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 June 30, 2016

 

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” and ‘smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer  ☐	Accelerated filer  ☐	Non-accelerated filer  ☐	Smaller reporting company  ☒
		(Do not check if a smaller
		reporting company)

 

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 August 11, 2016, there were 110,638,849 issued and outstanding 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)	2
Consolidated Statements of Operations (unaudited)	3
Consolidated Statements of Stockholders’ Equity (unaudited)	4
Consolidated Statements of Cash Flows (unaudited)	5
Notes to the Consolidated Financial Statements (unaudited)	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 4. Controls and Procedures	30
Part II – OTHER INFORMATION
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	31
Item 6. Exhibits	31

 

 

PART I. FINANCIAL INFORMATION

ITEM 1.  Financial Statements

 

CARBON NATURAL GAS COMPANY

Consolidated Balance Sheets

 

		June 30,				December 31,
(in thousands)		2016				2015
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	266			$	305
Accounts receivable:
Revenue			982				1,082
Joint interest billings and other			569				778
Commodity derivative asset			-				408
Prepaid expense, deposits and other current assets			190				213
Total current assets			2,007				2,786
Property and equipment (note 4):
Oil and gas properties, full cost method of accounting:
Proved, net			20,076				25,032
Unproved			3,137				3,194
Other property and equipment, net			193				238
			23,406				28,464
Investments in affiliates (note 5)			744				1,025
Other long-term assets			193				433
Total assets		$	26,350			$	32,708
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities		$	5,724			$	5,621
Firm transportation contract obligations (note 12)			425				436
Commodity derivative liability			306				-
Notes payable (note 6)			4,000				-
Total current liabilities			10,455				6,057
Non-current liabilities:
Firm transportation contract obligations (note 12)			207				416
Commodity derivative liability			102				-
Asset retirement obligations (note 3)			3,170				3,095
Notes payable (note 6)			-				3,500
Total non-current liabilities			3,479				7,011
Commitments (note 12)
Stockholders’ equity:
Preferred stock, $0.01 par value; authorized 1,000,000  shares, no shares issued and outstanding at June 30, 2016 and December 31, 2015			-				-
Common stock, $0.01 par value; authorized 200,000,000 shares, 110,638,849 and 107,655,916 shares issued and outstanding at June 30, 2016 and December 31, 2015, respectively			1,107				1,077
Additional paid-in capital			55,027				54,394
Accumulated deficit			(45,575	)			(38,130	)
Total Carbon stockholders’ equity			10,559				17,341
Non-controlling interests			1,857				2,299
Total stockholders’ equity			12,416				19,640
Total liabilities and stockholders’ equity		$	26,350			$	32,708

 

See accompanying notes to Consolidated Financial Statements.

 

 

CARBON NATURAL GAS COMPANY

Consolidated Statements of Operations

(Unaudited)

 

		Three Months Ended June 30,								Six Months Ended June 30,
(in thousands except per share amounts)		2016				2015				2016				2015
Revenue:
Natural gas sales		$	961			$	1,268			$	2,053			$	2,886
Oil sales			808				1,565				1,436				3,083
Commodity derivative (loss) income			(774	)			(59	)			(634	)			147
Other (loss) income			-				(33	)			1				18
Total revenue			995				2,741				2,856				6,134
Expenses:
Lease operating expenses			653				778				1,242				1,613
Transportation costs			385				357				758				755
Production and property taxes			124				230				259				429
General and administrative			1,552				1,791				3,075				3,666
Depreciation, depletion and amortization			436				696				938				1,341
Accretion of asset retirement obligations			35				32				70				63
Impairment of oil and gas properties			409				-				4,299				-
Total expenses			3,594				3,884				10,641				7,867
Operating loss			(2,599	)			(1,143	)			(7,785	)			(1,733	)
Other income and (expense):
Interest expense			(46	)			(53	)			(103	)			(97	)
Other			17				(11	)			17				(36	)
Equity investment income (loss)			(6	)			(2	)			(6	)			(1	)
Total other expense			(35	)			(66	)			(92	)			(134	)
Loss before income taxes			(2,634	)			(1,209	)			(7,877	)			(1,867	)
Provision for income taxes			-				-				-				-
Net loss before non-controlling interests			(2,634	)			(1,209	)			(7,877	)			(1,867	)
Net loss  attributable to non-controlling interests			(116	)			(28	)			(432	)			(56	)
Net (loss) income attributable to controlling interest		$	(2,518	)		$	(1,181	)		$	(7,445	)		$	(1,811	)
Net loss per common share:
Basic		$	(0.02	)		$	(0.01	)		$	(0.07	)		$	(0.02	)
Diluted		$	(0.02	)		$	(0.01	)		$	(0.07	)		$	(0.02	)
Weighted average common shares outstanding:
Basic			109,966				107,166				108,573				106,554
Diluted			109,966				107,166				108,573				106,554

