 Oil Swaps Oil Collars  Oil Swaps* Oil Collars* 
Year WTI Bbl Weighted Average  Price (b) Brent Bbl Weighted Average Price (c) WTI Bbl Weighted  Average Price (b) Brent Bbl Weighted  Average Price (c)  WTI Bbl Weighted Average Price (b) Brent Bbl Weighted Average Price (c) WTI Bbl Weighted Average Price (b) Brent Bbl Weighted Average Price (c) 
2019 180,775 $53.46 121,079 $66.93 - - 29,800 $47.00 - $75.00  70,835 $53.36 54,091 $65.45 5,200 $47.50 - $57.35 16,400 $47.00 - $75.00 
2020 121,147 $55.37 151,982 $66.03 18,000 $47.00 - $60.15 37,400 $47.00 - $75.00  121,147 $55.37 162,482 $65.67 28,200 $47.00 - $60.15 57,900 $47.00 - $75.00 
2021 - $- 86,341 $67.12 30,000 $47.00 - $60.15 98,000 $47.00 - $75.00  - $- 86,341 $67.12 49,500 $47.00 - $60.15 130,800 $47.00 - $75.00 
2022 - $- - $- - $- 90,800 $50.00 - $61.00 

  

*Includes 100% of Carbon California’s outstanding derivative hedges at March 31,September 30, 2019, and not our proportionate share.
(a)NYMEX Henry Hub Natural Gas futures contract for the respective period.
(b)NYMEX Light Sweet Crude West Texas Intermediate futures contract for the respective period.
(c)Brent future contracts for the respective period.

 

For our swap instruments, we receive a fixed price for the hedged commodity and pay a floating price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty. Costless collars are designed to establish floor and ceiling prices on anticipated future oil and gas production. The ceiling establishes a maximum price that the Company will receive for the volumes under contract, while the floor establishes a minimum price.

 

The following table summarizes the fair value of the derivatives recorded in the unaudited condensed consolidated balance sheets.

These derivative instruments are not designated as cash flow hedging instruments for accounting purposes:

 

(in thousands) March 31,
2019
  December 31,
2018
 
Commodity derivative contracts:      
Commodity derivative asset $-  $3,517 
Commodity derivative asset – non-current $147  $3,505 
         
Commodity derivative liability $1,657  $- 
Commodity derivative liability – non-current $318  $- 


(in thousands) September 30,
2019
  December 31,
2018
 
Commodity derivative contracts:      
Commodity derivative asset $6,722  $3,517 
Commodity derivative asset – non-current $3,072  $3,505 

 

The table below summarizes the commodity settlements and unrealized gains and losses related to the Company’s derivative instruments for the three and nine months ended March 31,September 30, 2019 and 2018. These commodity derivative settlements and unrealized gains and losses are recorded and included in commodity derivative income or loss in the accompanying unaudited condensed consolidated statements of operations. 

 

  Three Months Ended
March 31,
 
(in thousands) 2019  2018 
       
Commodity derivative contracts:      
Settlement losses $(456) $(377)
Unrealized losses  (8,850)  (249)
         
Total settlement and unrealized losses, net $(9,306) $(626)
  Three Months Ended
September 30,
  Nine Months Ended
September 30,
 
(in thousands) 2019  2018  2019  2018 
             
Commodity derivative contracts:            
Settlement gains (losses) $2,429  $(1,108) $2,198  $(2,169)
Unrealized gains (losses)  3,166   (2,794)  2,771   (8,381)
                 
Total settlement and unrealized gains (losses), net $5,595  $(3,902) $4,969  $(10,550)

  

Commodity derivative settlement gains and losses are included in cash flows from operating activities in our unaudited condensed consolidated statements of cash flows.

The counterparty in all of our derivative instruments is BP Energy Company. We have entered into ISDA Master Agreements with BP Energy Company that establishes standard terms for the derivative contracts and inter-creditor agreements with LegacyTexas Bank, Prudential and BP Energy Company whereby any credit exposure related to the derivative contracts entered into by us and BP Energy Company is secured by the collateral and backed by the guarantees supporting the credit facilities.

 

We net our derivative instrument fair value amounts executed with BP Energy Company pursuant to ISDA master agreements,Master Agreements, which providesprovide for the net settlement over the term of the contracts and in the event of default or termination of the contracts. The following table summarizes the locationeffect of netting arrangements for recognized derivative assets and fair value amounts of all derivative instrumentsliabilities that are subject to master netting arrangements or similar arrangements in the unaudited consolidated balance sheet, as well as the gross recognized derivative assets, liabilities and amounts offset in the unauditedcondensed consolidated balance sheet as of March 31,September 30, 2019.

 

     Net      Net 
 Gross   Recognized  Gross   Recognized 
 Recognized Gross Fair Value  Recognized Gross Fair Value 
 Assets/ Amounts Assets/  Assets/ Amounts Assets/ 
Balance Sheet Classification (in thousands) Liabilities Offset Liabilities  Liabilities Offset Liabilities 
              
Commodity derivative assets:              
Commodity derivative asset $1,063  $(1,063) $-  $7,236  $(514) $6,722 
Commodity derivative asset – non-current  2,049   (1,902)  147   4,275   (1,203)  3,072 
Total derivative assets $3,112  $(2,965) $147  $11,511  $(1,717) $9,794 
                        
Commodity derivative liabilities:                        
Commodity derivative liability $2,720  $(1,063) $(1,657) $(514) $514  $- 
Commodity derivative liability – non-current  2,220   (1,902)  (318)  (1,203)  1,203   - 
Total derivative liabilities $4,940  $(2,965) $(1,975) $(1,717) $1,717  $- 

 

Due to the volatility of oil and natural gas prices, the estimated fair value of our derivatives are subject to fluctuations from period to period.

 


Note 14 – Leases

On January 1, 2019, we adopted ASC 842. Results for reporting periods beginning January 1, 2019 are presented in accordance with ASC 842, while prior period amounts are reported in accordance with FASB ASC Topic 840 – Leases. On January 1, 2019, we recognized approximately $7.7 million in right-of-use assets and approximately $7.7 million in lease liabilities, representing the present value of minimum payment obligations associated with compressor, vehicle, and office space operating leases with non-cancellable lease terms in excess of one year. We do not have any finance leases, nor are we the lessor in any leasing arrangements. We have elected certain practical expedients available under ASC 842 including those that permit us to (i) account for lease and non-lease components in our contracts as a single lease component for all asset classes; (ii) not evaluate existing and expired land easements; (iii) not apply the recognition requirements of ASC 842 to leases with a lease term of twelve months or less; and (iv) retain our existing lease assessment and classification. As such, there was no cumulative-effect adjustment to retained earnings required at January 1, 2019. Additionally, the Company has elected the short-term lease recognition exemption for all classes of underlying assets and therefore, leases with a term of one year or less will not be recognized on the unaudited consolidated balance sheet. 

The lease amounts disclosed herein are presented on a gross basis. A portion of these costs may have been or will be billed to other working interest owners, and our net share of these costs, once paid, are included in lease operating expenses, pipeline operating expenses or general and administrative expenses, as applicable.

During the three months ended March 31, 2019, we did not acquire any right-of-use assets or incur any lease liabilities. Our right-of-use assets and lease liabilities are recognized at their discounted present value on the balance sheet at $7.3 million as of March 31, 2019. All leases recognized on our unaudited consolidated balance sheet are classified as operating leases, which include leases related to the asset classes reflected in the table below:

(in thousands) Right-of-Use Assets  Lease
Liability
 
Compressors $4,178  $4,178 
Corporate leases  2,433   2,438 
Vehicles  645   645 
Total $7,256  $7,261 

We recognize lease expense on a straight-line basis excluding short-term and variable lease payments which are recognized as incurred. Short-term lease cost represents payments for leases with a lease term of one year or less, excluding leases with a term of one month or less. Short-term leases include certain compressors and vehicles that have a non-cancellable lease term of less than one year.

The following table summarizes the components of our gross operating lease costs incurred during the three months ended March 31, 2019:

(in thousands) Three Months Ended March 31,
2019
 
Operating lease cost $531 
Short-term lease cost  161 
Total lease cost $692 

We do not have any leases with an implicit interest rate that can be readily determined. As a result, we calculate collateralized incremental borrowing rates to use as discount rates. We utilize the benchmark rates defined in our credit facilities, and adjust for facility utilization and term considerations, to establish collateralized incremental borrowing rates. Refer to Note 7 for additional information on our credit facilities.

Our weighted-average lease term and discount rate used are as follows:

(in thousands)Three Months Ended March 31,
2019
Weighted-average lease term (years)4.3
Weighted-average discount rate6.34%

The following table summarizes supplemental cash flow information related to leases:

Cash paid for amounts included in measurement of lease liabilities (in thousands) Three Months Ended March 31,
2019
 
Operating cash flows for operating leases $526 

Minimum future commitments by year for our long-term operating leases as of March 31, 2019 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet as follows:

(in thousands) Amount 
Remainder of 2019 $1,535 
2020  1,946 
2021  1,889 
2022  1,718 
2023  1,222 
Thereafter  11 
Total lease payments $8,321 
Less: imputed interest  (1,060)
Total lease liability $7,261 

NoteNOTE 15 – Commitments and ContingenciesCOMMITMENTS AND CONTINGENCIES

Delivery Commitments

 

We have entered into employment agreements with certain of our executives and officers. The term of the agreements generally ranges from one to two years and provides for renewal provisions in one-year increments thereafter. The agreements provide for, among other items, severance and continuation of benefit payments upon termination of employment or certain change of control events.


We have entered into non-current firm transportation contracts to ensure the transport for certain of our gas production to purchasers. Firm transportation volumes and the related demand charges for the remaining term of these contracts at March 31,as of September 30, 2019 are summarized in the table below.

