Quarterly Report (10-q)

Date : 05/19/2017 @ 1:27PM
Source : Edgar (US Regulatory)
Stock : Carbon Natural Gas Company (QB) (CRBO)
Quote : 12.0  0.0 (0.00%) @ 7:59AM
Carbon Natural Gas Company share price Chart

Quarterly Report (10-q)

 

 

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 quarter ended March 31, 2017

 

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 NATURAL GAS COMPANY
(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) 407-7043

 

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

 

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).

 

YES  ☒                      NO  ☐

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting 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 filer       Smaller reporting company  
Accelerated filer     Emerging growth company  
Non-accelerated filer (Do not check if a smaller reporting company)    

  

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

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

 

YES  ☐                NO  ☒

 

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

 

At May 10, 2017, there were issued and outstanding 5,627,589 shares of the Company’s common stock, $0.01 par value.

 

 

 

 

 

 

Carbon Natural Gas Company

 

TABLE OF CONTENTS

 

Part I – FINANCIAL INFORMATION

 

Item 1. Consolidated Financial Statements  
   
Consolidated Balance Sheets (unaudited) 1
   
Consolidated Statements of Operations (unaudited) 2
   
Consolidated Statements of Stockholders’ Equity (unaudited) 3
   
Consolidated Statements of Cash Flows (unaudited) 4
   
Notes to the Consolidated Financial Statements (unaudited) 5
   
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations 20  
   
Item 4. Controls and Procedures 32
   
Part II – OTHER INFORMATION
   
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 33
   
Item 6. Exhibits 33

 

 

 

 

PART I. FINANCIAL INFORMATION

 

ITEM 1. Financial Statements

 

CARBON NATURAL GAS COMPANY

Consolidated Balance Sheets

 

    March 31,  2017     December 31,
2016
 
(in thousands, except share and per share data)   (Unaudited)        
ASSETS            
             
Current assets:            
Cash and cash equivalents   $ 630     $ 858  
Accounts receivable:                
Revenue     2,170       2,369  
Trade receivables     546       330  
Receivable – related party     200       -  
Other     435       1,921  
Prepaid expenses, deposits and other current assets     373       305  
Total current assets     4,354       5,783  
                 
Property and equipment (note 4):                
Oil and gas properties, full cost method of accounting;                
Proved, net     33,063       33,212  
Unproved     1,966       1,999  
Other property and equipment, net     326       325  
Total property and equipment, net     35,355       35,536  
                 
Investments in affiliates (note 5)     6,444       668  
Other long-term assets     1,273       725  
                 
Total assets   $ 47,426     $ 42,712  
                 
LIABILITIES AND STOCKHOLDERS’ EQUITY                
                 
Current liabilities:                
Accounts payable and accrued liabilities   $ 7,672     $ 9,121  
Commodity derivative liability     311       1,341  
Firm transportation contract obligations (note 12)     452       561  
Total current liabilities     8,435       11,023  
                 
Non-current liabilities:                
Firm transportation contract obligations (note 12)     230       261  
Commodity derivative liability     -       591  
Ad valorem taxes payable     610       628  
Warrant derivative liability     4,939       -  
Asset retirement obligations (note 2)     5,077       5,006  
Notes payable (note 6)     15,530       16,230  
Total non-current liabilities     26,386       22,716  
                 
Commitments (note 12)                
                 
Stockholders’ equity:                
Preferred stock, $0.01 par value; authorized 1,000,000 shares, no shares issued and outstanding at March 31, 2017 and December 31, 2016     -       -  
Common stock, $0.01 par value; authorized 200,000,000 shares, 5,525,756 and 5,482,673 shares issued and outstanding at March 31, 2017 and December 31, 2016, respectively     1,097       1,096  
Additional paid-in capital     56,866       56,548  
Accumulated deficit     (47,244 )     (50,536 )
Total Carbon stockholders’ equity     10,719       7,108  
Non-controlling interests     1,886       1,865  
Total stockholders’ equity     12,605       8,973  
                 
Total liabilities and stockholders’ equity   $ 47,426     $ 42,712  

 

See accompanying notes to Consolidated Financial Statements.

 

  1  

 

 

CARBON NATURAL GAS COMPANY

Consolidated Statements of Operations

(Unaudited)

 

    Three Months Ended  
    March 31,  
(in thousands, except per share amounts)   2017     2016  
             
Revenue:            
Natural gas sales   $ 3,994     $ 1,092  
Oil sales     1,046       628  
Commodity derivative gain     2,144       140  
Other income     9       1  
Total revenue     7,193       1,861  
                 
Expenses:                
Lease operating expenses     1,205       589  
Transportation costs     489       372  
Production and property taxes     412       135  
General and administrative     1,670       1,523  
Depreciation, depletion and amortization     573       503  
Accretion of asset retirement obligations     78       35  
Impairment of oil and gas properties     -       3,890  
Total expenses     4,427       7,047  
                 
Operating income (loss )     2,766       (5,186 )
                 
Other income and (expense):                
Interest expense     (267 )     (57 )
Warrant derivative gain     830       -  
Equity investment income     7       -  
Total other income (expense)     570       (57 )
                 
Income (loss) before income taxes     3,336       (5,243 )
                 
Provision for income taxes     -       -  
                 
Net income (loss) before non-controlling interests     3,336       (5,243 )
                 
Net income (loss) attributable to non-controlling interests     44       (316 )
                 
Net income (loss) attributable to controlling interest   $ 3,292     $ (4,927 )
                 
Net income (loss) per common share:                
Basic   $ 0.60     $ (0.92 )
Diluted   $ 0.40     $ (0.92 )
Weighted average common shares outstanding:                
Basic     5,487       5,359  
Diluted     6,225       5,359  

 

See accompanying notes to Consolidated Financial Statements.

 

  2  

 

 

CARBON NATURAL GAS COMPANY

Consolidated Statement 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, 2016     5,482     $ 1,096     $ 56,548     $ 1,865     $ (50,536 )   $ 8,973  
                                                 
Stock-based compensation     -       -       319       -       -       319  
                                                 
Restricted stock vested     43       1       (1 )     -       -       -  
                                                 
Non-controlling interest distributions, net     -       -       -       (23 )     -       (23 )
                                                 
Net income     -       -       -       44       3,292       3,336  
                                                 
Balances, March 31, 2017     5,525     $ 1,097     $ 56,866     $ 1,886     $ (47,244 )   $ 12,605  

 

See accompanying notes to Consolidated Financial Statements.

 

  3  

 

 

CARBON NATURAL GAS COMPANY

Consolidated Statements of Cash Flows

(Unaudited)

 

    Three Months Ended  
    March 31,  
(in thousands)   2017     2016  
             
Cash flows from operating activities:            
Net income (loss)   $ 3,336     $ (5,243 )
Items not involving cash:                
Depreciation, depletion and amortization     573       503  
Accretion of asset retirement obligations     78       35  
Impairment of oil and gas properties     -       3,890  
Unrealized commodity derivative (gain) loss     (2,167 )     62  
Warrant derivative gain     (830 )     -  
Stock-based compensation expense     319       371  
Equity investment income     (7 )     -  
Other     (36 )     -  
Net change in:                
Accounts receivable     1,268       320  
Prepaid expenses, deposits and other current assets     (67 )     (39 )
Accounts payable, accrued liabilities and firm transportation obligations     (1,573 )     (163 )
Net cash provided (used in) operating activities     894       (264 )
                 
Cash flows from investing activities:                
Development and acquisition of properties and equipment     (396 )     (262 )
Other long-term assets     (3 )     5  
Equity investment     -       275  
Net cash (used in) provided by investing activities     (399 )     18  
                 
Cash flows from financing activities:                
Proceeds from notes payable     300       600  
Payments on notes payable     (1,000 )     (200 )
Distributions to non-controlling interests     (23 )     (3 )
Net cash (used in) provided by financing activities     (723 )     397  
                 
Net (decrease) increase in cash and cash equivalents     (228 )     151  
                 
Cash and cash equivalents, beginning of period     858       305  
                 
Cash and cash equivalents, end of period   $ 630     $ 456  

 

See accompanying notes to Consolidated Financial Statements.

 

  4  

 

 

Note 1 – Organization

 

Carbon Natural Gas Company (“Carbon” or the “Company”) is an independent oil and gas company engaged in the exploration, development and production of oil and natural gas in the United States. The Company’s business is comprised of the assets and properties of Nytis Exploration (USA) Inc. (“Nytis USA”) and its subsidiary Nytis Exploration Company LLC (“Nytis LLC”) which conducts the Company’s operations in the Appalachian and Illinois Basins, in addition to its subsidiary, Carbon California Operating Company, LLC which conducts the Company’s operations in California and the Company’s equity investment in Carbon California Company, LLC. Collectively, Carbon California Operating Company, LLC and Carbon California Company, LLC are referred to as Carbon California and collectively Carbon, Nytis USA, Nytis LLC and Carbon California are referred to as the Company.

 

Note 2 – Summary of Significant Accounting Policies

 

Basis of Presentation

 

The accompanying unaudited Consolidated Financial Statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In the opinion of management, the accompanying unaudited Consolidated Financial Statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of March 31, 2017 and the Company’s results of operations and cash flows for the three months ended March 31, 2017 and 2016. Operating results for the three months ended March 31, 2017 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for oil and natural gas, natural production declines, the uncertainty of exploration and development drilling results and other factors. For a more complete understanding of the Company’s operations, financial position and accounting policies, the unaudited Consolidated Financial Statements and the notes thereto should be read in conjunction with the Company’s audited Consolidated Financial Statements for the year ended December 31, 2016 filed on Form 10-K with the Securities and Exchange Commission (“SEC”).

 

In the course of preparing the unaudited Consolidated Financial Statements, management makes various assumptions, judgments and estimates to determine the reported amount of assets, liabilities, revenue and expenses and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and accordingly, actual results could differ from amounts initially established.

 

Principles of Consolidation

 

The Consolidated Financial Statements include the accounts of Carbon, Nytis USA and its consolidated subsidiary. Carbon owns 100% of Nytis USA. Nytis USA owns approximately 99% of Nytis LLC.