 

See accompanying notes to Consolidated Financial Statements.

 

 

CARBON NATURAL GAS COMPANY

Consolidated Statements of Stockholders’ Equity

(Unaudited)

(in thousands)

 

										Additional				Non-								Total
		Common Stock								Paid-in				Controlling				Accumulated				Stockholders’
		Shares				Amount				Capital				Interests				Deficit				Equity
Balances, December 31, 2015			107,655			$	1,077			$	54,394			$	2,299			$	(38,130	)		$	19,640
Stock-based compensation			-				-				663				-				-				663
Restricted stock vested			1,293				13				(13	)			-				-				-
Performance units vested			1,690				17				(17	)			-				-				-
Non-controlling interest distributions, net			-				-				-				(3	)			-				(3	)
Non-controlling interest - purchase			-				-				-				(7	)			-				(7	)
Net loss			-				-				-				(432	)			(7,445	)			(7,877	)
Balances, June 30, 2016			110,638			$	1,107			$	55,027			$	1,857			$	(45,575	)		$	12,416

 

See accompanying notes to Consolidated Financial Statements.

 

 

CARBON NATURAL GAS COMPANY

Consolidated Statements of Cash Flows

(Unaudited)

 

		Six Months Ended
		June 30,
(in thousands)		2016				2015
Cash flows from operating activities:
Net loss		$	(7,877	)		$	(1,867	)
Items not involving cash:
Depreciation, depletion and amortization			938				1,341
Accretion of asset retirement obligations			70				63
Impairment of oil and gas properties			4,299				-
Unrealized commodity derivative loss			966				764
Stock-based compensation expense			663				699
Equity investment loss			6				1
Other			(7	)			-
Net change in:
Accounts receivable			341				1,446
Prepaid expenses, deposits and other current assets			22				(75	)
Accounts payable, accrued liabilities and firm transportation contract obligations			(56	)			(1,723	)
Net cash (used in) provided by operating activities			(635	)			649
Cash flows from investing activities:
Development and acquisition of properties and equipment			(233	)			(2,343	)
Proceeds from sale of oil and gas properties and other assets			8				42
Other long-term assets			49				454
Equity investment distribution			275				-
Net cash provided by (used in) investing activities			99				(1,847	)
Cash flows from financing activities:
Proceeds from notes payable			700				1,100
Payments on notes payable			(200	)			(400	)
Distributions to non-controlling interests			(3	)			(59	)
Net cash provided by financing activities			497				641
Net decrease in cash and cash equivalents			(39	)			(557	)
Cash and cash equivalents, beginning of period			305				1,132
Cash and cash equivalents, end of period		$	266			$	575

 

See accompanying notes to Consolidated Financial Statements.

 

 

CARBON NATURAL GAS COMPANY

Notes to Consolidated Financial Statements

(Unaudited)

 

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. Collectively, Carbon, Nytis USA and Nytis LLC are referred to as the Company.

 

Note 2 – Going Concern

 

The accompanying Consolidated Financial Statements have been prepared assuming the Company will continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business for the twelve month period following the date of these Consolidated Financial Statements.