 

Period Dekatherms per day Demand Charges  Dekatherms
per day
 Demand Charges 
Apr 2019 – Mar 2020 58,871 $0.20 - 0.62 
Oct 2019 – Mar 2020 58,871 $0.20 - 0.62 
Apr 2020 – May 2020 57,791 $0.20 - 0.56  57,791 $0.20 - 0.56 
Jun 2020 – Oct 2020 56,641 $0.20 - 0.56  56,641 $0.20 - 0.56 
Nov 2020 – Aug 2022 50,341 $0.20 - 0.56  50,341 $0.20 - 0.56 
Sep 2022 – May 2027 30,990 $0.20 - 0.21  30,990 $0.20 - 0.21 

Jun 2027 – May 2036

 1,000 $0.20  1,000 $0.20 

 

As of March 31,September 30, 2019, the remaining commitment related to the firm transportation contracts assumed in the EXCO Acquisition in October 2016 and the OIE Membership Acquisition is $17.8$15.6 million and reflected in the Company’s unaudited condensed consolidated balance sheet. The fair values of these firm transportation obligations were determined based upon the contractual obligations assumed by the Company and discounted based upon the Company’s effective borrowing rate. These contractual obligations are being reduced monthly as the Company pays these firm transportation obligations in the future.obligations.

 

Natural gas processing agreement

 

We have entered into an initial five-year gas processing agreement.agreement expiring in 2022. We have an option to extend the term of the agreement by another five years. The related demand charges for volume commitments over the remaining term of the agreement at March 31, 2019 are approximately $1.8 million per year. We will pay a processing fee of $2.50 per MCFMcf for the term of the agreement, with a minimum annual volume commitment of 720,000 MCF.Mcf.

 

Capital Commitments

 

As of March 31,September 30, 2019, we had no capital commitments associated with Carbon California. commitments.

NoteNOTE 16 – Supplemental Cash Flow DisclosureSUPPLEMENTAL CASH FLOW DISCLOSURE

 

Supplemental cash flow disclosures for the threenine months ended March 31,September 30, 2019 and 2018 are presented below:

 

  Three Months Ended
March 31,
 
(in thousands) 2019  2018 
       
Cash paid during the period for:      
Interest $1,875  $336 
Non-cash transactions:        
Accounts payable and accrued liabilities $82  $(71)
Non-cash acquisition of Carbon California interests $-  $(18,906)
Carbon California Acquisition on February 1, 2018 $-  $17,114 
Exercise of warrant derivative $-  $(1,792)
Old Ironsides Notes interest paid-in-kind $594   - 

Note 17 – Subsequent Events

We evaluated activities from March 31, 2019, to the date these financial statements were available for issuance. We believe there are no subsequent events requiring recognition or disclosure.

  Nine Months Ended
September 30,
 
(in thousands) 2019  2018 
       
Cash paid during the period for:      
Interest $6,897  $2,770 
Non-cash transactions:        
Capital expenditures included in accounts payable and accrued liabilities $(1,195) $(491)
Adjustments to OIE Membership Acquisition purchase price $1,317  $- 
Increase in asset retirement obligations $-  $3,590 
Non-cash acquisition of Carbon California interests $-  $(18,906)
Carbon California Acquisition on February 1, 2018 $-  $17,114 
Obligations assumed with Seneca asset purchase $-  $330 
Accrued dividend for convertible preferred stock $-  $148 
Beneficial conversion feature for convertible preferred stock $-  $1,125 
Exercise of warrant derivative $-  $(1,792)

ITEM 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

The following discussion includes forward-looking statements about our business, financial condition and results of operations, including discussions about management’s expectations for our business. These statements represent projections, beliefs and expectations based on current circumstances and conditions, and you should not construe these statements either as assurances of performance or as promises of a given course of action. Instead, various known and unknown factors may cause our actual performance and management’s actions to vary, and the results of these variances may be both material and adverse. A description of material factors known to us that may cause our results to vary or may cause management to deviate from its current plans and expectations, is set forth under “Risk Factors.” The following discussion should be read in conjunction with “Forward-Looking Statements,” “Risk Factors” and our unaudited condensed consolidated financial statements, including the notes thereto appearing elsewhere in this Quarterly Report on Form 10-Q and the information included or incorporated by reference in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2018 (the “2018 Annual Report on Form 10-K.10-K”).

 

General Overview

 

Carbon is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of oil, natural gas and natural gas liquids properties located in the United States. We currently develop and operate oil and gas properties in the Appalachian Basin in Kentucky, Ohio, Tennessee, Virginia and West Virginia, in the Illinois Basin in Illinois and Indiana, and in the Ventura Basin in California through our majority-owned subsidiaries. We own 100% of the outstanding interests of Carbon Appalachia and Nytis Exploration (USA) Inc., a Delaware corporation (“Nytis USA”), which in turn owns 98.1%98.11% of Nytis Exploration Company LLC, a Delaware limited liability company (“Nytis LLC”).LLC. Nytis LLC holds interests in our operating subsidiaries, which include 46 consolidated partnerships and 18 non-consolidated partnerships. We own 53.92% of Carbon California, which consolidateswe consolidate as a majority-owned subsidiary. We focus on conventional and unconventional reservoirs, including shale, tight sands and coalbed methane. Our executive offices are in Denver, Colorado and we maintain offices in Lexington, Kentucky, and Santa Paula, California from which we conduct our oil and gas operations.

 

At March 31,September 30, 2019, our proved developed reserves were comprised of 22% oil and natural gas liquids (“NGL”) and 78% natural gas. Our current capital expenditure program is focused on the acquisition and development of oil and natural gas properties in areas where we currently operate. We believe that our asset and lease position, combined with our low operating expense structure and technical expertise, provides us with a portfolio of opportunities for the development of our oil and natural gas properties. Our growth plan is centered on the following activities:

 

 

Acquire and develop oil and gas producing properties that deliver attractive risk adjusted rates of return, provide for field development projects, and complement our existing asset base; and

   
 

Develop, optimize and maintain a portfolio of low risk, long-lived oil and natural gas properties that provide stable cash flows and attractive risk adjusted rates of return.

Factors That Significantly Affect Our Financial Condition and Results of Operations

 

Our revenue, profitability and future growth rate depend on many factors which are beyond our control, including but not limited to, economic, political and regulatory developments and competition from other industry participants. Our financial results are sensitive to fluctuations in oil and natural gas prices. Oil and gas prices historically have been volatile and may fluctuate widely in the future due to a variety of factors, including but not limited to, prevailing economic conditions, supply and demand of hydrocarbons in the marketplace, actions by speculators, and geopolitical events such as wars or natural disasters. The following table highlights the quarterly average of NYMEX oil and natural gas prices for the last eight calendar quarters:

 

 2017 2018 2019  2017 2018 2019 
 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1  Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 
                                  
Oil (Bbl) $48.29 $48.19 $55.39 $62.89 $67.90 $69.50 $58.83 $54.85  $55.39  $62.89  $67.90  $69.50  $58.83  $54.90  $59.96  $56.43 
Natural Gas (MMBtu) $3.09 $2.89 $2.87 $3.13 $2.77 $2.88 $3.62 $2.99  $2.87  $3.13  $2.77  $2.88  $3.62  $3.00  $2.57  $2.38 

 

Low oil, NGL and natural gas prices may decrease our revenues, may reduce the amount of oil, NGL and natural gas that we can produce economically and potentially lower our oil and natural gas reserves. Our estimated proved reserves may decrease if the economic life of underlying producing wells areis shortened as a result of lower oil, NGL and natural gas prices. A substantial or extended decline in oil, NGL or natural gas prices may result in future impairments of our proved reserves and may materially and adversely affect our future business, financial condition, cash flows, results of operations or liquidity. Lower oil, NGL and natural gas prices may also reduce the amount of borrowing base under our bank credit facilities, which are determined at the discretion of our lenderlenders and may make it more difficult to comply with the covenants and other restrictions under our bank credit facilities.

 


We use the full cost method of accounting for our oil and gas properties and performsperform a ceiling test quarterly. The ceiling calculation utilizes a rolling 12 month12-month average commodity price. We did not recognize an impairment for the three and nine months ended March 31,September 30, 2019 and 2018.

 

Future write downs or impairments, if any, are difficult to predict and will depend not only on commodity prices, but also other factors that include, but are not limited to, incremental proved reserves that may be added each period, revisions to previous reserve estimates, capital expenditures and operating costs. There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in subsequent periods.

 

Impairment charges do not affect cash flows from operating activities but do adversely affect net income and stockholders’ equity. An extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, cash flows and liquidity.

 

We use commodity derivative instruments, such as swaps and costless collars, to manage and reduce price volatility and other market risks associated with our production. These arrangements are structured to reduce our exposure to commodity price decreases, but they can also limit the benefit we might otherwise receive from commodity price increases.

 

Future property 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 credit facilities, sales of properties or the issuance of additional equity or debt.

 

Operational Highlights

 

During 2017 and 2018 and the first quarterthree quarters of 2019, we concentrated our efforts on the acquisition and development of producing properties through the acquisitions consummated by Carbon California and Carbon Appalachia. WeIn December 2018, we completed the purchase of Old Ironsides’ interests in Carbon Appalachia, resulting in ownership of 100% of Carbon Appalachia.Appalachia (“OIE Membership Acquisition”). Our field development activities have consisted principally of oil-related remediation and return to production and recompletion projects in California. Since closing these acquisitions, we have focused on operating efficiencies and reduction of operating expenses, optimization of natural gas gathering and compression facilities, greater flexibility in moving our production to markets with more favorable pricing, and the identification of development project opportunities to provide more efficient and lower cost operations. During the third quarter of 2019, we commenced a three-well drilling program in California that we expect to complete by the end of 2019.