 

Nytis LLC also holds an interest in various oil and gas partnerships. For partnerships where the Company has a controlling interest, the partnerships are consolidated. The Company is currently consolidating on a pro-rata basis 46 partnerships. In these instances, the Company reflects the non-controlling ownership interest in partnerships and subsidiaries as non-controlling interests on its Consolidated Statements of Operations and also reflects the non-controlling ownership interests in the net assets of the partnerships as non-controlling interests within stockholders’ equity on its Consolidated Balance Sheets. All significant intercompany accounts and transactions have been eliminated.

 

In accordance with established practice in the oil and gas industry, the Company’s unaudited Consolidated Financial Statements also include its pro-rata share of assets, liabilities, income, lease operating costs and general and administrative expenses of the oil and gas partnerships in which the Company has 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 the Company has the ability to significantly influence the operating decisions of the investee. When the Company does 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 Consolidated Financial Statements.

 

  5  

 

 

Note 2 – Summary of Significant Accounting Policies (continued)

 

Accounting for Oil and Gas Operations

 

The Company uses 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 whether or not proved reserves can be assigned to such properties. The Company assesses its 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 existing completion interval, are charged to expense as incurred.

 

The Company performs 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 price 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 book and tax basis of oil 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, 2017, the Company did not recognize a ceiling test impairment as the Company’s full cost pool did not exceed the ceiling limitation. For the three months ended March 31, 2016, the Company recognized a ceiling test impairment of approximately $3.9 million as the Company’s full cost pool exceeded its ceiling limitation. Future declines in oil and natural gas prices, and increases in future operating expenses and future development costs could result in additional impairments of our oil and gas properties in future periods. The effects of low commodity prices may continue to impact the ceiling test value until such time prices stabilize or improve. Impairment charges are a non-cash charge and accordingly, do not affect cash flow, but adversely affect our net income and stockholders’ equity.

 

Investments in Affiliates

 

Investments in non-consolidated affiliates are accounted for under either the equity or cost method of accounting as appropriate. The cost method of accounting is used for investments in affiliates in which the Company has 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 does 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 the Company holds between 20% and 50% of the voting interest in non-consolidated corporate affiliates or greater than a 3% to 5% interest of a partnership or limited liability company and exercises significant influence or control, the equity method of accounting is used to account for the investment. The Company’s investment in affiliates that is accounted for using the equity method of accounting, increases or decreases by the Company’s share of the affiliate’s profits or losses and such profits or losses are recognized in the Company’s Consolidated Statements of Operations. The Company reviews equity method investments for impairment whenever events or changes in circumstances indicate that an other than temporary decline in value has occurred. The amount of the impairment is based on quoted market prices, where available, or other valuation techniques.

 

  6  

 

 

Note 2 – Summary of Significant Accounting Policies (continued)

 

Related Party Transactions

 

On February 15, 2017, the Company entered into an amended and restated limited liability company agreement of Carbon California. Pursuant to the limited liability agreement, the Company was reimbursed $575,000 from Carbon California for due diligence costs incurred on behalf of Carbon California and allocated general and administrative expense in connection with its role of manager of Carbon California. This amount was recorded as a reduction of general and administrative expenses for the three months ended March 31, 2017. See Note 5 for additional information.

 

Warrant Derivative Liability

 

The Company issued a warrant related to its investment in Carbon California. The Company accounts for this warrant in accordance with guidance contained in ASC 815, Derivatives and Hedging , which requires this warrant to be recorded on the balance sheet as either an asset or a liability measured at its fair value, with changes in fair value recognized in earnings. Based on this guidance, the Company determined that the Company’s warrant does not meet the criteria for classification as equity. Accordingly, the Company classified the warrant as a liability. The warrant is subject to remeasurement at each balance sheet date, with any change in the fair value recognized as a component of other income or expense, net in the statement of operations.

 

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.

 

The following table is a reconciliation of the ARO for the three months ended March 31, 2017 and 2016:

 

(in thousands)   Three Months Ended
March 31,
 
    2017     2016  
Balance at beginning of period   $ 5,120     $ 3,095  
Accretion expense     78       35  
Additions during period     3       5  
      5,201       3,135  
Less: ARO recognized as a current liability     (124 )     -  
                 
Balance at end of period   $ 5,077     $ 3,135  

 

  7  

 

 

Note 2 – Summary of Significant Accounting Policies (continued)

 

Earnings Per Common Share

 

Basic earnings or loss per common share is computed by dividing the net income or loss attributable to common shareholders for the period by the weighted average number of common shares outstanding during the period. The shares of restricted common stock granted to certain officers, directors and employees of the Company are included in the computation of basic net income or loss 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 the Company with the proceeds from the exercise of warrants (which were assumed to have been made at the average market price of the common shares during the reporting period).

 

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

 

in thousands except per share amounts   Three Months Ended
March 31,
 
    2017     2016  
Basic Earnings (Loss) per Share            
Net income (loss)available to common shareholders, basic   $ 3,292     $ (4,927 )
Weighted average shares outstanding, basic     5,487       5,359  
                 
Net income (loss) per common share, basic   $ 0.60     $ (0.92 )
                 
Diluted Earnings (Loss) per Share                
Net income (loss)available to common shareholders, basic   $ 3,292     $ (4,927 )
Less: decrease in fair value of warrant     (830 )     -  
Adjusted net income (loss) available to common shareholders, diluted   $ 2,462     $ (4,927 )
                 
Weighted average shares outstanding, basic     5,487       5,359  
Add: dilutive effects of warrant and nonvested shares of restricted stock     738       -  
Weighted-average shares outstanding, diluted     6,225       5,359  
                 
Net income (loss) per common share, diluted   $ 0.40     $ (0.92 )

 

For the quarter ended March 31, 2017, the Company had net income and the diluted net income per share calculation for that period includes the dilutive effect of approximately 306,000 non-vested shares of restricted stock and approximately 432,000 in-the-money warrants. In addition, approximately 13,000 out-of-the-money warrants and approximately 296,000 restricted performance units, subject to future contingencies, were excluded from the basic and diluted loss per share calculations.

 

For the quarter ended March 31, 2016, the Company had a net loss and therefore, the diluted net loss per share calculation for that period excludes the anti-dilutive effect of approximately 13,000 warrants and approximately 289,000 non-vested shares of restricted stock. In addition, approximately 296,000 restricted performance units, subject to future contingencies, were excluded from the basic and diluted loss per share calculations.

 

  8  

 

 

Note 2 – Summary of Significant Accounting Policies (continued)

 

Adopted and Recently Issued Accounting Pronouncements

 

In March 2016, the FASB issued Accounting Standards Update No. 2016-09, Improvements To Employee Share-Based Payment Accounting (“ASU 2016-09”). The objective of this ASU is to simplify several aspects of the accounting for employee share-based payment transactions, including income tax consequences, classification of awards as either equity or liabilities and classification in the statement of cash flows. ASU 2016-09 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. Portions of this ASU must be applied prospectively while other portions may be applied either prospectively or retrospectively. The Company adopted this standard on January 1, 2017.

 

In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (“ASU 2016-02”). The objective of this ASU is to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. ASU 2016-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 and should be applied using a modified retrospective approach. Early adoption is permitted. The Company is currently evaluating the impact on its consolidated financial statements of adopting ASU 2016-02.

 

In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The objective of ASU 2014-09 is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The FASB subsequently issued ASU 2015-14, ASU 2016-08, ASU 2016-10, ASU 2016-20, which deferred the effective date of ASU 2014-09 and provided additional implementation guidance. These ASUs are effective for fiscal years, and interim periods within those years beginning after December 31, 2017. The standards permit retrospective application using either of the following methodologies: (1) restatement of each prior reporting period presented or (ii) recognition of a cumulative-effect adjustment as of the date of initial application. The Company plans to adopt these ASUs effective January 1, 2018. Although the Company is still in the process of assessing its contracts with customers and evaluating the effect of adopting these standards, as well as the transition method to be applied, the adoption is not expected to have a significant impact on the Company’s consolidated financial statements other than additional disclosures.

 

Note 3 – Acquisitions and Divestitures

 

In October 2016, Nytis LLC completed an acquisition (the “EXCO Acquisition”) consisting of producing natural gas wells and natural gas gathering facilities located in the Company’s Appalachian Basin operating area. The natural gas gathering facilities are primarily used to gather the Company’s natural gas production. The acquisition was pursuant to a purchase and sale agreement, effective October 1, 2016 (the “EXCO Purchase Agreement”) by and among EXCO Production Company (WV), LLC, BG Production Company (WV), LLC and EXCO Resources (PA) LLC (collectively, the “Sellers”) and Nytis LLC, as the buyer. The purchase price of the acquired assets pursuant to the EXCO Purchase Agreement was $9.0 million subject to customary closing adjustments plus certain assumed obligations.

 

The EXCO Acquisition provided the Company with proved developed reserves, production and operating cash flow in a location where the Company has similar assets.

 

EXCO Acquisition Unaudited Pro Forma Results of Operations

 

Below are consolidated results of operations for the quarters ended March 31, 2017 and 2016 as though the EXCO Acquisition had been completed as of January 1, 2016. The EXCO Acquisition closed October 3, 2016, and accordingly, the Company’s consolidated statement of operations for the quarter ended March 31, 2017 includes the results of operations for the three months ended March 31, 2017 of the EXCO properties acquired.

 

    Unaudited Pro Forma Consolidated Results  
    For Three Months Ended
March 31,
 
(in thousands, except per share amounts)   2017     2016  
Revenue   $ 7,193     $ 2,880  
Net income (loss) before non-controlling interests     3,336       (2,520 )
Net income (loss) attributable to non-controlling interests     44       (316 )
Net income (loss) attributable to controlling interests     3,292       (2,204 )
Net income (loss) income per share (basic)     0.60       (0.41 )
Net income (loss) income per share (diluted)     0.40       (0.41 )

 

  9  

 

 

Note 4 – Property and Equipment

 

Net property and equipment as of March 31, 2017 and December 31, 2016 consists of the following:

 

(in thousands)   March 31,
2017
    December 31,
2016
 
             
Oil and gas properties:            
Proved oil and gas properties   $ 112,155     $ 111,771  
Unproved properties not subject to depletion     1,966       1,999  
Accumulated depreciation, depletion, amortization and impairment     (79,092 )     (78,559 )
Net oil and gas properties     35,029       35,211  
                 
Furniture and fixtures, computer hardware and software, and other equipment     1,000       990  
Accumulated depreciation and amortization     (674 )     (665 )
Net other property and equipment     326       325  
                 
Total net property and equipment   $ 35,355     $ 35,536  

 

As of March 31, 2017 and December 31, 2016, the Company had approximately $2.0 million of unproved oil and gas properties not subject to depletion. The costs not subject to depletion relate to unproved properties that are excluded from amortized capital costs until it is determined whether or not proved reserves can be assigned to such 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 costs is expected to be completed within five years.