 

On May 17, 2016, Nytis LLC, entered into an amendment to its credit facility with Bank of Oklahoma that reduced the borrowing base under the credit facility from $20.0 million to $5.5 million (of which $500,000 is reserved for future interest payments as those payments become due under the credit facility) and changed the maturity date of the credit facility from May 31, 2017 to January 2, 2017. As a result of the reduction in the borrowing base (and associated borrowing base capacity) and the continuation of low commodity prices, the Company is not in compliance with the financial covenants under the credit facility (nor does it expect to be throughout the remainder of the year) and Bank of Oklahoma has curtailed the advancement of funds under the credit facility. Due to non-compliance with financial covenants, Bank of Oklahoma has the right to call a default under the credit facility. In addition, with the change in the maturity of the credit facility from May 31, 2017 to January 2, 2017, outstanding borrowings under the credit facility were classified as current on the Company’s Consolidated Balance Sheet, resulting in negative working capital of approximately $8.5 million as of June 30, 2016.

 

We are in the process of analyzing various alternatives to enhance our liquidity and capital structure including obtaining a new credit facility, issuing additional equity, divesting nonstrategic assets, reducing costs, or engaging in similar type activities. Although management believes that it will be able to obtain the necessary funding to allow the Company to remain a going concern through the methods discussed above, there can be no assurance that such methods will prove successful. The accompanying Consolidated Financial Statements do not include any adjustments that might result from the outcome of this uncertainty.

 

Note 3 – 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 fairly present the Company’s financial position as of June 30, 2016, the Company’s results of operations for the three and six months ended June 30, 2016 and 2015 and the Company’s cash flows for the six months ended June 30, 2016 and 2015. Operating results for the three and six months ended June 30, 2016 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, 2015 filed on Form 10-K with the Securities and Exchange Commission (“SEC”).

 

 

Note 3 – Summary of Significant Accounting Policies (continued)

 

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 47 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 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.

 

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.

 

 

Note 3 – Summary of Significant Accounting Policies (continued) 

 

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 and six months ended June 30, 2016, the Company recognized a ceiling test impairment of approximately $409,000 and $4.3 million, respectively, as the Company’s full cost pool exceeded the ceiling limitations. For the three and six months ended June 30, 2015, the Company did not recognize a ceiling test impairment as its full cost pool did not exceed the ceiling test 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 price declines will continue to impact the ceiling test value until such time the 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 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 an impairment assessment for each investment is 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 5% interest in partnerships or limited liability companies 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 are 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.

 

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.

 

 

Note 3 – Summary of Significant Accounting Policies (continued)

 

The following table is a reconciliation of the ARO for the six months ended June 30, 2016 and 2015:

 

		Six Months Ended June 30,
(in thousands)		2016				2015
Balance at beginning of period		$	3,095			$	2,968
Accretion expense			70				63
Additions during period			5				-
Balance at end of period		$	3,170			$	3,031

 

Earnings (Loss) 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 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 options and 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 (loss) income per share:

 

		Three Months Ended June 30,								Six Months Ended June 30,
(in thousands except per share amounts)		2016				2015				2016				2015
Net loss		$	(2,518	)		$	(1,181	)		$	(7,445	)		$	(1,811	)
Basic weighted-average common shares outstanding during the period			109,966				107,166				108,573				106,554
Add dilutive effects of stock options, warrants and non-vested shares of restricted stock			-				-				-				-
Diluted weighted-average common shares outstanding during the period			109,966				107,166				108,573				106,554
Basic net (loss) income per common share		$	(0.02	)		$	(0.01	)		$	(0.07	)		$	(0.02	)
Diluted net (loss) income per common share		$	(0.02	)		$	(0.01	)		$	(0.07	)		$	(0.02	)

 

For the three and six months ended June 30, 2016 and 2015, the Company had a net loss and therefore, the diluted net loss per share calculation excluded the anti-dilutive effect of approximately 250,000 warrants and approximately 4.9 million non-vested shares of restricted stock in each period. For the three and six months ended June 30, 2016, approximately 6.0 million restricted performance units, in each period, subject to future contingencies are excluded from the basic and diluted loss per share. For the three and six months ended June 30, 2015, approximately 5.0 million restricted performance units, subject to future contingencies, were excluded from the basic and diluted loss per share in each respective period.

 

Adopted and Recently Issued Accounting Pronouncements

 

In March 2016, the FASB issued Accounting Standards Update (“ASU”) 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. Early adoption is permitted. The Company is currently evaluating the impact on its Consolidated Financial Statements of adopting ASU 2016-09.