 

As of March 31,September 30, 2019, we owned working interests in approximately 8,8007,800 gross wells (7,100(7,500 net), royalty interests located primarily in California, Illinois, Indiana, Kentucky, Ohio, Tennessee, Virginia, and West Virginia and hadheld leasehold positions in approximately 336,000336,400 net developed acres and approximately 1,317,9001,274,000 net undeveloped acres. Approximately 68%70% of the undeveloped acreage is held by production and of the remaining undeveloped acreage, approximately 80%87% have lease terms of greater than five years remaining in the primary term or contractual extension periods.

 

Our oil and natural gas assets contain an inventory of field development projects which may provide growth opportunities when oil and natural gas commodity prices warrant capital investment to develop the properties.

 

Recent Developments and Factors Affecting Comparability

 

We are continually evaluating producing property and land acquisition opportunities in our operating areaareas which would expand our operations and provide attractive risk adjusted rates of return on invested capital. The drilling of additional oil and natural gas wells is contingent on our expectation of future oil and natural gas prices.

  

Investment in Affiliates

Carbon Appalachia

 

Carbon Appalachia was formed in 2016 by us, Yorktown and Old Ironsides to acquire producing assets in the Appalachian Basin in Kentucky, Tennessee, Virginia and West Virginia. Carbon Appalachia was accounted for as an equity method investment from April 2017 until December 31, 2018, upon the closing of the OIE Membership Acquisition which required us to consolidate Carbon Appalachia for financial reporting purposes.


 

In December 2018, we completed the acquisition of all of the Class A Units of Carbon Appalachia owned by Old Ironsides for a purchase price of $58.1 million, subject to customary and standard purchase price adjustments (“OIE Membership Acquisition”).adjustments. As a result of the OIE Membership Acquisition, we now hold all of the issued and outstanding ownership interests of Carbon Appalachia, along with its direct and indirect subsidiaries (Carbon Appalachia Group, LLC, Carbon Tennessee Mining Company, LLC, Carbon Appalachia Enterprises, LLC, Carbon West Virginia Company, LLC, Cranberry Pipeline Corporation, Knox Energy, LLC, Coalfield Pipeline Company and Appalachia Gas Services Company, LLC). As a result, we consolidate Carbon AppalachiaThe OIE Membership Acquisition was funded with cash, debt and the issuance of notes to Old Ironsides. See Note 3 – Acquisitions in the unaudited condensed consolidated financial statements in Item 1 for financial reporting purposes.additional information on the OIE Membership Acquisition.

 

Outlined below is

Liberty Acquisition

In July 2018, we completed an acquisition of 54 operated oil and gas wells covering approximately 55,000 gross acres (22,000 net) and the associated mineral interests in the Appalachian Basin for a summarypurchase price of (i) ownership changes$3.0 million, subject to Carbon Appalachia since its formation, (ii)customary and standard purchase price adjustments (the “Liberty Acquisition”).  The Liberty Acquisition increased our resulting percent ownership of Class A Units, which represents the votingworking interest in Carbon Appalachia, and (iii)the acquired wells from 60% to 100%.  The Liberty Acquisition was funded through borrowings under our proportionate share in Carbon Appalachia after giving effect of all classes of ownership interests.previous credit facility. The Liberty Acquisition was accounted for as a non-significant asset acquisition.

 

Timing  Ownership Changes Resulting Class A
Units (%)
  Proportionate Share
(%)
 
April 2017  Formation: $0.24 million capital contribution  2.00%  2.98%
August 2017  $3.71 million capital contribution  15.20%  16.04%
September 2017  $2.92 million capital contribution  18.55%  19.37%
November 2017  Warrant exercise  26.50%  27.24%
December 2018  OIE Membership Acquisition  100.00%  100.00%


Carbon California

 

Carbon California was formed in 2016 by us, Yorktown and Prudential to acquire producing assets in the Ventura Basin in California. Carbon California was accounted for as an equity method investment from February 2017 until January 31, 2018, upon the exercise of the California Warrant, which required us to consolidate Carbon California for financial reporting purposes as of February 1, 2018.

Outlined below is a summary of (i) ownership changes to Carbon California since its formation, (ii) our resulting percent ownership of Class A Units, and (iii) our proportionate share in Carbon California after giving effect of all classes of ownership interests.

Timing  Ownership Changes Resulting Class A
Units (%)
  Proportionate Share
(%)
 
February 2017  Formation  0.00%  17.81%
February 2018  Warrant exercise  46.96%  56.41%
May 2018  $5.0 million capital contribution  47.05%  53.92%

Recent AcquisitionsSeneca Acquisition

 

WhenIn May 2018, but effective as of October 1, 2017, Carbon California makes acquisitions, we contribute our pro rata equity portion of the purchase price to fund such acquisitions. In 2018, we contributed an aggregate of $5.0 million to Carbon California in connection with Carbon California’s acquisition activities.

When Carbon Appalachia made acquisitions (prior to the OIE Membership Acquisition described below), we contributed our pro rata equity portion of the purchase price to fund such acquisitions. During 2018, we did not contribute any funds to Carbon Appalachia.

While we made other non-material acquisitions that are not specifically listed, the acquisitions described below most meaningfully affect our financial condition.

In December 2018, we acquired all of the Class A Units of Carbon Appalachia owned by Old Ironsides for a purchase price of $58.1 million, subject to purchase price adjustments (OIE Membership Acquisition). As a result of the OIE Membership Acquisition, we now hold all of the issued and outstanding ownership interests of Carbon Appalachia, along with its direct and indirect subsidiaries (Carbon Appalachia Group, LLC, Carbon Tennessee Mining Company, LLC, Carbon Appalachia Enterprises, LLC, Carbon West Virginia Company, LLC, Cranberry Pipeline Corporation, Knox Energy, LLC, Coalfield Pipeline Company and Appalachia Gas Services Company, LLC). The acquisition was funded with cash, debt and the issuance of notes to Old Ironsides.

On July 11, 2018, we completed an acquisition of 54 operated oil and gas wells covering approximately 55,000 gross acres (22,000 net) and the associated mineral interests in the Appalachian Basin for a purchase price of $3.0 million, subject to customary and standard purchase price adjustments (the “Liberty Acquisition”).  The Liberty Acquisition increased our working interest in the acquired wells from 60% to 100%.  The Liberty Acquisition was funded through borrowings under our previous credit facility. The Liberty Acquisition is accounted for as a non-significant asset acquisition.

In May 2018, but effective as of October 1, 2017, Carbon California acquired 332 operated and one non-operated oil wells and one non-operated oil well covering approximately 6,800 gross acres (6,600 net), and fee interests in and to certain lands, situated in the Ventura Basin, together with associated wells, pipelines, facilities, equipment and other property rights for a purchase price of $43.0 million, subject to customary and standard purchase price adjustments, from Seneca Resources Corporation (the “Seneca Acquisition”). We contributed approximately $5.0 million to Carbon California to fund our portion of the purchase price with the remainder funded by Prudential and debt. We raised our $5.0 million through the issuance of 50,000 shares of Series B Convertible Preferred Stock, par value $0.01 per share (the “Preferred Stock”), to Yorktown.


Increase in Authorized Shares of Common Stock

On June 1, 2018, we increased the number of authorized shares of our common stock from 10,000,000 to 35,000,000.

Preferred Stock Issuance to Yorktown

In connection with the closing of the Seneca Acquisition, we raised $5.0 million through the issuance of 50,000 shares of Series B Convertible Preferred Stock, par value $0.01 per share, to Yorktown. See Note 9 to the unaudited condensed consolidated financial statements.

 

Principal Components of Our Cost Structure

 

Lease operating expenses. Lease operating expenses are costs incurred to bring oil and natural gas out of the ground, together with the costs incurred to maintain our producing properties. Such costs include maintenance, repairs and workover expenses related to our oil and natural gas properties.

 

 Pipeline operating expenses. Pipeline operating expenses are costs incurred to accept, transport and deliver gas across our midstream assets.

 


Transportation and gathering costs. Transportation and gathering costs are incurred to bring oil and natural gas to market. Gathering refers to the utilization of low pressurelow-pressure pipelines to move the oil and natural gas from the wellhead into a transportation pipeline, or in case of oil, into a tank battery from which sales of oil are made.

 

Production and property taxes.  Production and property taxes consist of severance, property and propertyad valorem taxes. Production and severance taxes and are paid on oil and natural gas produced based on a percentage of market prices or at fixed rates established by federal, state or local taxing authorities. Ad valorem tax rates, which can fluctuate by year, are determined by individual counties where we have production and are assessed on our sales one or two years in arrears depending on the location of the production.

 

Marketing gas purchases.  Marketing gas purchases consist of third-party purchases of gas associated with our midstream operations.

 

Depreciation, amortization and impairment. We use the full cost method of accounting for oil and gas properties. All costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. We perform a quarterly ceiling test based on average first-of-the-month prices during the twelve-month period prior to the reporting date. The full cost ceiling test is a limitation on capitalized costs prescribed by the SEC. The ceiling test is not a fair value-based measurement; rather, it is a standardized mathematical calculation that compares the net capitalized costs of our full cost pool to estimated discounted cash flows. Should the net capitalized cost exceed the sum of the estimated discounted cash flows, a ceiling test write-down would be recognized to the extent of the excess. For the three months ended March 31, 2019 and 2018, we did not incur a ceiling test impairment.

 

Depletion.Depletion is calculated using capitalized costs in the full cost pool, including estimated asset retirement costs and estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values and depleted based on a unit-of-production method.

 

General and administrative expense.  General and administrative expense includes payroll and benefits for our corporate staff, non-cash stock basedstock-based compensation, costs of maintaining our offices, costs of managing our production, marketing, development and acquisition operations, franchise taxes, audit, tax, legal and other professional fees and legal compliance. Certain of these costs are recovered as management reimbursements in place with Carbon California and, prior to the completion of the OIE Membership Acquisition on December 31, 2018, Carbon Appalachia. In 2018, we expensed costs in preparation of an equity raise that we do not believe is likely to occur in the short term.