 

During the three months ended March 31, 2017 and 2016, the Company capitalized general and administrative expenses applicable to development and exploration activities of approximately $75,000 and $133,000, respectively.

 

Depletion expense related to oil and gas properties for the three months ended March 31, 2017 and 2016 was approximately $533,000, or $0.41 per Mcfe, and $472,000, or $0.79 per Mcfe, respectively. Depreciation and amortization expense related to furniture and fixtures, computer hardware and software and other equipment for the three months ended March 31, 2017 and 2016 was approximately $40,000 and $31,000, respectively.

 

Note 5 – Equity Method Investment

 

The Company has a 50% interest in Crawford County Gas Gathering Company, LLC (“CCGGC”) which owns and operates pipelines and related gathering and treatment facilities. The Company’s gas production located in Illinois is gathered by CCGGC’s gathering facilities. The Company’s investment in CCGGC is accounted for under the equity method of accounting, and its share of income or loss is recognized. During the three months ended March 31, 2017 and 2016, the Company recorded equity method income of approximately $7,000 and nil, respectively, related to this investment. During the first quarter of 2016, the Company received a cash distribution of $275,000 from CCGGC.

 

On February 15, 2017, the Company entered into an amended and restated limited liability company agreement (the “Carbon California LLC Agreement”) of Carbon California, a Delaware limited liability company established by the Company. Pursuant to the Carbon California LLC Agreement, Carbon acquired a 17.8% interest in Carbon California represented by Class B Units. The Class B Units were acquired for no cash consideration.

 

On February 15, 2017, Carbon California (i) issued and sold Class A Units to two institutional investors for an aggregate cash consideration of $22.0 million, (ii) entered into a Note Purchase Agreement (the “Note Purchase Agreement” ) with two institutional investors for the issuance and sale of up to $25.0 million of Senior Secured Revolving Notes (the “Senior Revolving Notes” ) due February 15, 2022 and (iii) entered into a Securities Purchase Agreement (the “ Securities Purchase Agreement” ) with one institutional investor for the issuance and sale of $10.0 million of Senior Subordinated Notes (the “Subordinated Notes” ) due February 15, 2024. The Company is not a guarantor of the Senior Revolving Notes or the Subordinate Notes. The closing of the Note Purchase Agreement and the Securities Purchase Agreement on February 15, 2017, resulted in the sale and issuance by Carbon California of (i) Senior Revolving Notes in the principal amount of $10.0 million and (ii) Subordinated Notes in the original 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. The current borrowing base is $15.0 million.

 

  10  

 

 

Note 5 – Equity Method Investment (continued)

 

Net proceeds from the Offering Transaction were used by Carbon California to complete the acquisitions of oil and gas assets in the Ventura Basin of California, which acquisitions also closed on February 15, 2017. The remainder of the net proceeds are being used to fund field development projects and to fund future complementary acquisitions and for general working capital purposes of Carbon California.

 

In connection with the Company entering into the Carbon California LLC Agreement described above and Carbon California engaging in the transactions also described above, the Company issued to an affiliate of one of the institutional investors which purchased Class A Units of Carbon California (which is also an affiliate of the Company’s largest stockholders), a warrant to purchase approximately 1.5 million shares of the Company’s common stock at an exercise price of $7.20 per share (the “Warrant”). The exercise price for the Warrant is payable exclusively with Class A Units of Carbon California and the number of shares of the Company’s common stock for which the Warrant is exercisable is determined, as of the time of exercise, by dividing (a) the aggregate unreturned capital of the warrantholder’s Class A Units of Carbon California by (b) the exercise price. The Warrant has a term of seven years and includes certain standard registration rights with respect to the shares of the Company’s common stock issuable upon exercise of the Warrant.

 

Based on its 17.8% interest in Carbon California and its role of manager of Carbon California, the Company is accounting for its investment in Carbon California under the equity method of accounting. For the period of February 15, 2017 through March 31, 2017, Carbon California had a net loss. Once Carbon California reports income, the Company will not record income (or losses) until the Company’s share of such income equals the amount of its share of losses not previously reported.

 

The Company accounts for the Warrant as the initial investment in Carbon California and a liability based on the fair value of the Warrant as of the date of grant (February 15, 2017). Future changes to the fair value of the Warrant will be recognized in earnings.

 

As of grant date of the Warrant, the Company estimated that the fair market value of the Warrant was approximately $5.8 million and recorded that amount to its investment in Carbon California and a long-term liability. This valuation is preliminary and may change in future time periods. As of March 31, 2017, the Company estimated that the fair value of the Warrant was approximately $4.9 million. The difference in the fair value of the Warrant from the grant date though March 31, 2017 was approximately $830,000 and was recognized in other income in the Company’s Consolidated Statements of Operations for the three months ended March 31, 2017.

 

Note 6 – Bank Credit Facility

 

In 2016, Carbon entered into a 4-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank. LegacyTexas Bank is the initial lender and acts as administrative agent.

 

The credit facility has a maximum availability of $100.0 million (with a $500,000 sublimit for letters of credit), which availability is subject to the amount of the borrowing base. The initial borrowing base established under the credit facility was $17.0 million. The borrowing base is subject to semi-annual redeterminations in March and September commencing March 2017. On March 30, 2017, the borrowing base was increased to $23.0 million.

 

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Note 6 – Bank Credit Facility (continued)

 

The credit facility is guaranteed by each existing and future direct or indirect subsidiary of Carbon (subject to certain exceptions). The obligations of Carbon and the subsidiary guarantors under the credit facility are secured by essentially all tangible and intangible personal and real property of the Company (subject to certain exclusions).

 

Interest is payable quarterly and accrues on borrowings under the credit facility at a rate per annum equal to either (i) the base rate plus an applicable margin between 0.50% and 1.50% or (ii) the Adjusted LIBOR rate plus an applicable margin between 3.50% and 4.50% at Carbon’s option. The actual margin percentage is dependent on the credit facility utilization percentage. Carbon is obligated to pay certain fees and expenses in connection with the credit facility, including a commitment fee for any unused amounts of 0.50%.

 

The credit facility contains certain affirmative and negative covenants that, among other things, limit the Company’s ability to (1) 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 its affiliates; (viii) enter into sales-leaseback transaction; (ix) make optional or voluntary payment of debt; (x) change the nature of its business; (xi) change its 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 certain basket amounts and acceptable transaction levels. In addition, the credit facility requires Carbon’s compliance, on a consolidated basis, with (i) maximum funded Debt/EBITDA ratio of 3.5 to 1.0 and (ii) a minimum current ratio of 1.0 to 1.0, commencing with the quarter ended March 31, 2017. The Company was in compliance with the financial covenants associated with the credit facility as of March 31, 2017.

 

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

 

As required under the terms of the credit facility, the Company established pricing for a certain percentage of its production through the use of derivative contracts. The Company is party to an ISDA Master Agreement 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 the Company and BP Energy Company is secured by the collateral and backed by the guarantees supporting the credit facility.

 

As of March 31, 2017, there were approximately $15.5 million in outstanding borrowings and approximately $7.5 million of additional borrowing capacity available under the credit facility. The Company’s effective borrowing rate at March 31, 2017 was approximately 5.75%.

 

Note 7 – Income Taxes

 

The Company recognizes 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. The Company has 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, 2017, the Company has established a full valuation allowance against the balance of net deferred tax assets.

 

  12  

 

 

Note 8 – 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.

 

As of March 31, 2017, the Company had 200,000,000 shares of common stock authorized with a par value of $0.01 per share, of which approximately 5.5 million were issued and outstanding and 1,000,000 shares of preferred stock authorized with a par value of $0.01 per share, none of which were issued and outstanding. During the first three months of 2017, the increase in the Company’s issued and outstanding common stock was a result of restricted stock that vested during the period.

 

Equity Plans Prior to Merger

 

Pursuant to the merger of Nytis USA with and into the Company in 2011, all options, warrants and restricted stock were adjusted to reflect the conversion ratio used in the merger. As of March 31, 2017, the Company has 12,500 warrants outstanding and exercisable related to these plans.

 

Nytis USA Restricted Stock Plan

 

As of March 31, 2017, all of restricted stock issued under the Nytis USA Restricted Stock Plan (“Nytis USA Plan”) have vested. The Company accounted for these grants at their intrinsic value. From the date of grant through March 31, 2013, the Company estimated that none of these shares would vest and accordingly, no compensation cost had been recorded through March 31, 2013.

 

In June 2013, the vesting terms of these restricted stock grants were modified so that 25% of the shares would vest on the first of January from 2014 through 2017. As such, the Company recognized compensation expense for those restricted stock grants based on the fair value of the shares on the date the vesting terms were modified. Compensation expense recognized for those restricted stock grants was nil and approximately $84,000 for the three months ended March 31, 2017 and 2016, respectively. As of March 31, 2017, compensation costs relative to those restricted stock grants were fully recognized.

 

Carbon Stock Incentive Plans

 

The Company has two stock plans, the Carbon 2011 and 2015 Stock Incentive Plans (collectively the “Carbon Plans”). The Carbon Plans were approved by the shareholders of the Company and in the aggregate provide for the issuance of approximately 1.1 million shares of common stock to Carbon officers, directors, employees or consultants eligible to receive these awards under the Carbon Plans.

 

The Carbon Plans provide for granting Director Stock Awards to non-employee directors and for granting Incentive Stock Options, Non-qualified Stock Options, Restricted Stock Awards, Performance Awards and Phantom Stock Awards, or a combination of the foregoing, as is best suited to the circumstances of the particular employee, officer, director or consultant.

 

Restricted Stock

 

During the three months ended March 31, 2017, approximately 81,000 shares of restricted stock were granted under the terms of the Carbon Plan in addition to 462,000 shares granted during previous years. For employees, these restricted stock awards either vest ratably over a three-year service period or cliff vest after a three year service period. For non-employee directors the awards vest upon the earlier of a change in control of the Company or the date their membership on the Board of Directors is terminated other than for cause. The Company recognizes compensation expense for these restricted stock grants based on the estimated grant date fair value of the shares, amortized ratably over three years for employee awards (based on the required service period for vesting) and seven years for non- employee director awards (based on a market survey of the average tenure of directors among U.S. public companies). As of March 31, 2017, approximately 236,000 of these restricted stock grants have vested.