 

 

Note 3 – Summary of Significant Accounting Policies (continued)

 

In February 2016, the FASB issued ASU 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 August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements – Going Concern (“ASU 2014-15”). The objective of ASU 2014-15 is to provide guidance on management’s responsibility to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for fiscal years ending after December 15, 2016 and annual and interim periods thereafter. The Company is currently evaluating the impact on its Consolidated Financial Statements of adopting ASU 2014-15.

 

Note 4 – Property and Equipment

 

Net property and equipment as of June 30, 2016 and December 31, 2015 consists of the following:

 

(in thousands)		June 30, 2016				December 31, 2015
Oil and gas properties:
Proved oil and gas properties		$	97,675			$	97,453
Unproved properties not subject to depletion			3,137				3,194
Accumulated depreciation, depletion, amortization and impairment			(77,599	)			(72,421	)
Net oil and gas properties			23,213				28,226
Furniture and fixtures, computer hardware and software, and other equipment			804				825
Accumulated depreciation and amortization			(611	)			(587	)
Net other property and equipment			193				238
Total net property and equipment		$	23,406			$	28,464

 

As of June 30, 2016 and December 31, 2015, the Company had approximately $3.1 million and $3.2 million, respectively, 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 six months ended June 30, 2016 and 2015, the Company capitalized general and administrative expenses applicable to development and exploration activities of approximately $289,000 for each respective period.

 

Depletion expense related to oil and gas properties for the three and six months ended June 30, 2016 was approximately $407,000, or $0.65 per Mcfe, and approximately $879,000, or $0.72 per Mcfe, respectively. For the three and six months ended June 30, 2015, depletion expense was approximately $661,000, or $1.07 per Mcfe, and $1.3 million, respectively, or $0.97 per Mcfe, respectively.

 

Depreciation and amortization expense related to furniture and fixtures, computer hardware and software and other equipment for the three months ended June 30, 2016 and 2015 was approximately $29,000 and $35,000, respectively and for the six months ended June 30, 2016 and 2015 was approximately $59,000 and $72,000, 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 treating facilities. The Company’s gas production located in Illinois is gathered and transported on CCGGC’s gathering facilities. The Company’s investment in CCGGC is accounted for under the equity method of accounting, and its share of the income or loss is recognized. For the six months ended June 30, 2016 and 2015, the Company recorded equity investment loss of approximately $6,000 and $1,000, respectively, related to its investment in CCGGC. In addition, during the first quarter of 2016, the Company received a cash distribution of $275,000 from CCGGC.

 

Note 6 – Bank Credit Facility

 

On May 17, 2016, Nytis LLC’s entered into an amendment to its credit facility with Bank of Oklahoma that reduced the Company’s borrowing base under the credit facility from $20.0 million to $5.5 million (of which $500,000 is reserved for future interest payments as those payments become due under the credit facility) and changed the maturity date of the credit facility from May 31, 2017 to January 2, 2017. In addition, the amendment to the credit agreement provided waivers from Bank of Oklahoma regarding Nytis LLC’s past practice of advancing funding for general and administrative expenses of Carbon and ratified and affirmed the respective obligations for both Bank of Oklahoma and Nytis LLC under the credit facility.

 

At June 30, 2016, there were approximately $4.0 million in outstanding borrowings under the credit facility. The Company’s effective borrowing rate at June 30, 2016 was approximately 3.8%. The credit facility is collateralized by substantially all of the Company’s oil and gas assets. The credit facility includes terms that place limitations on certain types of activities including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, merger and acquisitions, and the payment of dividends. The credit facility requires satisfaction of a minimum current ratio (the ratio of current assets (including borrowing base capacity) to current liabilities as defined) of 1.0 to 1.0 and a maximum funded debt ratio (the ratio of the outstanding balance of all interest bearing indebtedness to the sum of EBITDAX (net income plus interest expense, income taxes, depreciation, depletion, amortization, exploration and impairment expenses and other non-cash charges)) for the most recently completed fiscal quarter times four of 4.25 to 1.0 as of the end of any fiscal quarter. The credit facility also provides for a maximum line of credit of $9.5 million for hedging arrangements. Carbon and Nytis USA are guarantors of Nytis LLC’s obligations under its credit facility.

 

No repayments of principal are required until maturity, except to the extent outstanding balances exceed the borrowing base then in effect. The Company has the right to both repay principal at any time and to reborrow.