 

Interest expense.expense, net.  We finance a portion of our working capital requirements for drilling and completion activities and acquisitions with borrowings under our bank credit facilities. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. Interest expense, net is net of interest income.

 

Income tax expense.  We are subject to state and federal income taxes but typically have not been in a tax paying position for regular federal income taxes, primarily due to the current deductibility of intangible drilling costs (“IDC”) and net operating loss (“NOL”) carryforwards. We pay alternative minimum tax, state income or franchise taxes where IDC or NOL deductions do not exceed taxable income or where state income or franchise taxes are determined on another basis. As of December 31, 2018, we have NOL carryforwards of approximately $29.2 million available to reduce future years’ federal taxable income. Federal NOLs incurred through 2017 expire in various years through 2037 while the NOLs incurred during 2018 and in future years will never expire. As of December 31, 2018, we have various state NOL carryforwards available to reduce future years’ state taxable income, which are dependent on apportionment percentages and state laws that can change from year to year and impact the amount of such carryforwards. These state NOL carryforwards will expire in the future based upon each jurisdiction’s specific lawlaws surrounding NOL carry forwards.carryforwards.

 

In 2017, the Tax Cuts and Jobs Act (“24

TCJA”) was enacted. The TCJA significantly changes the U.S. corporate tax law by, among other things, lowering the U.S. corporate income tax rate from 35% to 21% beginning in January 2018. FASB ASC Topic 740,Income Taxes, requires companies to recognize the impactResults of the changes in tax law in the period of enactment.Operations

 

Other provisions of the TCJA effective in 2018 that may impact income taxes include (i) a limitation on the current deductibility of interest expense in excess of 30% of adjusted taxable income, (ii) a limitation on the usage of NOLs generated after 2017 to 80% of taxable income, (iii) the inclusion of performance based compensation in determining the excessive compensation limitation, and (iv) the unlimited carryforward of NOLs.

Results of Operations

Three Months Ended March 31,September 30, 2019 Compared to Three Months Ended March 31,September 30, 2018

 

The following discussion and analysis relates to items that have affected our results of operations for the three months ended March 31,September 30, 2019 and 2018. The following table sets forth, for the periods presented, selected historical unaudited condensed consolidated statements of operations and production data. The information contained in the table below should be read in conjunction with the Company’s unaudited condensed consolidated financial statements and notes thereto and the information under “Forward Looking Statementsbelow.


 

  Three Months Ended    
  March 31,  Percent 
(in thousands except production and per unit data) 2019  2018 (1)  Change 
Revenue:         
Natural gas sales $19,316  $3,939   390%
Natural gas liquids sales  247   163   51%
Oil sales  8,989   2,983   201%
Transportation and handling  734   -   * 
Marketing gas sales  4,944   -   * 
Commodity derivative loss  (9,306)  (626)  1387%
Other income  26   14   86%
Total revenues  24,950   6,473   285%
             
Expenses:            
Lease operating expenses  6,616   2,087   217%
Pipeline operating expenses  3,085   -   * 
Transportation costs  3,799   855   344%
Production and property taxes  2,010   433   364%
Marketing gas purchases  4,172   -   * 
General and administrative  4,689   2,948   59%
General and administrative – related party reimbursement  -   (1,116)  (100%)
Depreciation, depletion and amortization  3,980   1,492   167%
Accretion of asset retirement obligations  394   141   179%
Total expenses  28,745   6,840   320%
             
Operating income (loss) $(3,795) $(367)  (846%)
             
Other income and (expense):            
Interest expense  (2,914)  (1,002)  191%
Warrant derivative gain  -   225   * 
Equity investment income  19   5,828   * 
Total other income (expense) $(2,895) $5,051   (157%)
             
Production data:            
Natural gas (Mcf)  5,544,052   1,323,092   319%
Oil (Bbl)  147,492   47,103   213%
Natural gas liquids (Bbl)  13,210   4,502   193%
Combined (Mcfe)  6,508,264   1,632,722   299%
             
Average prices before effects of hedges:            
Natural gas (per Mcf) $3.48  $2.98   17%
Oil (per Bbl) $60.95  $57.80   5%
Natural gas liquids (per Bbl) $18.67  $35.30   (47%)
Combined (per Mcfe) $4.39  $4.34   1%
             
Average prices after effects of hedges**:            
Natural gas (per Mcf) $3.34  $2.98   12%
Oil (per Bbl) $63.29  $50.39   26%
Natural gas liquids (per Bbl) $18.67  $35.30   (47%)
Combined (per Mcfe) $4.32  $4.11   1%
             
Average costs (per Mcfe):            
Lease operating expenses $1.02  $1.28   (20%)
Transportation costs $0.26  $0.52   12%
Production and property taxes $0.31  $0.27   15%
Cash-based general and administrative expense, net of related party reimbursement $0.69  $0.95   (27%)
Depreciation, depletion and amortization $0.61  $0.91   (33%)

  Three Months Ended    
  September 30,  Percent 
(in thousands, except production and per unit data) 2019  2018 (1)  Change 
Revenue:         
Natural gas sales $11,963  $4,372   174%
Natural gas liquids sales  10   406   (98%)
Oil sales  9,049   11,850   (24%)
Transportation and handling  304   -   * 
Marketing gas sales  3,491   -   * 
Commodity derivative loss  5,595   (3,902)  * 
Other income  123   16   663%
Total revenues  30,535   12,742   140%
             
Expenses:            
Lease operating expenses  7,689   4,767   61%
Pipeline operating expenses  2,614   -   * 
Transportation costs  1,593   1,433   11%
Production and property taxes  16   743   (98%)
Marketing gas purchases  3,872   -   * 
General and administrative  2,852   3,517   (19%)
General and administrative – related party reimbursement  -   (1,170)  * 
Depreciation, depletion and amortization  4,112   2,731   51%
Accretion of asset retirement obligations  420   206   104%
Total expenses  23,168   12,227   89%
             
Operating income $7,367  $515   * 
             
Other income (expense):            
Interest expense, net  (3,047)  (1,127)  170%
Equity investment income  32   157   * 
Total other (expense) $(3,015) $(970)  * 
             
Production data:            
Natural gas (Mcf)  5,392,453   1,357,350   297%
Oil (Bbl)  147,160   165,427   (11%)
Natural gas liquids (Bbl)  2,000   11,055   (82%)
Combined (Mcfe)  6,287,413   2,416,242   160%
             
Average prices before effects of hedges:            
Natural gas (per Mcf) $2.22  $3.22   (31%)
Oil (per Bbl) $61.49  $71.63   (14%)
Natural gas liquids (per Bbl) $4.98  $36.70   (86%)
Combined (per Mcfe) $3.34  $6.88   (51%)
             
Average prices after effects of hedges**:            
Natural gas (per Mcf) $2.67  $3.29   (19%)
Oil (per Bbl) $61.55  $64.29   (4%)
Natural gas liquids (per Bbl) $4.98  $36.70   (86%)
Combined (per Mcfe) $3.73  $6.42   (42%)
             
Average costs (per Mcfe):            
Lease operating expenses $1.22  $1.97   (38%)
Transportation costs $0.25  $0.59   (58%)
Production and property taxes $-  $0.31   (100%)
Cash-based general and administrative expense, net of related party reimbursement $0.42  $0.89   (53%)
Depreciation, depletion and amortization $0.65  $1.13   (42%)

  

*Not meaningful or applicable

**Includes effect of settled commodity derivative gains and losses
(1)Includes Carbon California activity for the period of consolidation from February 1, 2018 through March 31, 2018, and does not includeExcludes Carbon Appalachia activity during 2018 as Carbon Appalachia did not consolidate until December 31, 2018 upon the closing of the OIE Membership Acquisition. See Recent Developments and Factors Affecting Comparability.


Oil,Natural gas, natural gas liquids, and natural gasoil sales –Sales of oil,natural gas, natural gas liquids and natural gasoil increased 303% to approximately $28.6 million26% for the three months ended March 31,September 30, 2019 from approximately $7.1 million forcompared to the three months ended March 31, 2018. This increase issame period in 2018, primarily attributeddue to a 319%, 213% and 193%160% increase in natural gas, oil and natural gas liquids and oil sales volumes, respectively, and an increasepartially offset by a 51% decrease in natural gas and oil prices of 17% and 5%, respectively.combined product pricing. The increases in production were a direct result of the acquisitionsacquisition of Carbon Appalachia and Carbon California during 2018 and the resultant consolidation of the related activity for the three months ended March 31,September 30, 2019. Carbon Appalachia operating results are included in each of the three months ended March 31,September 30, 2019 whereas no Carbon Appalachia results were included in the three months ended March 31, 2018. Carbon California operating results are included in each of the three months ended March 31, 2019 whereas only the months of February and March reflect Carbon California activities during the three months ended March 31, 2018. Furthermore, the December 2017 California wildfires significantly impacted Carbon California results of operations in the first quarter ofSeptember 30, 2018.

 

Commodity derivative gains and losses –To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we enter into derivative contracts including fixed price swap contracts and costless collars. Because we do not designate these derivatives as cash flow hedges, they do not receive hedge accounting treatment and all mark-to-market gains or losses, as well as settlement gains or losses on the derivative instruments, are currently recognized in our results of operations. The unrealized gains and losses represent the changes in the fair value of these contracts as oil and natural gas futures prices fluctuate relative to the fixed price we will receive from these contracts. For the three months ended March 31,September 30, 2019 and 2018, we had hedging gains of approximately $5.6 million and hedging losses of approximately $9.3$3.9 million, and $626,000, respectively.

 

Lease operating expensesLease operating expenses for the three months ended March 31,September 30, 2019 increased 217% comparedprimarily due to the three months ended March 31, 2018. The increase was primarily attributable to the Carbon Appalachia and Carbon California acquisitionsOIE Membership Acquisition and the resultant increased production volumes. Expenses during the three months ended March 31, 2018 were also lower as a result of the December 2017 California wildfires. On a per Mcfe basis, lease operating expenses decreased to $1.02$1.22 per Mcfe for the three months ended March 31,September 30, 2019 from $1.28$1.97 per Mcfe for the three months ended March 31,September 30, 2018. We experience higher costs on a per Mcfe basis associated with the production of oil versus gas. Oil production accounted for approximately 41% of our production mix for the three months ended September 30, 2018 and 14% for the three months ended September 30, 2019.