 

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Note 8 – Stockholders’ Equity (continued)

 

Restricted Stock (continued)

 

Compensation costs recognized for these restricted stock grants were approximately $188,000 and $201,000 for the three months ended March 31, 2017 and 2016, respectively. As of March 31, 2017, there was approximately $1.1 million of unrecognized compensation costs related to these restricted stock grants. This cost is expected to be recognized over the next six years.

 

Restricted Performance Units

 

As of March 31, 2017, approximately 401,000 shares of restricted performance units have been granted under the terms of the Carbon Plan. The performance units represent a contractual right to receive one share of the Company’s 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 for the Company as well as the lapse of forfeiture restrictions pursuant to the terms and conditions of the agreements, including for certain of the grants, the requirement of continuous employment by the grantee prior to a change in control of the Company. Based on the relative achievement of performance, approximately 296,000 restricted performance units are outstanding as of March 31, 2017.

 

The Company accounts for the performance units granted during 2012 and 2014 through 2016 at their fair value determined at the date of grant. The final measurement of compensation cost will be based on the number of performance units that ultimately vest. At March 31, 2017, the Company estimated that none of the performance units granted in 2012 and 2016 would vest due to change in control and other performance provisions and accordingly, no compensation cost has been recorded for these performance units. At September 30, 2016, the Company estimated that it was probable that certain of the performance units granted in 2014 and 2015 would vest. Compensation costs of approximately $132,000 and nil related to these performance units were recognized for the three months ended March 31, 2017 and 2016, respectively. As of March 31, 2017, if change in control and other performance provisions pursuant to the terms and conditions of these agreements are met in full, the estimated unrecognized compensation cost related to the performance units granted in 2012 and 2014 through 2016 would be approximately $1.9 million.

 

The performance units granted in 2013 contain specific vesting provisions, no change in control provisions nor any performance conditions other than stock price performance. Due to different earning requirements compared to the performance units granted in 2012 and 2014 through 2016, the Company recognized compensation expense for the performance units granted in 2013 based on the grant date fair value of the performance units, amortized ratably over three years (the performance period). The fair value of the performance units granted in 2013 was estimated using a Monte Carlo simulation (“MCS”) valuation model using the following key assumptions: no expected dividends, volatility of our stock and those of defined peer companies used to determine our performance relative to the defined peer group, a risk free interest rate and an expected life of three years. Compensation costs recognized for these performance unit grants were approximately nil and $86,000 for the three months ended March 31, 2017 and 2016, respectively. As of March 31, 2017, compensation costs relative to these performance units have been fully recognized.

 

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Note 9 – Accounts Payable and Accrued Liabilities

 

Accounts payable and accrued liabilities at March 31, 2017 and December 31, 2016 consist of the following:

 

(in thousands)   March 31, 2017     December 31,
2016
 
             
Accounts payable   $ 1,973     $ 2,315  
Oil and gas revenue payable to oil and gas property owners     1,918       1,415  
Gathering and transportation payables     423       468  
Production taxes payable     201       113  
Drilling advances received from joint venture partner     140       955  
Accrued drilling costs     -       4  
Accrued lease operating costs     185       282  
Accrued ad valorem taxes     1,315       1,552  
Accrued general and administrative expenses     1,117       1,572  
Accrued interest     189       184  
Other liabilities     211       261  
                 
Total accounts payable and accrued liabilities   $ 7,672     $ 9,121  

 

Note 10 – 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 the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available under 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. The Company’s policy is to recognize transfers in and/or out of the fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Company has consistently applied the valuation techniques discussed below for all periods presented.

 

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Note 10 – Fair Value Measurements (continued)

 

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2017 and December 31, 2016 by level within the fair value hierarchy:

 

(in thousands)   Fair Value Measurements Using  
    Level 1     Level 2     Level 3     Total  
March 31, 2017                        
Assets:                        
Commodity derivatives   $ -     $ 546     $ -     $ 546  
Liabilities:                                
Commodity derivatives   $ -     $ 311     $ -     $ 311  
Warrant derivative   $ -     $ -     $ 4,939     $ 4,939  
                                 
December 31, 2016                                
Liabilities:                                
Commodity derivatives   $ -     $ 1,932     $ -     $ 1,932  

 

As of March 31, 2017, the Company’s commodity derivative financial instruments are comprised of eight natural gas and nine oil swap agreements. The fair values of these agreements are determined under an income valuation technique. The valuation requires a variety of inputs, including contractual terms, published forward prices, volatilities for options, and discount rates, as appropriate. The Company’s estimates of fair value of derivatives include consideration of the counterparty’s credit worthiness, the Company’s credit worthiness and the time value of money. The consideration of these factors resulted in an estimated exit-price for each derivative asset or liability under a market place participant’s view. All of the significant inputs are observable, either directly or indirectly; therefore, the Company’s derivative instruments are included within the Level 2 fair value hierarchy. The counterparty for all of the Company’s commodity financial instruments as of March 31, 2017 is BP Energy Company.

 

Level 3 Fair Value Measurements

 

A third-party valuation specialist is utilized to determine the fair value of the Company’s warrant designated as Level 3. The Company reviews this valuation, including the related model inputs and assumptions, and analyzes changes in fair value measurements between periods. The Company corroborates such inputs, calculations and fair value changes using various methodologies, and reviews unobservable inputs for reasonableness utilizing relevant information from other published sources.

 

The Company estimated the fair value of the Company’s warrant designated as Level 3 on February 15, 2017, the grant date of the warrant, to be approximately $5.8 million, using a call option pricing model with the following assumptions: a seven-year term, exercise price of $7.20, volatility rate of 41.8% and a risk free rate of 2.3%. The Company remeasured the warrant as of March 31, 2017, using the same call option pricing model, using the following assumptions: a term of 6.9 years, exercise price of $7.20, volatility rate of 39.3% and a risk free rate of 2.2%. As of March 31, 2017, the fair value of the warrant was approximately $4.9 million.

 

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

 

The fair value of the following 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 Company uses 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. During the three months ended March 31, 2017 and 2016, the Company recorded asset retirement obligations for additions of approximately $3,000 and $5,000 respectively. See Note 2 for additional information.

 

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Note 11 – Physical Delivery Contracts and Oil and Gas Derivatives

 

The Company has historically used commodity-based derivative contracts to manage exposures to commodity price on certain of its oil and natural gas production. The Company does not hold or issue derivative financial instruments for speculative or trading purposes. The Company also enters 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. Therefore, these contracts are not recorded at fair value in the unaudited Consolidated Financial Statements.

 

Pursuant to the terms of the Company’s credit facility with LegacyTexas Bank, the Company has entered into swap derivative agreements to hedge certain of its oil and natural gas production for 2017 through 2019. As of March 31, 2017, these derivative agreements consisted of the following:

 

    Natural Gas     Oil  
          Weighted           Weighted  
          Average           Average  
Year   MMBtu     Price (a)     Bbl     Price (b)  
                         
2017     2,520,000     $ 3.30       45,000     $ 52.98  
2018     3,120,000     $ 3.01       48,000     $ 54.11  
2019     1,320,000     $ 2.85       36,000     $ 54.90  

 

(a) NYMEX Henry Hub Natural Gas futures contract for the respective delivery month.

(b) NYMEX Light Sweet Crude West Texas Intermediate futures contract for the respective delivery month

 

For its swap instruments, the Company receives a fixed price for the hedged commodity and pays 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.

 

The following table summarizes the fair value of the derivatives recorded in the unaudited Consolidated Balance Sheets.

 

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

 

(in thousands)   March 31,
2017
    December 31,
2016
 
Commodity derivative contracts:            
Current assets   $ -     $ -  
Non-current assets   $ 546     $ -  
                 
Current liabilities   $ 311     $ 1,341  
Non-current liabilities   $ -     $ 591  

 

The table below summarizes the commodity settlements and unrealized gains and losses related to the Company’s derivative instruments for the three months ended March 31, 2017 and 2016. These commodity derivative settlements and unrealized gains and losses are recorded and included in commodity derivative income or loss in the accompanying Consolidated Statements of Operations.

 

(in thousands)   Three Months Ended
March 31,
 
    2017     2016  
Commodity derivative contracts:            
Settlement (losses) gains   $ (23 )   $ 202  
Unrealized gains (losses)     2,167       (62 )
                 
Total settlement and unrealized gains (losses), net   $ 2,144     $ 140  

 

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Note 11 – Physical Delivery Contracts and Oil and Gas Derivatives (continued)

 

Commodity derivative settlement gains and losses are included in cash flows from operating activities in the Company’s unaudited Consolidated Statements of Cash Flows.

 

The counterparty in all of the Company’s derivative instruments is BP Energy Company. The Company has entered into an ISDA Master Agreement 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 the Company and BP Energy Company is secured by the collateral and backed by the guarantees supporting the credit facility.

 

The Company nets its derivative instrument fair value amounts executed with is its counterparty pursuant to an ISDA master agreement, which provides 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 location and fair value amounts of all derivative instruments in the unaudited Consolidated Balance Sheet, as well as the gross recognized derivative assets, liabilities and amounts offset in the unaudited Consolidated Balance Sheet as of March 31, 2017.

 

                    Net  
        Gross           Recognized  
        Recognized     Gross     Fair Value  
        Assets/     Amounts     Assets/  
    Balance Sheet Classification   Liabilities     Offset     Liabilities  
                       
Commodity derivative assets:                    
Current assets     $ 179     $ (179 )   $ -  
Other long-term assets       651       (105 )     546  
Total derivative assets     $ 830     $ (284 )   $ 546  
                           
Commodity derivative liabilities:                          
Current liability     $ 490     $ (179 )   $ 311  
Non-current liabilities       105       (105 )     -  
Total derivative liabilities     $ 595     $ (284 )   $ 311  

 

Due to the volatility of oil and natural gas prices, the estimated fair values of the Company’s derivatives are subject to large fluctuations from period to period.

 

Note 12 – Commitments

 

The Company has entered into employment agreements with certain executives and officers of the Company. The term of the agreements generally range from one to two years and provide 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.

 

The Company has entered into long-term firm transportation contracts to ensure the transport for certain of its gas production to purchasers. Firm transportation volumes and the related demand charges for the remaining term of these contracts at March 31, 2017 are summarized in the table below.