 

The borrowing base is redetermined semi-annually, and the available borrowing amount could be increased or decreased as a result of such redeterminations. Under certain circumstances the lender may request an interim redetermination. The facility has variable interest rates based upon the ratio of outstanding debt to the borrowing base. Interest rates are based on either an Alternate Base Rate or LIBOR. The portion of the loan based on an “Alternate Base Rate” is determined by the rate per annum equal to 1.5% plus the greatest of the following: (a) the Federal Funds Rate for such day plus one-half of one percentage point, (b) the Prime Rate for such day or (c) LIBOR for a one-month LIBOR Interest Period plus one percentage point. The portion based on LIBOR is determined by the rate per annum equal to LIBOR plus between 2.5% and 3.25% for each LIBOR tranche. The credit facility includes a hedging component that provides a line of credit under commodity swap, exchange, collar, cap and fixed price agreements in addition to agreements designed to protect the Company against changes in interest and currency exchange rates.

 

As a result of the reduction in the borrowing base (and associated borrowing base capacity) and the continuation of low commodity prices, the Company is not in compliance with the minimum current ratio and maximum fund debt ratio requirements associated with the credit agreement as of June 30, 2016. As a result, Bank of Oklahoma has curtailed the advancement of funds under the credit facility. Due to the non-compliance with financial covenants, Bank of Oklahoma has the right to call a default under the credit facility. In the event a default is called, the credit facility could be terminated and amounts outstanding could be declared immediately due and payable by Bank of Oklahoma, subject to notice and, in certain cases, cure periods.

 

 

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 June 30, 2016, the Company has established a full valuation allowance against the balance of net deferred tax assets.

 

Note 8 – Stockholders’ Equity

 

Authorized and Issued Capital Stock

 

As of June 30, 2016, the Company had 200,000,000 shares of common stock authorized with a par value of $0.01 per share, of which 110,638,849 were issued and outstanding. The Company also had 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 six months of 2016, the increase in the Company’s issued and outstanding common stock was a result of the vesting of restricted stock and performance units 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 June 30, 2016, the Company has approximately 250,000 warrants outstanding and exercisable and approximately 489,000 shares of common stock outstanding that are subject to restricted stock agreements.

 

Nytis USA Restricted Stock Plan

 

As of June 30, 2016, there were approximately 489,000 shares of restricted stock issued under the Nytis USA Restricted Stock Plan (“Nytis USA Plan”). The Company accounted for these grants at their intrinsic value. From the date of the 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 is recognizing compensation expense for these restricted stock grants based on the fair value of the shares on the date the vesting terms were modified. Compensation costs recognized for these restricted stock grants were approximately $84,000 for the three months ended June 30, 2016 and 2015 and approximately $168,000 for the six months ended June 30, 2016 and 2015. As of June 30, 2016, there was approximately $168,000 of unrecognized compensation costs related to these restricted stock grants which the Company expects will be recognized ratably over the next six months.

 

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 22.6 million shares of common stock to Carbon’s 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.

 

 

Note 8 – Stockholders’ Equity (continued)

 

Restricted Stock

 

During the six months ended June 30, 2016, approximately 1.7 million shares of restricted stock were granted under the terms of the Carbon Plans in addition to approximately 6.6 million shares granted during previous years. For employees, these restricted stock awards vest ratably over 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 June 30, 2016, approximately 3.9 million of these restricted stock grants have vested.

 

Compensation costs recognized for these restricted stock grants were approximately $167,000 and $199,000 for the three months ended June 30, 2016 and 2015, respectively and approximately $368,000 and $359,000 for the six months ended June 30, 2016 and 2015, respectively. As of June 30, 2016, there was approximately $1.4 million of unrecognized compensation costs related to these restricted stock grants. This cost is expected to be recognized over the next 6.8 years.

 

Restricted Performance Units

 

During the six months ended June 30, 2016, 1.6 million shares of performance units were granted under the terms of the Carbon Plans in addition to approximately 6.4 million shares granted during previous years. 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 6.0 million restricted performance units are outstanding as of June 30, 2016.