 

Transportation costs –Transportation costs for the three months ended March 31,September 30, 2019 increased 95% compared to the three months ended March 31, 2018. This increase is attributabledue to an increase in production as a result of the Carbon Appalachia Acquisition and a full three months of Carbon California operations.OIE Membership Acquisition. On a per Mcfe basis, these expenses decreased from $0.52$0.59 per Mcfe for the three months ended March 31,September 30, 2018 to $0.26$0.25 per Mcfe for the three months ended March 31,September 30, 2019.

 

Production and property taxes –Production and property taxes increased from approximately $433,000decreased for the three months ended March 31, 2018September 30, 2019 due to approximately $2.0 million for the three months ended March 31, 2019. This increase is primarily attributable to increased oil and natural gas sales as a result of consolidation of Carbon Appalachia and a full three months of Carbon California production.decreased ad valorem estimated tax rates. Production taxes averaged approximately 7.0%3.5% and 6.1%1.9% of product sales for the three months ended March 31,September 30, 2019 and 2018, respectively. Ad valorem tax rates, which can fluctuate by year,Production taxes associated with oil production are determined by individual counties where we havegenerally lower on a per Mcfe basis versus gas production. Oil production accounted for approximately 41% of our production mix for the three months ended September 30, 2018 and are assessed on our sales one or two years in arrears depending on14% for the location of the production.three months ended September 30, 2019.

 

Depreciation, depletion and amortization (DD&A)(“DD&A”) –DD&A increased from approximately $1.5 million for the three months ended March 31, 2018 to approximately $4.0 million for the three months ended March 31,September 30, 2019 primarily due to the consolidation of Carbon Appalachia and a full three months of Carbon California operations.Appalachia. On a per Mcfe basis, DD&A decreased from $0.91$1.13 per Mcfe for the three months ended March 31,September 30, 2018 to $0.61$0.65 per Mcfe for the three months ended March 31,September 30, 2019. The decrease in the depletion rate is primarily attributable to the consolidation of Carbon Appalachia.


 

General and administrative expensesCash-based general– General and administrative expenses increased from approximately $1.5 million for the three months ended March 31, 2018 to approximately $4.5 million for the three months ended March 31, 2019. This increase isSeptember 30, 2019, primarily attributabledue to the consolidation of Carbon Appalachia and a full three months of Carbon California operations.Appalachia. As a result of the consolidation of Carbon Appalachia and Carbon California during the three months ended March 31,September 30, 2019, management reimbursements which offset general and administrative expenses decreased by approximately $1.1$1.2 million compared to the three months ended December 31,September 30, 2018.


We define the term cash-based general and administrative expense (non-GAAP measure) as consolidated general and administrative expense adjusted to exclude non-cash stock-based compensation and related party reimbursements. On a per Mcfe basis, cash-based general and administrative expenses, net of related party reimbursements, decreased from $0.95$0.89 per Mcfe for the three months ended March 31,September 30, 2018 to $0.69$0.42 per Mcfe for the three months ended March 31,September 30, 2019. Non-cash stock based compensation and otherCash-based general and administrative expenses for the three months ended March 31,September 30, 2019 and 2018 are summarized in the following table:

 

General and administrative expenses Three Months Ended
March 31,
  Increase/ 
(in thousands) 2019  2018  (Decrease) 
          
Stock-based compensation $222  $292  $(70)
Other general and administrative expenses  4,467   2,656   1,811 
General and administrative – related party reimbursement  -   (1,116)  1,116 
General and administrative expense $4,689  $1,832  $2,858 

General and administrative expenses Three Months Ended
September 30,
 
(in thousands) 2019  2018 
       
General and administrative expenses $2,852  $3,517 
Adjustments:        
Stock-based compensation  (204)  (187)
General and administrative – related party reimbursement  -   (1,170)
Cash-based general and administrative expense $2,648  $2,160 

   

Interest expense, net Interest expense, net increased from approximately $1.0 million for the three months ended March 31, 2018 to approximately $2.9 million for the three months ended March 31,September 30, 2019, primarily due to higher outstanding debt balances related to borrowings to complete the Carbon AppalachiaOIE Membership Acquisition and the Seneca acquisitionsAcquisition in 2018. On a per Mcfe basis, interest expense decreased from $0.61 per Mcfe for the three months ended March 31, 2018 to $0.45 per Mcfe for the three months ended March 31, 2019.

 

Transportation and handling, marketing gas sales, pipeline operating expenses and marketing gas purchases –Subsequent to the OIE Membership Acquisition on December 31, 2018, we consolidate Carbon Appalachia operations. The associated revenues and expenses are presented within our unaudited consolidated statements of operations during the three months ended March 31,September 30, 2019. These operations were not presented in our unaudited consolidated statements of operations during the three months ended MarchSeptember 30, 2018.

27

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018

The following discussion and analysis relates to items that have affected our results of operations for the nine months ended September 30, 2019 and 2018. The following table sets forth, for the periods presented, selected historical unaudited condensed consolidated statements of operations and production data.

  Nine Months Ended    
  September 30,  Percent 
(in thousands, except production and per unit data) 2019  2018 (1)  Change 
Revenue:         
Natural gas sales $45,495  $11,835   284%
Natural gas liquids sales  451   1,119   (60%)
Oil sales  27,940   22,924   22%
Transportation and handling  1,361   -   * 
Marketing gas sales  11,656   -   * 
Commodity derivative loss  4,969   (10,550)  (147%)
Other income  820   35   2243%
Total revenues  92,692   25,363   265%
             
Expenses:            
Lease operating expenses  21,784   10,824   101%
Pipeline operating expenses  8,650   -   * 
Transportation costs  4,392   3,786   16%
Production and property taxes  3,692   1,792   106%
Marketing gas purchases  14,969   -   * 
General and administrative  11,489   9,007   28%
General and administrative – related party reimbursement  -   (3,383)  (100%)
Depreciation, depletion and amortization  11,973   6,202   93%
Accretion of asset retirement obligations  1,219   510   139%
Total expenses  78,168   28,738   172%
             
Operating income (loss) $14,524  $(3,375)  * 
             
Other income (expense):            
Interest expense, net  (9,772)  (3,331)  193%
Warrant derivative gain  -   225   * 
Gain on derecognized equity investment in affiliate-Carbon California  -   5,390   * 
Equity investment income  73   1,121   * 
Total other (expense) income $(9,699) $3,405   * 
             
Production data:            
Natural gas (Mcf)  16,236,149   4,205,890   286%
Oil (Bbl)  444,926   327,028   36%
Natural gas liquids (Bbl)  26,990   29,454   (8%)
Combined (Mcfe)  19,067,645   6,344,782   201%
             
Average prices before effects of hedges:            
Natural gas (per Mcf) $2.80  $2.81   0%
Oil (per Bbl) $62.80  $70.10   (10%)
Natural gas liquids (per Bbl) $16.72  $37.97   (56%)
Combined (per Mcfe) $3.87  $5.65   (32%)
             
Average prices after effects of hedges**:            
Natural gas (per Mcf) $2.95  $2.89   2%
Oil (per Bbl) $62.42  $62.51   0%
Natural gas liquids (per Bbl) $16.72  $37.97   (56%)
Combined (per Mcfe) $3.99  $5.31   (25%)
             
Average costs (per Mcfe):            
Lease operating expenses $1.14  $1.71   (33%)
Transportation costs $0.23  $0.60   (62%)
Production and property taxes $0.19  $0.28   (32%)
Cash-based general and administrative expense, net of related party reimbursement $0.57  $0.78   (27%)
Depreciation, depletion and amortization $0.63  $0.98   (36%)

*Not meaningful or applicable
**Includes effect of settled commodity derivative gains and losses
(1)Includes Carbon California activity for the period of consolidation from February 1, 2018 through September 30, 2018 and does not include Carbon Appalachia activity during 2018 as Carbon Appalachia did not consolidate until December 31, 2018 upon the closing of the OIE Membership Acquisition. See Recent Developments and Factors Affecting Comparability.

28

Natural gas, natural gas liquids, and oil sales –Sales of natural gas, natural gas liquids and oil increased approximately 106% for the nine months ended September 30, 2019 compared to the same period in 2018 primarily due to a 201% increase in natural gas, natural gas liquids and oil sales volumes, partially offset by a 32% decrease in combined product pricing. The increases in production were a direct result of the acquisitions of Carbon Appalachia and Carbon California and the resultant consolidation of the related activity for the nine months ended September 30, 2019. Carbon Appalachia operating results are included in each of the nine months ended September 30, 2019 whereas no Carbon Appalachia results were included in the nine months ended September 30, 2018. Additionally, the December 2017 California wildfires significantly impacted Carbon California results of operations for the nine months ended September 30, 2018. Carbon California oil production was not impacted during the nine months ended September 30, 2019. Finally, the Seneca Acquisition closed May 1, 2018, and therefore operations for the nine months ended September 30, 2018 include only five months of operations from the assets acquired compared to their inclusion for all nine months during 2019.

Commodity derivative gains and losses – To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we enter into derivative contracts including fixed price swap contracts and costless collars. Because we do not designate these derivatives as cash flow hedges, they do not receive hedge accounting treatment and all mark-to-market gains or losses, as well as settlement gains or losses on the derivative instruments, are currently recognized in our results of operations. The unrealized gains and losses represent the changes in the fair value of these contracts as oil and natural gas futures prices fluctuate relative to the fixed price we will receive from these contracts. For the nine months ended September 30, 2019 and 2018, we had hedging gains of approximately $5.0 million and hedging losses of approximately $10.6 million, respectively.