 

Period   Dekatherms per day     Demand Charges  
Apr 2016 - Apr 2018     5,530     $ 0.20 - $0.65  
May 2018 - May 2020     3,230     $ 0.20 - $0.62  
Apr 2020 – May 2020     2,150     $ 0.20  
Jun 2020 – May 2036     1,000     $ 0.20  

 

A liability of approximately $682,000 related to firm transportation contracts assumed in asset acquisitions, which represents the remaining commitment, is reflected on the Company’s unaudited Consolidated Balance Sheet as of March 31, 2017. The fair value 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 amortized on a monthly basis as the Company pays these firm transportation obligations in the future.

 

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Note 13 – Supplemental Cash Flow Disclosure

 

Supplemental cash flow disclosures for the three months ended March 31, 2017 and 2016 are presented below:

 

    Three Months Ended
March 31,
 
(in thousands)   2017     2016  
             
Cash paid during the period for:            
Interest   $ 216     $ 53  
Non-cash transactions:                
Increase in net asset retirement obligations   $ 3     $ 5  
(Decrease) increase in accounts payable and accrued liabilities included in oil and gas properties   $ (8 )   $ 38  

 

Note 14 – Subsequent Events

 

On April 3, 2017, the Company finalized a limited liability company agreement (the “Carbon Appalachia LLC Agreement” ) and the initial funding of Carbon Appalachian Company, LLC (“ Carbon Appalachia ”). Carbon Appalachia was formed by Carbon and two institutional investors to acquire producing assets in Southern Appalachia and has an initial equity commitment of $100.0 million.

 

Pursuant to the Carbon Appalachia LLC Agreement, Carbon acquired a 2.0% interest in Carbon Appalachia represented by Class A Units associated with its equity commitment of $2.0 million. Carbon also has the ability to earn up to an additional 20.0% of Carbon Appalachia (represented by Class B Units) after certain return thresholds to the holders of Class A Units are met. The Class B Units were acquired for no cash consideration.

 

In addition, Carbon acquired a 1.0% carried interest represented by Class C Units which were obtained in connection with the contribution to Carbon Appalachia of a portion of its working interest in undeveloped properties in Tennessee. If Carbon Appalachia agrees to drill horizontal Chattanooga Shale wells on these properties, it will pay 100% of the cost of drilling and completion of the first 20 wells to earn a 75% working interest in such properties. Carbon, through its subsidiary, Nytis LLC, will retain a 25% working interest in the properties.

 

In connection with and concurrently with the closing of the acquisition described below, Carbon Tennessee Company, LLC (“ Carbon Tennessee ”), an indirect subsidiary of Carbon Appalachia, entered into a 4-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank with an initial borrowing base of $10.0 million.

 

Borrowings under the credit facility, along with the initial equity contributions made to Carbon Appalachia, were used by Carbon Tennessee to complete the acquisition of natural gas producing properties and related facilities located predominantly in Tennessee (the “Acquisition” ). The Acquisition was structured such that Carbon Tennessee acquired all of the issued and outstanding equity of two of the seller’s subsidiaries that own natural gas producing properties and related facilities. The purchase price was $20.0 million, subject to normal and customary pre and post-closing adjustments, and Carbon Tennessee used $8.5 million drawn from the credit facility toward the purchase price.

 

In connection with the Company entering into the Carbon Appalachia LLC Agreement described above and Carbon Tennessee engaging in the Acquisition, the Company issued to an affiliate of one of the institutional investors which purchased Class A Units of Carbon Appalachia (which is also an affiliate of the Company’s largest stockholders), a warrant to purchase approximately 400,000 shares of the Company’s common stock at an exercise price of $7.20 per share. The exercise price for the warrant is payable exclusively with Class A Units of Carbon Appalachia and the number of shares of the Company common stock for which the warrant is exercisable is determined, as of the time of exercise, by dividing (a) the aggregate unreturned capital plus an internal rate of return on such capital of the warrantholder’s Class A Units of Carbon Appalachia by (b) the exercise price. The warrant has a term of seven years and includes certain standard registration rights with respect to the shares of Carbon’s common stock issuable upon exercise of the warrant. If exercised, the warrant provides Carbon an opportunity to increase its ownership stake in Carbon Appalachia without requiring the payment of cash.

 

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

 

General Overview

 

All expectations, forecasts, assumptions and beliefs about our future results, condition, operations and performance are forward-looking statements as described under the heading “ Forward Looking Statements ” at the end of this Item. Our actual results may differ materially because of a number of risks and uncertainties. The following discussion and analysis should be read in conjunction with the Company’s Consolidated Financial Statements and Notes thereto and the information included or incorporated by reference in the Company’s 2016 Annual Report on Form 10-K as filed with the Securities and Exchange Commission (“SEC”) under the headings “ Risk Factors ” and “ Management’s Discussion and Analysis of Financial Condition and Results of Operations .”

 

Carbon is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of oil and natural gas properties located in the United States. We focus on conventional and unconventional reservoirs, including shale, tight sands and coalbed methane. Our executive offices are located 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, 2017, our proved developed reserves were comprised of 7% oil and 93% natural gas. Our current capital expenditure program is focused on the acquisition of oil and natural gas properties and the development of our oil and coalbed methane reserves. We believe that our drilling inventory and lease position, combined with our low operating expense structure, 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:

 

Producing property and land acquisitions which provide attractive risk adjusted rates of return and complement our existing asset base; and
     
Development, optimization and maintenance of a portfolio of low risk, long-lived oil and natural gas properties that provide stable cash flows and attractive risk adjusted rates of return.

 

Our revenue, profitability and future growth rate depend on many factors which are beyond our control, such as 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. The following table highlights the quarterly average of NYMEX price trends for oil and natural gas prices for the last eight calendar quarters:

 

    2015     2016     2017  
    Q2     Q3     Q4     Q1     Q2     Q3     Q4     Q1  
                                                 
Oil (Bbl)   $ 57.96     $ 46.44     $ 42.17     $ 33.51     $ 45.60     $ 44.94     $ 49.33     $ 51.86  
Natural Gas (MMBtu)   $ 2.61     $ 2.74     $ 2.17     $ 2.06     $ 1.98     $ 2.93     $ 2.98     $ 3.07  

 

Although oil and natural gas prices have begun to recover from the lows experienced during the first quarter of 2016, forecasted prices for both oil and natural gas remain low. Lower oil and natural gas prices may not only decrease our revenues, but may also reduce the amount of oil and natural gas that the Company can produce economically and potentially lower our oil and natural gas reserves. The Company’s estimated proved reserves may decrease as the economic life of the underlying producing wells may be shortened as a result of lower oil and natural gas prices. A substantial or extended decline in oil 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.

 

The Company uses the full cost method of accounting for its oil and gas properties and performs a ceiling test quarterly. Because the ceiling calculation requires a rolling 12 month average commodity price, due to the effect of lower commodity prices in 2016, the Company recognized an impairment of approximately $4.3 million for the year ended December 31, 2016.

 

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Future write downs or impairments, if any, are difficult to reasonably 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 among other factors. There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in subsequent periods and the estimates described in this paragraph should not be construed as indicative of our future results.

 

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. Lower oil and natural gas prices may also reduce the amount of borrowing base under our bank credit facility, which is determined at the discretion of our lender and also may make it more difficult to comply with the covenants and other restrictions under our bank credit facility.

 

Future acquisitions or dispositions could have a material impact on our financial condition and results of operations by increasing or decreasing our reserves, production and revenues as well as expenses and future capital expenditures. We currently anticipate that we would finance any future acquisitions with available borrowings under our credit facility, sales of properties or the issuance of additional equity or debt.

 

Operational Highlights

 

Weakness in commodity prices has had a significant adverse impact on our results of operations, our debt balance and the amount of cash flow available to invest in exploration and development activities. Based on recent and expected future prices for oil and natural gas, we reduced our drilling activity to manage and optimize the utilization of our capital resources. During 2016 and for the three months ended March 31, 2017, other than the EXCO Acquisition, our development activities have consisted principally of optimizing our gathering facilities and marketing arrangements to provide greater flexibility in moving our natural gas production to markets with more favorable pricing.

 

At March 31, 2017, we had approximately 464,000 net acres of mineral leases located in the Appalachian and Illinois Basins of the United States. Approximately 68% of this acreage is held by production and of the remaining acreage, approximately 45% have lease terms of greater than five years remaining in the primary term or contractual extension periods.

 

In the Appalachia Basin, the principal focus of our leasing, drilling and completion activities is directed at a Berea Sandstone formation horizontal oil drilling program in eastern Kentucky and western West Virginia. As of March 31, 2017, we have over 40,000 net mineral acres in the region. Since 2010, we have drilled 55 horizontal wells in the program. During the program, we have enhanced our well performance, improved well drilling and completion performance, including reduced drilling days, increased horizontal lateral length, decreased cost per frac stage and reduced days from spud to first production. In addition, we have established an infrastructure of oil and natural gas gathering and salt water handling and disposal facilities which will benefit the economics of future drilling. We continue to acquire leases and producing properties where we have identified additional potential to expand our activities.

 

Another area of focus of our drilling and completion activities is the development of a coalbed methane resource located in the Illinois Basin. The Company has approximately 62,000 net mineral acres in Indiana and Illinois which are prospective for the development of coalbed methane. The Company also owns interests in natural gas gathering, compression and salt water disposal facilities. Since 2006, we have conducted a drilling program in the Seelyville coal formation, including participating as a 50% joint venture partner in the drilling of 36 vertical and two horizontal wells.

 

Our natural gas properties are largely held by production and contain a low risk multi-year development inventory of potential future drilling locations which, at the appropriate level of natural gas commodity price, will provide significant drilling and completion opportunities from multiple proven producing formations. During 2015, the Company participated in the drilling of 25 stratigraphic wells to identify potential future horizontal locations in the Seelyville coal formation.

 

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Recent Developments

 

Development of our oil properties and natural gas wells during 2017 is contingent on our expectation of future oil and natural gas prices. The Company is evaluating potential producing property and land acquisition opportunities in California and the Appalachian Basin that would expand the Company’s operations and provide attractive risk adjusted rates of returns.

 

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 fractured shares were issued. All references to the number of shares of common stock and per share amounts give retroactive effect to the reverse stock split for all periods presented.