Lease operating expenses – Lease operating expenses for the nine months ended September 30, 2019 increased primarily due to the OIE Membership Acquisition and the resultant increased production volumes. Expenses during the nine months ended September 30, 2018 were also lower as a result of the December 2017 California wildfires. On a per Mcfe basis, lease operating expenses decreased to $1.14 per Mcfe for the nine months ended September 30, 2019 from $1.71 per Mcfe for the nine months ended September 30, 2018. We experience higher costs on a per Mcfe basis associated with the production of oil versus gas. Oil production accounted for approximately 31% of our production mix for the nine months ended September 30, 2018 and 14% for the nine months ended September 30, 2019.

Transportation costs – Transportation costs for the nine months ended September 30, 2019 increased due to an increase in production as a result of the OIE Membership Acquisition and a full nine months of Carbon California operations, including Seneca Acquisition assets. On a per Mcfe basis, these expenses decreased from $0.60 per Mcfe for the nine months ended September 30, 2018 to $0.23 per Mcfe for the nine months ended September 30, 2019.

Production and property taxes – Production and property taxes increased for the nine months ended September 30, 2019 due to increased oil and natural gas sales as a result of the consolidation of Carbon Appalachia and a full nine months of Carbon California production, partially offset due to decreased ad valorem estimated tax rates utilized. Production taxes averaged approximately 3.6% and 2.2% of product sales for the nine months ended September 30, 2019 and 2018, respectively. Production taxes associated with oil production are generally lower on a per Mcfe basis versus gas production. Oil production accounted for approximately 31% of our production mix for the nine months ended September 30, 2018 and 14% for the nine months ended September 30, 2019.

Depreciation, depletion and amortization (“DD&A”) – DD&A increased for the nine months ended September 30, 2019 primarily due to the consolidation of Carbon Appalachia and a full nine months of Carbon California operations, including the Seneca Acquisition assets. On a per Mcfe basis, DD&A decreased from $0.98 per Mcfe for the nine months ended September 30, 2018 to $0.63 per Mcfe for the nine months ended September 30, 2019. The decrease in the depletion rate is primarily attributable to the consolidation of Carbon Appalachia.

29

General and administrative expenses –General and administrative expenses increased for the nine months ended September 30, 2019 primarily due to the consolidation of Carbon Appalachia and a full nine months of Carbon California operations. As a result of the consolidation of Carbon Appalachia and Carbon California during the nine months ended September 30, 2019, management reimbursements which offset general and administrative expenses, decreased by approximately $3.4 million compared to the nine months ended September 30, 2018. On a per Mcfe basis, cash-based general and administrative expenses, net of related party reimbursements, decreased from $0.78 per Mcfe for the nine months ended September 30, 2018 to $0.57 per Mcfe for the nine months ended September 30, 2019. Cash-based general and administrative expenses for the nine months ended September 30, 2019 and 2018 are summarized in the following table:

General and administrative expenses Nine Months Ended
September 30,
 
(in thousands) 2019  2018 
       
General and administrative expenses $11,489  $9,007 
Adjustments:        
Stock-based compensation  (650)  (672)
General and administrative – related party reimbursement  -   (3,383)
Cash-based general and administrative expense $10,839  $4,952 

Interest expense, net –Interest expense, net increased for the nine months ended September 30, 2019 primarily due to higher outstanding debt balances related to borrowings to complete the OIE Membership Acquisition and the Seneca Acquisition in 2018.

  

Transportation and handling, marketing gas sales, pipeline operating expenses and marketing gas purchases –Subsequent to the OIE Membership Acquisition on December 31, 2018, we consolidate Carbon Appalachia operations. The associated revenues and expenses are presented within our unaudited consolidated statements of operations during the nine months ended September 30, 2019. These operations were not presented in our unaudited consolidated statements of operations during the nine months ended September 30, 2018.

Liquidity and Capital Resources

Our primary sources of liquidity and capital resources are cash flows from operations, borrowings under our credit facilities and senior revolving notes, and on occasion, the sale of non-core assets. Borrowings under the credit facilities and senior revolving notes may be used to fund field development projects and to fund future complementary acquisitions and for general working capital purposes. We may use other sources of capital, including the issuance of debt or equity securities, to fund acquisitions or maintain financial flexibility.

As of September 30, 2019, our liquidity was $19.5 million, consisting of cash on hand of $3.5 million and $16.0 million of available borrowing capacity on our credit facilities.

On December 31, 2018, we closed the OIE Membership Acquisition. As a result, we now own 100% of all interests in Carbon Appalachia; therefore, we receive 100% of the cash flows associated with Carbon Appalachia.

Prior to the consolidation of Carbon California and Carbon Appalachia effective February 1, 2018 and December 31, 2018, respectively, we generated operating cash flow by providing management services to these unconsolidated subsidiaries. These management service reimbursements were included in general and administrative – related party reimbursement on our unaudited condensed consolidated statements of operations. We also received reimbursements of operating expenses, our share of which were included in investments in affiliates on our unaudited condensed consolidated statements of operations. As we now consolidate Carbon California and Carbon Appalachia, these management and operating reimbursements are eliminated in the unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2019.

Commodity Derivatives

 

Our exploration, development and acquisition activities may require us to make significant operating and capital expenditures. Historically, we have used cash flow from operations and our bank credit facilities as our primary sources of liquidity and on occasion, we have engaged in the sale of assets. Changes in the market prices for oil and natural gas directly impact our level of cash flow generated from operations. The prices we receive for our production are determined by prevailing market conditions and greatly influence our revenue, cash flow, profitability, access to capital and future rate of growth. We employ a commodity hedging strategy in an attempt to moderate the effects of commodity price fluctuations on our cash flow.

The following table reflects our outstanding derivative agreements as of March 31, 2019:

  Natural Gas Swaps  Natural Gas Collars 
     Weighted
Average
     Weighted
Average Price
 
Year MMBtu  Price (a)  MMBtu  Range (a) 
             
2019  11,762,000  $2.82   374,000  $2.60 – $3.03 
2020  12,433,000  $2.73   1,018,000  $2.50 – $2.70 
2021  6,448,000  $2.58   -  $- 

  Oil Swaps  Oil Collars 
Year WTI Bbl  Weighted Average  Price (b)  Brent Bbl  Weighted Average Price (c)  WTI Bbl  Weighted  Average Price  Brent Bbl  Weighted  Average Price 
2019  180,775  $53.46   121,079  $66.93   -   -   29,800  $47.00 - $75.00 
2020  121,147  $55.37   151,982  $66.03   18,000  $47.00 - $60.15   37,400  $47.00 - $75.00 
2021  -  $-   86,341  $67.12   30,000  $47.00 - $60.15   98,000  $47.00 - $75.00 

*Includes 100% of Carbon California’s outstanding derivative hedges at March 31, 2019, and not our proportionate share.
(a)NYMEX Henry Hub Natural Gas futures contract for the respective period.
(b)NYMEX Light Sweet Crude West Texas Intermediate futures contract for the respective period.
(c)Brent future contracts for the respective period.

 

This hedge program mitigates uncertainty regarding cash flow that we will receive with respect to a portion of our expected production through 2021.2022. Future hedging activities may result in reduced income or even financial losses to us.SeeRisk Factors-The use of derivative instruments used in hedging arrangements could result in financial losses or reduce income,” in our 2018 Annual Report on Form 10-K for further details of the risks associated with our hedging activities. In the future, we may determine to increase or decrease our hedging positions. See Note 14 – Commodity Derivatives in the unaudited condensed consolidated financial statements in Item 1 for more information, including our outstanding derivatives.

 


We have derivative contracts with BP Energy Company pursuant to ISDA Master Agreements. BP Energy Company is currently our only derivative contract counterparty.

Management Reimbursements

In our role as manager of Carbon California and Carbon Appalachia we receive reimbursements for management services. Prior to consolidation of Carbon California and Carbon Appalachia effective February 1, 2018 and December 31, 2018, respectively, these management service reimbursements were included in general and administrative – related party reimbursement on our unaudited consolidated statements of operations. As we now consolidate both Carbon California and Carbon Appalachia, these reimbursements are eliminated upon consolidation.

Operating Reimbursements

In our role as operator of Carbon California and Carbon Appalachia, we receive reimbursements of operating expenses. Prior to consolidation of Carbon California and Carbon Appalachia effective February 1, 2018 and December 31, 2018, respectively, these operating reimbursements were included in operating expenses on our unaudited consolidated statements of operations. As we now consolidate both Carbon California and Carbon Appalachia, these reimbursements are eliminated upon consolidation.

Historically, the primary sources of liquidity have been our credit facilities (described below) and cash flow from operations. We may use other sources of capital, including the issuance of debt or equity securities, to fund acquisitions or maintain our financial flexibility.

Credit Facilities and Notes Payable

Carbon Appalachia

2018 Credit Facility

In connection with and concurrently with the closing of the OIE Membership Acquisition, the Company and its subsidiaries amended and restated our prior credit facilities for a new $500.0 million senior secured asset-based revolving credit facility maturing December 31, 2022 and a $15.0 million term loan which matures in 2020 (the“2018 Credit Facility”). The 2018 Credit Facility includes a sublimit of $1.5 million for letters of credit. The borrowers under the 2018 Credit Facility are Carbon Appalachia Enterprises, LLC (“CAE”) and various other subsidiaries of the Company (including Nytis USA, together with CAE, the“Borrowers”). Under the 2018 Credit Facility, Carbon is neither a borrower nor a guarantor. The initial borrowing base under the 2018 Credit Facility was $75.0 million, and remained so as of March 31, 2019.

The 2018 Credit Facility is guaranteed by each existing and future direct or indirect subsidiary of the Borrowers and certain other subsidiaries of the Company (subject to various exceptions) and the obligations under the 2018 Credit Facility are secured by essentially all tangible and intangible and real property (subject to certain exclusions).

Interest accrues on borrowings under the 2018 Credit Facility at a rate per annum equal to either (i) the base rate plus an applicable margin equal to 0.25% - 0.75% depending on the utilization percentage or (ii) the Adjusted LIBOR rate plus an applicable margin equal to 2.75% - 3.75% depending on the utilization percentage, at the Borrowers’ option. The Borrowers are obligated to pay certain fees and expenses in connection the 2018 Credit Facility, including a commitment fee for any unused amounts of 0.50% and an origination fee of 0.50%. Loans under the 2018 Credit Facility may be prepaid without premium or penalty.

The 2018 Credit Facility also provides for a $15.0 million term loan which bears interest at a rate of 6.25% and is payable in 18 equal monthly installments beginning February 1, 2019 with the last payment due on June 30, 2020.

The 2018 Credit Facility contains certain affirmative and negative covenants that, among other things, limit the Company’s ability to (i) incur additional debt; (ii) incur additional liens; (iii) sell, transfer or dispose of assets; (iv) merge or consolidate, wind-up, dissolve or liquidate; (v) make dividends and distribution on, or repurchase of, equity; (vi) make certain investments; (vii) enter into certain transactions with their affiliates; (viii) enter in sale-leaseback transactions; (ix) make optional or voluntary payment of debt other than obligations under the 2018 Credit Facility; (x) change the nature of their business; (xi) change their fiscal year or make changes to the accounting treatment or reporting practices; (xii) amend their constituent documents; and (xiii) enter into certain hedging transactions.

The affirmative and negative covenants are subject to various exceptions, including certain basket amounts and acceptable transaction levels. In addition, the 2018 Credit Facility requires the Borrowers’ compliance, on a consolidated basis, with a maximum Net Debt (all debt of the Borrowing Parties minus all unencumbered cash and cash equivalents of the Borrowers not to exceed $3.0 million) / EBITDAX (as defined) ratio of 3.50 to 1.00 and a current ratio covenant minimum of 1.00 to 1.00, tested quarterly, commencing with the quarter ending March 31, 2019.

As of March 31, 2019, there was approximately $70.2 million in outstanding borrowings, an additional $4.8 million borrowing capacity under the 2018 Credit Facility, and Carbon Appalachia was in compliance with its financial covenants.


Old Ironsides Notes

On December 31, 2018, as part of the OIE Membership Acquisition, we delivered unsecured promissory notes in the aggregate original principal amount of approximately $25.1 million to Old Ironsides (the “Old Ironsides Notes”). The Old Ironsides Notes bear interest at 10% per annum and have a term of five years, the first three of which require interest-only payments at the end of each calendar quarter beginning with the quarter ending March 31, 2019. At the end of the three-year interest-only period, the then current outstanding principal balance and interest is to be paid in 24 equal monthly payments. The Old Ironsides Notes also require mandatory prepayments upon the occurrence of certain subsequent liquidity events. A mandatory, one-time principal reduction payment in the aggregate amount of $2.0 million was made to Old Ironsides on February 1, 2019. Subsequent to the closing of the OIE Membership Acquisition Old Ironsides ceased to be a related party.

The interest payable under the Old Ironsides Notes can be paid-in-kind at the election of the Company. This provision allows the Company to increase the principal balance associated with the Old Ironsides Notes. This election creates a second tranche of principal, which bears interest at 12% per annum. On March 31, 2019, the Company elected to pay-in-kind approximately $594,000.

Carbon California

Senior Revolving Notes, Related Party

On February 15, 2017, Carbon California entered into a Note Purchase Agreement (the “Note Purchase Agreement) for the issuance and sale of Senior Secured Revolving Notes to Prudential with an initial revolving borrowing capacity of $25.0 million which mature on February 15, 2022 (the “Senior Revolving Notes”). Carbon Energy Corporation is not a guarantor of the Senior Revolving Notes. The closing of the Note Purchase Agreement on February 15, 2017 resulted in the sale and issuance by Carbon California of Senior Revolving Notes in the principal amount of $10.0 million. The maximum principal amount available under the Senior Revolving Notes is based upon the borrowing base attributable to Carbon California’s proved oil and gas reserves which is to be determined at least semi-annually. As of March 31, 2019, the borrowing base was $41.0 million, of which $38.5 million was outstanding.

Carbon California may elect to incur interest at either (i) 5.50% plus the London interbank offered rate (“LIBOR”) or (ii) 4.50% plus the Prime Rate (which is defined as the interest rate published daily by JPMorgan Chase Bank, N.A.). As of March 31, 2019, the effective borrowing rate for the Senior Revolving Notes was 7.80%. In addition, the Senior Revolving Notes include a commitment fee for any unused amounts at 0.50% as well as an annual administrative fee of $75,000, payable on February 15 each year.

The Senior Revolving Notes are secured by all the assets of Carbon California. The Senior Revolving Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated proved developed production at such time for year one, two and three at a rate of 75%, 65% and 50%, respectively. Carbon California may make principal payments in minimum installments of $500,000. Distributions to equity members are generally restricted.

Carbon California may at any time repay the Senior Revolving Notes, in whole or in part, without penalty. Carbon California must pay down Senior Revolving Notes or provide mortgages of additional oil and natural gas properties to the extent that outstanding loans and letters of credit exceed the borrowing base.  

Subordinated Notes, Related Party

On February 15, 2017, Carbon California entered into a Securities Purchase Agreement (the “Securities Purchase Agreement”) with Prudential Capital Energy Partners, L.P. for the issuance and sale of Subordinated Notes due February 15, 2024, bearing interest of 12% per annum (the “Subordinated Notes”). Carbon Energy Corporation is not a guarantor of the Subordinated Notes. The closing of the Securities Purchase Agreement on February 15, 2017 resulted in the sale and issuance by Carbon California of Subordinated Notes in the original principal amount of $10.0 million, all of which remains outstanding as of March 31, 2019.


The Subordinated Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated production at such time for year one, two and three at a rate of 67.5%, 58.5% and 45%, respectively.

Prepayment of the Subordinated Notes is allowed at 100%, subject to a 3.0% fee of outstanding principal. Prepayment is not subject to a prepayment fee after February 17, 2020. Distributions to equity members are generally restricted.

2018 Subordinated Notes, Related Party

On May 1, 2018, Carbon California entered into an agreement with Prudential for the issuance and sale of $3.0 million in Subordinated Notes due February 15, 2024, bearing interest of 12% per annum (the “2018 Subordinated Notes”), of which $3.0 million remains outstanding as of March 31, 2019.

The 2018 Subordinated Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated production at such time for year one, two and three at a rate of 67.5%, 58.5% and 45%, respectively.

Prepayment of the 2018 Subordinated Notes is allowed at 100%, subject to a 3.0% fee of outstanding principal. Prepayment is not subject to a prepayment fee after February 17, 2020. Distributions to equity members are generally restricted.

Restrictions and Covenants

The Senior Revolving Notes, Subordinated Notes and 2018 Subordinated Notes contain affirmative and negative covenants that, among other things, limit Carbon California’s ability to (i) incur additional debt; (ii) incur additional liens; (iii) sell, transfer or dispose of assets; (iv) merge or consolidate, wind-up, dissolve or liquidate; (v) make dividends and distributions on, or repurchases of, equity; (vi) make certain investments; (vii) enter into certain transactions with our affiliates; (viii) enter into sales-leaseback transactions; (ix) make optional or voluntary payments of debt; (x) change the nature of our business; (xi) change our fiscal year to make changes to the accounting treatment or reporting practices; (xii) amend constituent documents; and (xiii) enter into certain hedging transactions.


The affirmative and negative covenants are subject to various exceptions, including basket amounts and acceptable transaction levels. In addition, (i) the Senior Revolving Notes require Carbon California’s compliance, on a consolidated basis, with (A) a maximum Debt/EBITDA ratio of 4.0 to 1.0, stepping down to 3.5 to 1.0 starting with the quarter ending June 30, 2018, (B) a maximum Senior Revolving Notes/EBITDA ratio of 2.5 to 1.0, (C) a minimum interest coverage ratio of 3.0 to 1.0 and (D) a minimum current ratio of 1.0 to 1.0 and (ii) the Subordinated Notes require Carbon California’s compliance, on a consolidated basis, with (A) a maximum Debt/EBITDA ratio of 4.5 to 1.0, stepping down to 4.0 to 1.0 starting with the quarter ending June 30, 2018, (B) a maximum Senior Revolving Notes/EBITDA ratio of 3.0 to 1.0, (C) a minimum interest coverage ratio of 2.5 to 1.0, (D) an asset coverage test whereby indebtedness may not exceed the product of 0.65 times Adjusted PV-10 set forth in the most recent reserve report, (E) maintenance of a minimum borrowing base of $10,000,000 under the Senior Revolving Notes and (F) a minimum current ratio of 0.85 to 1.00.

As of March 31, 2019, Carbon California was in compliance with its covenants.

Borrowings under the Senior Revolving Notes and net proceeds from the Subordinated Notes issuances were used to fund certain acquisitions by Carbon California. Additional borrowings under the Senior Revolving Notes may be used to fund field development projects and to fund future complementary acquisitions and for general working capital purposes of Carbon California.

Sources and Uses of Cash

Our primary sources of liquidity and capital resources are operating cash flow and borrowings under our credit facilities. On December 31, 2018, we closed the OIE Membership Acquisition. As a result, we now own 100% of all interests in Carbon Appalachia. Upon closing, we received approximately $12.1 million in cash and will now receive 100% of cash flows associated with Carbon Appalachia.

Our primary uses of funds are expenditures for acquisitions, exploration and development activities, leasehold acquisitions, other capital expenditures and debt service.

Low prices for our oil and natural gas production may adversely impact our operating cash flow and amount of cash available for development activities.