 

Acquisitions and Equity Method Investments

 

In October 2016, Nytis LLC completed the EXCO Acquisition consisting of producing natural gas wells and natural gas gathering facilities located primarily in West Virginia. The acquisition was pursuant to a purchase and sale agreement, effective October 1, 2016, by and among EXCO Production Company (WV), LLC, BG Production Company (WV), LLC and EXCO Resources (PA) LLC (collectively, the “Sellers”) and Nytis LLC, as the buyer. The purchase price of the acquired assets pursuant to the EXCO Purchase Agreement was $9.0 million subject to customary closing adjustments plus certain assumed obligations.

 

The acquired assets significantly increased the natural gas production and reserves of the Company and are expected to increase cash flow, reduced general and administrative expenses (per unit of production) and provide an inventory of development projects. The acquired assets consisted of the following:

 

Approximately 2,300 natural gas wells and over 900 miles of associated natural gas gathering pipelines and compression facilities operated by the Company. As of March 31, 2017, these wells were producing approximately 9,000 net Mcfe per day (97% natural gas).

 

Average working and net revenue interest of the acquired wells of 94% and 79%, respectively.

 

Estimated proved developed producing reserves of approximately 46.4 Bcfe (97% natural gas).

 

Approximately 201,000 net acres of oil and natural gas mineral interests.

 

In connection with and concurrently with the closing of the EXCO Acquisition, Carbon entered into a 4-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank. Borrowings under the credit facility were used (i) to pay off and terminate Nytis LLC’s then existing credit facility, (ii) to pay the purchase price of the EXCO Acquisition, (iii) to pay costs and expenses associated with the acquisition and the credit facility and (iv) provide working capital for the Company. The initial borrowing base established under the credit facility was $17.0 million. The borrowing base is subject to semi-annual redeterminations in March and September, commencing March 2017. On March 30, 2017, the borrowing base was increased to $23.0 million.

 

On February 15, 2017, the Company entered into an amended and restated limited liability company agreement (the Carbon California LLC Agreement”) of Carbon California Company, LLC, a Delaware limited liability company (“Carbon California”) established by the Company. Pursuant to the Carbon California LLC Agreement, Carbon acquired a 17.8% interest in Carbon California represented by Class B Units. The Class B Units were acquired for no cash consideration. In connection with its role as the manager of Carbon California, $600,000 of general and administrative expenses on an annual basis is allocated and paid by Carbon California. The negotiation and diligence of the oil and gas acquisitions described below was led by the Company and at the closing of the acquisitions, the Company was reimbursed $500,000 for its time and expenditures related to such efforts.

 

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On February 15, 2017, Carbon California (i) issued and sold Class A Units to two institutional investors for an aggregate cash consideration of $22.0 million, (ii) entered into a Note Purchase Agreement (the “Note Purchase Agreement” ) with two institutional investors for the issuance and sale of up to $25.0 million of Senior Secured Revolving Notes (the “Senior Revolving Notes” ) due February 15, 2022 and (iii) entered into a Securities Purchase Agreement (the “ Securities Purchase Agreement” ) with one institutional investor for the issuance and sale of $10 million of Senior Subordinated Notes (the “Subordinated Notes” ) due February 15, 2024. The Company is not a guarantor of the Senior Revolving Notes or the Subordinate Notes. The closing of the Note Purchase Agreement and the Securities Purchase Agreement on February 15, 2017, resulted in the sale and issuance by Carbon California of (i) Senior Revolving notes in the principal amount of $10.0 million and (ii) Subordinated Notes in the original 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. The current borrowing base is $15.0 million.

 

Net proceeds from the Offering Transaction were used by Carbon California to complete the acquisitions of certain oil and gas assets in the Ventura Basin of California, which acquisitions also closed on February 15, 2017. The remainder of the net proceeds are being used to fund field development projects and to fund future complementary acquisitions and for general working capital purposes of Carbon California.

 

In connection with the Company entering into the Carbon California LLC Agreement described above and Carbon California engaging in the transactions also described above, the Company issued to an affiliate of one of the institutional investors which purchased Class A Units of Carbon California (which is also an affiliate of the Company’s largest stockholders), a warrant to purchase approximately 1.5 million shares of the Company’s common stock at an exercise price of $7.20 per share (the “Warrant”). The exercise price for the Warrant is payable exclusively with Class A Units of Carbon California and the number of shares of the Company’s common stock for which the Warrant is exercisable is determined, as of the time of exercise, by dividing (a) the aggregate unreturned capital of the warrantholder’s Class A Units of Carbon California by (b) the exercise price. The Warrant has a term of seven years and includes certain standard registration rights with respect to the shares of the Company’s common stock issuable upon exercise of the Warrant. If exercised, the Warrant provides the Company an opportunity to increase its ownership stake in Carbon California without requiring the payment of cash.

 

On April 3, 2017, the Company finalized a limited liability company agreement (the “ Carbon Appalachia LLC Agreement ”) and the initial funding of Carbon Appalachian Company, LLC (“ Carbon Appalachia ”). Carbon Appalachia was formed by Carbon and two institutional investors to acquire producing assets in Southern Appalachia and has an initial equity commitment of $100.0 million.

 

Pursuant to the Carbon Appalachia LLC Agreement, Carbon acquired a 2.0% interest in Carbon Appalachia represented by Class A Units associated with its equity commitment of $2.0 million. The Company will be the manager of Carbon Appalachia. Carbon also has the ability to earn up to an additional 20.0% of Carbon Appalachia (represented by Class B Units) after certain return thresholds to the holders of Class A Units are met. The Class B Units were acquired for no cash consideration.

 

In addition, Carbon acquired a 1.0% carried interest represented by Class C Units which were obtained in connection with the contribution to Carbon Appalachia of a portion of its working interest in undeveloped properties in Tennessee. If Carbon Appalachia agrees to drill horizontal Chattanooga Shale wells on these properties, it will pay 100% of the cost of drilling and completion of the first 20 wells to earn a 75% working interest in such properties. Carbon, through its subsidiary, Nytis LLC, will retain a 25% working interest in the properties.

 

In connection with its role as the manager of Carbon Appalachia, $300,000 of annual general and administrative expenses will be allocated to and paid by Carbon Appalachia.

 

In connection with and concurrently with the closing of the acquisition described below, Carbon Tennessee Company, LLC (“ Carbon Tennessee ”), an indirect subsidiary of Carbon Appalachia, entered into a 4-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank with an initial borrowing base of $10.0 million.

 

Borrowings under the credit facility, along with the initial equity contributions made to Carbon Appalachia, were used by Carbon Tennessee to complete the acquisition of natural gas producing properties and related facilities located predominantly in Tennessee (the “ Acquisition”). The Acquisition was structured such that Carbon Tennessee acquired all of the issued and outstanding equity of two of the seller’s subsidiaries that own natural gas producing properties and related facilities. The purchase price was $20.0 million, subject to normal and customary pre and post-closing adjustments, and Carbon Tennessee used $8.5 million drawn from the credit facility toward the purchase price.

 

In connection with the Company entering into the Appalachia LLC Agreement described above and Carbon Tennessee engaging in the Acquisition, the Company issued to an affiliate of one of the institutional investors which purchased Class A Units of Carbon Appalachia (which is also an affiliate of the Company’s largest stockholders), a warrant to purchase approximately 400,000 shares of the Company’s Common Stock at an exercise price of $7.20 per share. The exercise price for the warrant is payable exclusively with Class A Units of Carbon Appalachia and the number of shares of the Company common stock for which the warrant is exercisable is determined, as of the time of exercise, by dividing (a) the aggregate unreturned capital plus an internal rate of return on such capital of the warrantholder’s Class A Units of Carbon Appalachia by (b) the exercise price. The warrant has a term of seven years and includes certain standard registration rights with respect to the shares of Carbon’s common stock issuable upon exercise of the warrant. If exercised, the warrant provides Carbon an opportunity to increase its ownership stake in Carbon Appalachia without requiring the payment of cash.

 

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Results of Operations

 

Three Months Ended March 31, 2017 Compared to Three Months Ended March 31, 2016.

 

The following discussion and analysis relates to items that have affected our results of operations for the three months ended March 31, 2017 and 2016. The following table sets forth, for the periods presented, selected historical statements of operations data. The information contained in the table below should be read in conjunction with the Company’s Consolidated Financial Statements and Notes thereto and the information under “ Forward Looking Statements ” below.

 

    Three Months Ended        
    March 31,     Percent  
(in thousands, except production and per unit data)   2017     2016     Change  
Revenue:                  
Natural gas sales   $ 3,994     $ 1,092       266 %
Oil sales     1,046       628       67 %
Commodity derivative gain     2,144       140       *  
Other income     9       1       *  
Total revenues     7,193       1,861       286 %
                         
Expenses:                        
Lease operating expenses     1,205       589       105 %
Transportation costs     489       372       32 %
Production and property taxes     412       135       205 %
General and administrative     1,670       1,523       10 %
Depreciation, depletion and amortization     573       503       14 %
Accretion of asset retirement obligations     78       35       122 %
Impairment of oil and gas properties     -       3,890       *  
Total expenses     4,427       7,047       (37 %)
                         
Operating income (loss)   $ 2,766     $ (5,186 )     *  
                         
Other income and (expense):                        
Interest expense   $ (267 )   $ (57 )     *  
Warrant derivative gain     830       -       *  
Equity investment income     7       -       *  
Total other income (expense)   $ 570     $ (57 )     *  
                         
Production data:                        
Natural gas (Mcf)     1,160,907       481,039       141 %
Oil and liquids (Bbl)     20,654       19,463       6 %
Combined (Mcfe)     1,284,831       597,817       115 %
                         
Average prices before effects of hedges:                        
Natural gas (per Mcf)   $ 3.44     $ 2.27       52 %
Oil and liquids (per Bbl)   $ 50.65     $ 32.26       57 %
Combined (per Mcfe)   $ 3.92     $ 2.88       36 %
                         
Average prices after effects of hedges**:                        
Natural gas (per Mcf)   $ 4.71     $ 2.44       93 %
Oil and liquids (per Bbl)   $ 83.12     $ 35.38       135 %
Combined (per Mcfe)   $ 5.59     $ 3.11       80 %
                         
Average costs (per Mcfe):                        
Lease operating expenses   $ 0.94     $ 0.98       (4 %)
Transportation costs   $ 0.38     $ 0.62       (39 %)
Production and property taxes   $ 0.32     $ 0.23       39 %
Cash-based general and administrative expense   $ 1.05     $ 1.93       (46 %)
Depreciation, depletion and amortization   $ 0.45     $ 0.84       (46 %)

 

* Not meaningful or applicable              
** Includes realized and unrealized commodity derivative gains        

 

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Oil and natural gas revenues - Revenues from sales of oil and natural gas increased 193% to approximately $5.0 million for the three months ended March 31, 2017 from approximately $1.7 million for the three months ended March 31, 2016. Natural gas revenues for the first quarter ended March 31, 2017 increased approximately 266% over the same period in 2016 primarily due to an increase in gas production of 141% primarily due to the acquisition of producing oil and natural gas properties in the Appalachian Basin in the fourth quarter of 2016 and a 52% increase in average natural gas prices. Oil revenues for the first quarter ended March 31, 2017 increased approximately 67% over the same period in 2016 primarily due to a 57% increase in oil prices and a 6% increase in oil production.