 

The following table presents net cash provided by or used in operating, investing and financing activities for the threenine months ended March 31,September 30, 2019 and 2018.2018:

 

  Nine Months Ended 
  September 30, 
(in thousands) 2019  2018 
       
Net cash provided by operating activities $14,122  $3,312 
Net cash used in investing activities $(3,862) $(44,406)
Net cash (used in) provided by financing activities $(12,482) $43,921 

  Three Months Ended 
  March 31, 
(in thousands) 2019  2018 
       
Net cash provided by operating activities $8,311  $95 
Net cash (used in) investing activities $(336) $(599)
Net cash (used in) provided by financing activities $(2,695) $2,968 

Operating Activities

Net cash provided by operating activities is primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and changes in working capital. Operating cash flows increased approximately $8.1$10.8 million for the threenine months ended March 31,September 30, 2019 as compared to the same period in 2018. This increase was primarily due to increased revenues from the acquisition of producing oil and natural gas properties in the Appalachian Basin in the fourth quarter of 2018 and increased revenues from the consolidation of Carbon California, effective February 1, 2018.including the Seneca Acquisition.

Investment Activities

 

Net cash used in investing activities is primarily comprised of the acquisition, exploration and development of oil and natural gas properties, net of dispositions of oil and natural gas properties. Net cash used in investing activities decreased approximately $263,000$40.5 million for the threenine months ended March 31,September 30, 2019 as compared to the same period in 2018.2018, primarily due to the Seneca Acquisition.

Financing Activities

 

Net cash provided by or used in financing activities is primarily comprised of activities associated with our credit facilities and equity contributions and distributions.facilities. During the threenine months ended March 31,September 30, 2019, the Company (i) paid $2.0 million in principal associated with the Old Ironsides Notes; (ii)Notes, paid approximately $1.7$8.7 million in principal associated with the 2018 Credit Facility, term note; and (iii) increased netpaid approximately $5.7 million in principal associated with the Senior Revolving Notes. The payments were partially offset by an increase in borrowings under the 2018 Credit Facility revolver by approximately $1.0$4.0 million. During the threenine months ended March 31,September 30, 2018, the Company increased borrowings by approximately $1.0$34.5 million, received $5.0 million in proceeds from the issuance of preferred stock to Yorktown, and $2.0received an equity contribution of $5.0 million under its previously held credit facility revolver andfrom Prudential related to the Carbon California Senior Revolving Notes, respectively.Seneca Acquisition. 

 

Capital Expenditures

 

Capital expenditures incurred for the threenine months ended March 31,September 30, 2019 and 2018 are summarized in the following table:

 

 Three Months Ended
March 31,
  Nine Months Ended
September 30,
 
(in thousands) 2019 2018  2019 2018 
          
Drilling and development $461  $707  $4,003  $940 
Other  39  167   223   43,741 
Total capital expenditures $500  $874  $4,226  $44,681 

  

Capital expenditures presented in the table above represent cash used for capital expenditures.

 

Due to low commoditynatural gas prices, the Company reduced its drilling program in 2018 and for three months ended March 31, 2019 and has focused on the optimization of our gathering facilities and marketing arrangements to provide greater flexibility in moving natural gas production to markets with more favorable pricing. Other factors impacting the level of our capital expenditures include the cost and availability of oil field services, general economic and market conditions and weather disruptions. We have approximately $3.0 million to $5.0 million in planned capital expenditures for the remainder of 2019 as we complete our oil drilling program in California.


Credit Facilities and Notes Payable

 

For a discussion of our long-term debt, see Note 7 – Credit Facilities and Notes Payable in the unaudited condensed consolidated financial statements in Item 1.

Off-Balance Sheet Arrangements

 

From time-to-time, we enter intoWe did not have any off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. Asas of March 31, 2019, the off-balance sheet arrangements and transactions that we have entered into include (i) operating lease agreements, (ii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as natural gas transportation contracts, and (iii) oil and natural gas physical delivery contracts that are not expected to be net cash settled and are considered to be normal sales contracts and not derivatives. We do not believe that any of these arrangements are reasonably likely to materially affect our liquidity or availability of, or requirements for, capital resources.September 30, 2019.

 


Critical Accounting Policies, Estimates, Judgments, and Assumptions

 

Our critical accounting policies and estimates are set forth in“Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations- Critical Accounting Policies, Estimates, Judgments, and Assumptions” in our 2018 Annual Report on Form 10-K. As of March 31,September 30, 2019, there have been no significant changes to our critical accounting policies and estimates since our 2018 Annual Report on Form 10-K was filed.  

 

Forward Looking Statements

 

The information in this Quarterly Report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements are statements other than statements of historical or present facts, that address activities, events, outcomes, and other matters that the Company plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates, or anticipates (and other similar expressions) will, should, or may occur in the future. Generally, the words “expects,” “anticipates,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “may,” “will,” “could,” “should,” “future,” “potential,” “continue,” variations of such words, and similar expressions identify forward-looking statements. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.

 

These forward-looking statements appear in a number ofseveral places in this report and include statements with respect to, among other things:

 

estimates of our oil, natural gas liquids, and natural gas reserves;

 

estimates of our future oil, natural gas liquids, and natural gas production, including estimates of any increases or decreases in our production;

 

our future financial condition and results of operations;

 

our future revenues, cash flows, and expenses;

 

our access to capital and our anticipated liquidity;

  

our future business strategy and other plans and objectives for future operations and acquisitions;

 

our outlook on oil, natural gas liquids, and natural gas prices;

 

the amount, nature, and timing of future capital expenditures, including future development costs;

  

our ability to access the capital markets to fund capital and other expenditures;

 

our assessment of our counterparty risk and the ability of our counterparties to perform their future obligations; and

 

the impact of federal, state and local political, regulatory, and environmental developments in the United States of America

  

We believe the expectations and forecasts reflected in our forward-looking statements are reasonable, but we can give no assurance that they will prove to be correct. We caution you that these forward-looking statements can be affected by inaccurate assumptions and are subject to all the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, and sale of oil, natural gas liquids and natural gas. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in our 2018 Annual Report on Form 10-K.


  

Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

 


We caution you not to place undue reliance on these forward-looking statements, which speak only as of the date of this report, and we undertake no obligation to update this information to reflect events or circumstances after the filing of this report with the SEC, except as required by law. All forward-looking statements, expressed or implied, included in this Quarterly Report on Form 10-Q and attributable to us are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we may make or persons acting on our behalf may issue.

 

ITEM 3.Quantitative and Qualitative Disclosures About Market Risk

 

As a smaller reporting company, we are not required to provide the information otherwise required byfor this item.

 

ITEM 4.Controls and Procedures

 

Evaluation of disclosure controls and procedures.  

 

We have established disclosure controls and procedures to ensure that material information relating to us and our consolidated subsidiaries is made known to the officers who certify our financial reports and the Board of Directors.

 

Our Chief Executive Officer, Patrick R. McDonald, and our Chief Financial Officer, Kevin D. Struzeski, evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of the end of the period covered by this Quarterly Report on Form 10-Q (the “Evaluation Date”).September 30, 2019. Based on this evaluation, they believe that as of the Evaluation DateSeptember 30, 2019 our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (i) is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms; and (ii) is accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

 

Changes in internal control over financial reporting.  There were no changes in our internal control over financial reporting during the quarter ended March 31,September 30, 2019, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


33

 

PART II. OTHER INFORMATION

 

ITEM 1.Legal Proceedings

 

We are subject to legal claims and proceedings in the ordinary course of our business. Management believes that should the controversies be resolved against us, none of the current pending proceedings would have a material adverse effect on us.

 

ITEM 1A.Risk Factors

 

Risk factors relating to us are discussed in “Part I, Item 1A. Risk Factors” in our 2018 Annual Report. There have been no material changes fromto the risk factors previously disclosed in our 2018 Annual Report.Report on Form 10-K. 

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

None. 

 

ITEM 6.Exhibits

 

Exhibit No. Description
   
10.1 Second Amendment to the Amended and Restated Credit Agreement, among Carbon Appalachia Enterprises, LLC and Nytis Exploration (USA) Inc. and LegacyTexas Bank, dated December 31, 2018, incorporated by reference to Exhibit 10.2 to Form 8-K filed on January 7, 2019.
10.2Letter Amendment, dated December 31, 2018, to Membership Interest Purchase Agreement, dated as of May 4, 2018, by and among Old Ironsides Fund II-A Portfolio Holding Company, LLC, Old Ironsides Fund II-B Portfolio Holding Company, LLC, and Carbon Energy Corporation, incorporated by reference to Exhibit 10.1 to Form 8-K filed on January 7, 2019.
10.3Amendment to the Employment Agreement of Patrick R. McDonald, dated March 4,August 14, 2019,  incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 6,August 15, 2019.
10.410.2* Amendment to the Employment Agreement of Mark D. Pierce,Omnibus Annual Incentive Plan, dated March 4, 2019, incorporated by reference to Exhibit 10.2 to Form 8-K filed on March 6,August 9, 2019.
10.5Amendment to the Employment Agreement of Kevin D. Struzeski, dated March 4, 2019, incorporated by reference to Exhibit 10.3 to Form 8-K filed on March 6, 2019.
31.1* Certification of Chief Executive Officer Pursuant to Rule 13a-15(e) / Rule 15d-15(e).
31.2* Certification of Chief Financial Officer Pursuant to Rule 13a-14(a) / Rule 15(e)/15d-15(e).
32.1† Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002.
32.2† Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002.
101* Interactive data files pursuant to Rule 405 of Regulation S-T.

 

*Filed herewith
Not considered to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section

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.

 

 CARBON ENERGY CORPORATION
 (Registrant)
  
Date: MayNovember 13, 2019By:/s/ Patrick R. McDonald
  PATRICK R. MCDONALD,
  Chief Executive Officer
   
Date: MayNovember 13, 2019By:/s/ Kevin D. Struzeski
  KEVIN D. STRUZESKI
  Chief Financial Officer

 

 

35

47