 

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 using fixed price swap contracts when our management believes that available futures prices for our oil and natural gas production are sufficient to warrant hedging to ensure predicable cash flows for certain of the Company’s production. Because we do not designate these derivatives as cash flow hedges, they do not receive hedge accounting treatment and all mark-to-markets 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, 2017 and 2016, we had hedging gains of approximately $2.1 million and $140,000, respectively.

 

Lease operating expenses- Lease operating expenses for the three months ended March 31, 2017 increased 105% compared to the three months ended March 31, 2016. This increase is principally attributed to the acquisition of oil and natural gas properties in the Appalachian Basin in the fourth quarter of 2016. On a per Mcfe basis, lease operating expenses decreased from $0.98 per Mcfe for the three months ended March 31, 2016 to $0.94 per Mcfe for the three months ended March 31, 2017.

 

Transportation costs- Transportation costs for the three months ended March 31, 2017 increased 32% compared to the three months ended March 31, 2016. This increase is primarily attributed to transportation and gathering expenses associated with the acquisition of oil and natural gas properties in the Appalachian Basin in the fourth quarter of 2016. On a per Mcfe basis, these expenses decreased from $0.62 per Mcfe for the three months ended March 31, 2016 to $0.38 per Mcfe for the three months ended March 31, 2017 primarily due to lower transportation costs per unit for the Appalachian Basin properties acquired in the fourth quarter of 2016 compared to the Company’s other natural gas properties.

 

Production and property taxes- Production and property taxes increased from approximately $135,000 for the three months ended March 31, 2016 to approximately $489,000 for the three months ended March 31, 2017. This increase is primarily attributed to increased oil and natural gas revenues due to the factors listed above. Production taxes, which averaged approximately 4.3% for the Company for the three months ended March 31, 2017, are generally calculated as a percentage of sales revenues. Ad valorem tax rates, which can fluctuate by year, are determined by individual counties where the Company has production and are assessed on the Company’s oil and natural gas revenues one or two years in arrears depending on the location of the production. On a per Mcfe basis, these expenses increased from $0.23 per Mcfe for the three months ended March 31, 2016 to $0.32 per Mcfe for the three months ended March 31, 2017.

 

Depreciation, depletion and amortization (DD&A)- DD&A increased from approximately $503,000 for the three months ended March 31, 2016 to approximately $573,000 for the three months ended March 31, 2017 primarily due to an increase in oil and natural gas production offset, in part, by a decrease in the depletion rate. The decrease in the depletion rate is primarily attributed to the acquisition of producing oil and natural gas properties in the Appalachian Basin in the fourth quarter of 2016 which reduced the Company’s blended depletion rate. In addition, the depletion rate decreased due to impairment charges recognized by the Company during the first six months of 2016. On a per Mcfe basis, DD&A decreased from $0.84 per Mcfe for the three months ended March 31, 2016 to $0.45 per Mcfe for the three months ended March 31, 2017.

 

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Impairment of oil and gas properties- The Company did not recognize a non-cash impairment charge against its oil and natural gas properties in the first quarter of 2017. For the first quarter of 2016, due to low commodity prices, the Company recorded impairment expenses of approximately $3.9 million. The ceiling limitation calculation is not intended to be indicative of the fair market value of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and various components of our balance sheet. Any recorded impairment is not reversible at a later date.

 

General and administrative expenses- Cash-based general and administrative expenses increased from approximately $1.2 million for the quarter ended March 31, 2016 to approximately $1.4 million for the quarter ended March 31, 2017. The increase was primarily attributed to personnel related costs and other costs associated with potential acquisition opportunities, offset, in part, by a reimbursement from Carbon California for due diligence costs incurred on behalf of Carbon California and allocated general and administrative expenses in connection with its role of manger of Carbon California. On a per Mcfe basis, cash-based general and administrative expenses decreased from $1.93 for the three months ended March 31, 2016 to $1.05 per Mcfe for the three months ended March 31, 2017. Non-cash stock-based compensation and other general and administrative expenses for the quarters ended March 31, 2017 and 2016 are summarized in the following table:

   

    Three Months Ended March 31,  
    2017     2016     Increase/Decrease  
(in thousands)                  
Stock-based compensation   $ 319     $ 371     $ (52 )
Other general and administrative expenses     1,351       1,152       199  
General and administrative expense, net   $ 1,670     $ 1,523     $ 147  

 

Interest expense - Interest expense increased from approximately $57,000 for the three months ended March 31, 2016 to approximately $267,000 for the three months ended March 31, 2017 primarily due to higher outstanding debt balances and interest rates.

 

Liquidity and Capital Resources

 

Our exploration, development and acquisition activities require us to make significant operating and capital expenditures. Historically, we have used cash flow from operations and our bank credit facility as our primarily 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.

 

In connection with the closing of the EXCO Acquisition and entering into the credit facility with LegacyTexas Bank, the Company entered into swap derivative agreements to hedge a portion of its oil and natural gas production.

 

The following table reflects the Company’s outstanding derivative hedges as of March 31, 2017:

 

    Natural Gas     Oil  
          Weighted           Weighted  
          Average Price           Average Price  
Year   MMBtu     (a)     Bbl     (b)  
2017     2,520,000     $ 3.30       45,000     $ 52.98  
2018     3,120,000     $ 3.01       48,000     $ 54.11  
2019     1,320,000     $ 2.85       36,000     $ 54.90  

 

(a) NYMEX Henry Hub Natural Gas futures contract for the respective period.

(b) NYMEX Light Sweet Crude West Texas Intermediate future contract for the respective period.

 

  26  

 

 

This level of hedging will provide a measure of certainty of the cash flow that we will receive for a portion of our production through 2019. However, future hedging activities may result in reduced income or even financial losses to us. See Risk Factors— The use of derivative instruments used in hedging arrangements could result in financial losses or reduce income ,” in our 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.

 

The primary source of liquidity historically has been our credit facility (described below). In October 2016, the Company entered into a four-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank with an initial borrowing base of $17.0 million. The borrowing base is subject to semi-annual redeterminations in March and September, commencing March 2017. On March 30, 2017, the Borrowing base was increased to $23.0 million. See- “Bank Credit Facility” below for further details.

 

Our ability to access the debt and equity capital markets on economical terms is affected by general economic conditions, the domestic and global financial markets, our operational and financial performance, the value of our equity securities, prevailing commodity prices, and other macroeconomic factors outside of our control.

 

After closing the EXCO Acquisition and entering into the credit facility with LegacyTexas Bank, we believe that we are adequately positioned for the current economic environment due to our projected cash flow, access to undrawn debt capacity, our large inventory of drilling locations and acreage position and minimal capital expenditure obligations.

 

In February 2017, the Company entered into the Carbon California LLC Agreement of Carbon California and will be the manager of Carbon California. In connection with its role as manager of Carbon California, $600,000 of annual general and administrative expenses will be allocated to and paid by Carbon California. Pursuant to the Carbon California LLC Agreement, the Company acquired its interest in Carbon California for no cash consideration; however, the Company may have future capital expenditure obligations to Carbon California depending on future commodity prices and the level of drilling and development activity of Carbon California.

 

In April 2017, the Company finalized the Carbon Appalachia LLC Agreement. In connection with its role as manager of Carbon Appalachia, $300,000 of annual general and administrative expenses will be allocated to be paid by Carbon Appalachia. Pursuant to the Carbon Appalachia LLC Agreement, Carbon acquired a 2% interest in Carbon Appalachia represented by Class A units associated with its equity commitment of $2.0 million.

 

Based on our current outlook of commodity prices and our estimated production for 2017, we expect to fund our future activities primarily with cash flow from operations, our credit facility, sales of non-strategic properties or the issuance of additional equity or debt. Such transactions, if any, will depend on general economic conditions, domestic and global financial markets, the Company’s operational and financial performance, the value of our equity securities, prevailing commodity prices, and other macroeconomic factors outside of our control. Current market conditions may limit our ability to source attractive acquisition opportunities and to issue new debt or equity securities in the public or private markets. The ability of oil and gas companies to access the equity and high yield debt markets has been limited since the significant decline in commodity prices throughout 2015 and 2016. We expect that our net cash provided by operating activities may be adversely affected by continued low commodity prices. We believe that our expected future cash flows provided by operating activities will be sufficient to fund our normal recurring activities (other than the potential acquisition of additional oil and natural gas properties), and our contractual obligations. If low commodity prices continue, we may elect to continue to defer our planned capital expenditures. We believe that our financial flexibility to adjust our spending levels will provide us with sufficient liquidity to meet our financial obligations should economic conditions deteriorate. See “Risk Factors” , in our Annual Report filed on Form 10-K with the SEC, for a discussion of the risks and uncertainties that affect our business and financial and operating results.

 

Bank Credit Facility

 

In 2016, Carbon entered into a 4-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank. LegacyTexas Bank is the initial lender and acts as administrative agent.

 

  27  

 

 

The credit facility has a maximum availability of $100.0 million (with a $500,000 sublimit for letters of credit), which availability is subject to the amount of the borrowing base. The initial borrowing base established under the credit facility was $17.0 million. The borrowing base is subject to semi-annual redeterminations in March and September commencing March 2017. On March 30, 2017, the borrowing base was increased to $23.0 million.

 

The credit facility is guaranteed by each existing and future direct or indirect subsidiary of Carbon (subject to certain exceptions). The obligations of Carbon and the subsidiary guarantors under the credit facility are secured by essentially all tangible and intangible personal and real property of the Company (subject to certain exclusions).

 

Interest is payable quarterly and accrues on borrowings under the credit facility at a rate per annum equal to either (i) the base rate plus an applicable margin between 0.50% and 1.50% or (ii) the Adjusted LIBOR rate plus an applicable margin between 3.50% and 4.50% at Carbon’s option. The actual margin percentage is dependent on the credit facility utilization percentage. Carbon is obligated to pay certain fees and expenses in connection with the credit facility, including a commitment fee for any unused amounts of 0.50%.

 

The 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 distributions on, or repurchases of, equity; (vi) make certain investments; (vii) enter into certain transactions with its affiliates; (viii) enter into sales-leaseback transactions; (ix) make optional or voluntary payment of debt; (x) change the nature of its business; (xi) change its 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 certain basket amounts and acceptable transaction levels. In addition, the credit facility requires Carbon’s compliance, on a consolidated basis, with (i) a maximum funded Debt/EBITDA ratio of 3.5 to 1.0 and (ii) a minimum current ratio of 1.0 to 1.0, commencing with the quarter ended March 31, 2017. The Company was in compliance with the financial covenants associated with the credit facility as of March 31, 2017.

 

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

 

As required under the terms of the credit facility, the Company established pricing for a certain percentage of its production through the use of derivative contracts. The Company is a party to an ISDA Master Agreement with BP Energy Company that established 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 the Company and BP Energy Company is secured by the collateral and backed by the guarantees supporting the credit facility.

 

As of March 31, 2017, there was approximately $15.5 million in borrowings and approximately $7.5 million of additional borrowing capacity under the credit facility. The Company’s effective borrowing rate at March 31, 2017 was approximately 5.75%.

 

Sources and Uses of Cash

 

Our primary sources of liquidity and capital resources are operating cash flow, borrowings under our credit facility and sales of non-strategic assets. Our primary uses of funds are expenditures for acquisition, exploration and development activities, leasehold and property acquisitions, other capital expenditures and debt service.

 

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

 

  28  

 

 

The following table presents net cash provided by or used in operations, investing and financing activities for the three months ended March 31, 2017 and 2016.

 

    Three Months Ended  
    March 31,  
(in thousands)   2017     2016  
             
Net cash provided by (used in) operating activities   $ 894     $ (264 )
Net cash provided by (used in) investing activities   $ (399 )   $ 18  
Net cash (used in) provided by financing activities   $ (723 )   $ 397  

 

Net cash provided by or used in 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 $1.2 million for the first quarter ended March 31, 2017 as compared to the same period in 2016. 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 2016 and higher oil and natural gas prices in the first quarter of 2017 as compared to the same period in 2016.

 

Net cash used in or provided by or investing activities is primarily comprised of 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 increased approximately $417,000 for the first quarter ended March 31, 2017 as compared to the same period in 2016. In the first quarter of 2016, the Company received a cash distribution of $275,000 from Crawford County Gas Gathering Company. In addition, the Company increased its capital expenditures in the first quarter of 2017 by approximately $134,000 compared to the first quarter of 2016.

 

The increase in cash used in financing cash flows of approximately $1.1 million for the quarter ended March 31, 2017 as compared to the quarter ended March 31, 2016 was primarily due to reduced borrowings, and increased debt repayment in the first quarter of 2017 as compared to the same period in 2016.

 

Capital Expenditures

 

Capital expenditures for the three months ended March 31, 2017 and 2016 are summarized in the following table:

 

   

Three Months Ended

March 31,

 
(in thousands)   2017     2016  
             
Acquisition of oil and gas properties:            
Unevaluated properties   $ -     $ 89  
Drilling and development     330       130  
Pipeline and facilities     25       33  
Other     41       10  
Total capital expenditures   $ 396     $ 262  

 

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

 

Due to continued low commodity prices, the Company has significantly reduced its drilling program in 2016 and for the three months ended March 31, 2017 and have focused on optimizing 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.

 

  29  

 

 

Off-Balance Sheet Arrangements

 

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of March 31, 2017, 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.

 

Non-GAAP Measures

 

EBITDA and Adjusted EBITDA

 

“EBITDA” and “Adjusted EBITDA” are non-GAAP financial measures. We define EBITDA as net income (loss) before interest expense, taxes, depreciation, depletion and amortization. We define Adjusted EBITDA as EBITDA prior to accretion of asset retirement obligations, ceiling test write downs of oil and gas properties, non-cash stock-based compensation expense, non-cash warrant derivative gain or loss and the gain or loss on sold investments or properties. EBITDA and Adjusted EBITDA is consolidated including non-controlling interests and as used and defined by us, may not be comparable to similarly titled measures employed by other companies and are not measures of performance calculated in accordance with GAAP. EBITDA and Adjusted EBITDA should not be considered in isolation or as a substitute for operating income, net income or loss, cash flow provided by or used in operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. EBITDA and Adjusted EBITDA provide no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. EBITDA and Adjusted EBITDA do not represent funds available for discretionary use because those funds are required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration and development expenses, and other commitments and obligations. However, our management believes EBITDA and Adjusted EBITDA are useful to an investor in evaluating our operating performance because these measures:

 

are widely used by investors in the oil and natural gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods, book value of assets, capital structure and the method by which assets were acquired, among other factors; and
     
help investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and are used by our management for various purposes, including as a measure of operating performance, in presentations to our board of directors, as a basis for strategic planning and forecasting and by our lenders pursuant to a covenant under the Company’s credit facility.

 

There are significant limitations to using EBITDA and Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies and the different methods of calculating EBITDA and Adjusted EBITDA reported by different companies.

 

  30  

 

 

The following table represents a reconciliation of our net earnings or loss, the most directly comparable GAAP measure to EBITDA and Adjusted EBITDA for the three months ended March 31, 2017 and 2016.

 

    Three months ended
March 31,
 
(in thousands)   2017     2016  
             
Net income (loss)   $ 3,336     $ (5,243 )
                 
Adjustments:                
Interest expense     267       57  
Depreciation, depletion and amortization     573       503  
EBITDA     4,176       (4,683 )
                 
Adjusted EBITDA                
EBITDA     4,176       (4,683 )
Adjustments:                
Non-cash stock-based compensation     319       371  
Non-cash warrant derivative gain or loss     (830 )     -  
Impairment of oil and gas properties     -       3,890  
Accretion of asset retirement obligations     78       35  
Adjusted EBITDA   $ 3,743     $ (387 )

 

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 of places in this report and include statements with respect to, among other things:

 

estimates of our oil and natural gas reserves;

 

estimates of our future oil 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;

 

our outlook on oil 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.

 

  31  

 

 

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 of 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 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 or incorporated in our Annual Report filed on Form 10-K with the SEC.

 

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 Form 10-Q and attributable to the Company 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 4. Controls and Procedures

 

Evaluation of Disclosure Controls and Procedures

 

We have established disclosure controls and procedures to ensure that material information related to the Company and its consolidated subsidiaries is made known to the officers who certify the Company's financial reports and the Board of Directors.

 

As required by Rule 13a - 15(b) under the Securities Exchange Act of 1934 as amended (the "Exchange Act"), we have evaluated under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rules 13a - 15(e) and 15d-15(e) under the Exchange Act as of March 31, 2017. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms and that such information is accumulated and communicated to our management, as appropriate, to allow such persons to make timely decisions regarding required disclosures.

 

Our principal executive officer and principal financial officer have concluded that our current disclosure controls and procedures were effective as of March 31, 2017 at the reasonable assurance level.

 

Changes in Internal Control over Financial Reporting

 

There has not been any change in our internal control over financial reporting that occurred during our quarterly period ended March 31, 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

  32  

 

 

PART II. OTHER INFORMATION

 

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

 

The following sets forth the information with respect to the unregistered sale of equity securities that occurred during the quarter ended March 31, 2017 or subsequently, and have not been reported on a current report on Form 8-K or other report filed with the Securities and Exchange Commission.

 

On March 16, 2017, pursuant to the Carbon Plans, the Company granted 21,000 restricted shares to its non-employee directors, 40,000 restricted shares to its officer employees and 20,050 restricted shares to its non-officer employees. To the extent these stock grants constituted a sale of equity securities, the Company relied on Sections 4(a)(2) of the Securities Act of 1933 for these stock grants. No commissions or other remuneration were paid in connection with these stock grants.

 

ITEM 6. Exhibits

 

Exhibit No.   Description
     
3(i)(a)   Amended and Restated Certificate of Incorporation of Carbon Natural Gas Company incorporated by reference to exhibit 3(i) to Form 8-K for Carbon Natural Gas Company filed on May 5, 2011.
3(i)(b)   Amended and Restated Certificate of Designation with respect to Series A Convertible Preferred Stock of Carbon Natural Gas Company, incorporated by reference to exhibit 3(i) to Form 8-K for Carbon Natural Gas Company filed July 6, 2011.
3(i)(c)   Certificate of Amendment to Certificate of Incorporation of Carbon Natural Gas Company, Incorporated by reference to exhibit 3(i) to Form 8-K for Carbon Natural Gas Company filed on July 19, 2011.
3(i)(d)   Certificate of Amendment to the Amended and Restated Certificate of Incorporation of Carbon Natural Gas Company, incorporated by reference to exhibit 3.1 to Form 8-K for Carbon Natural Gas Company filed on March 16, 2017.
3(ii)   Amended and Restated Bylaws incorporated by reference to exhibit 3(i) to Form 8-K filed on May 5, 2015.
4.1   Form of Warrant with respect to Carbon California Company, LLC, incorporated by reference to exhibit 4.1 to Form 8-K for Carbon Natural Gas Company filed on February 21, 2017.  
10.1*   Amended and Restated Limited Liability Company Agreement of Carbon California Company, LLC dated February 15, 2017.
10.2*   Management Services Agreement by and between Carbon Natural Gas Company and Carbon California Company, LLC dated February 15, 2017.  
10.3*   Carbon Natural Gas Company 2017 Annual Incentive Plan.
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

 

  33  

 

 

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 NATURAL GAS COMPANY
  (Registrant)
   
Date: May 19, 2017 By: /s/ Patrick R. McDonald
    PATRICK R. MCDONALD,
    Chief Executive Officer
     
Date: May 19, 2017 By: /s/ Kevin D. Struzeski
    KEVIN D. STRUZESKI
    Chief Financial Officer

 

 

34

 

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