 

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 June 30, 2016, the Company estimated that none of the performance units granted in 2012 and 2014 through 2016 would vest due to change in control and other performance provisions and accordingly, no compensation cost has been recorded. As of June 30, 2016, if change in control provisions and performance achievements pursuant to the terms and conditions of the 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 $3.8 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 vesting requirements compared to the performance units granted in 2012 and 2014 through 2016, the Company recognizes 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 $41,000 and $86,000 for the three months ended June 30, 2016 and 2015, respectively, and approximately $127,000 and $173,000 for the six months ended June 30, 2016 and 2015, respectively. As of June 30, 2016, compensation costs related to performance units granted in 2013 have been fully recognized.

 

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Note 9 – Accounts Payable and Accrued Liabilities

 

Accounts payable and accrued liabilities at June 30, 2016 and December 31, 2015 consist of the following:

 

		June 30,				December 31,
(in thousands)		2016				2015
Accounts payable		$	1,073			$	577
Oil and gas revenue payable to oil and gas property owners			1,228				1,221
Production taxes payable			52				59
Drilling advances received from joint venture partner			1,633				2,115
Accrued drilling costs			112				112
Accrued lease operating costs			47				76
Accrued ad valorem taxes			553				496
Accrued general and administrative expenses			781				833
Other accrued liabilities			245				132
Total accounts payable and accrued liabilities		$	5,724			$	5,621

 

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 June 30, 2016 and December 31, 2015 by level within the fair value hierarchy:

 

		Fair Value Measurements Using
(in thousands)		Level 1				Level 2				Level 3				Total
June 30, 2016
Liabilities:
Commodity derivatives		$	-			$	408			$	-			$	408
December 31, 2015
Assets:
Commodity derivatives		$	-			$	559			$	-			$	559

 

As of June 30, 2016, the Company’s commodity derivative financial instruments are comprised of nine natural gas swap agreements, one natural gas costless collar agreement and four oil costless collar agreements. The fair values of these agreements are determined under an income valuation technique. The valuation model requires a variety of inputs, including contractual terms, published forward prices, volatilities for options, and discount rates, as appropriate. 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 in all of the Company’s commodity derivative financial instruments is the lender in the Company’s bank credit facility.

 

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 six months ended June 30, 2016 and 2015, the Company recorded asset retirement obligations for additions of approximately $5,000 and nil, respectively. See Note 3 for additional information.

 

Note 11 – Physical Delivery Contracts 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 gas physical delivery contracts to effectively provide gas price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives and therefore these contracts are not recorded at fair value in the Consolidated Financial Statements.

 

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

 

As of June 30, 2016, the Company has two short-term physical delivery contracts which require the Company to deliver fixed volumes of natural gas. The Company has sufficient production from its natural gas producing properties delivering to the specific meters under these contracts. The following table summarizes the future production volumes to be delivered and sold under these contracts:

 

				Daily Volume
		Period		(Dths per day)				Price
Contract 1		Jul - Oct 2016			1,000			Index less $0.29
Contract 2		Jul - Sep 2016			611			98% of Index less $0.23

 

The Company’s other oil and gas sales contracts approximate index prices.

 

The Company’s costless collar and swap agreements as of June 30, 2016 are summarized in the table below:

 

		Natural Gas								Oil
						Weighted								Weighted
						Average								Average
Quarter		MMBtu				Price (a)( c)				Bbl				Price (b)( c)
Swaps:
Jul - Sep 2016			140,000			$	2.75				-				-
Oct - Dec 2016			150,000			$	2.77				-				-
Jan - Mar 2017			240,000			$	2.78				-				-
Apr - Jun 2017			240,000			$	2.78				-				-
Jul - Sep 2017			190,000			$	2.93				-				-
Oct - Dec 2017			180,000			$	2.92				-				-
Jan - Mar 2018			60,000			$	3.00				-				-
Apr - Jun 2018			40,000			$	3.00				-				-
Collars:
Jul - Sep 2016			30,000				$2.75 - $3.40				5,500				$48.64 - $57.91
Oct - Dec 2016			30,000				$2.75 - $3.40				4,500				$48.33 - $58.00
Jan - Mar 2017			-				-				4,500				$48.33 - $61.67
Apr - Jun 2017			-				-				4,500				$48.33 - $61.67
Jul - Sep 2017			-								4,500				$48.33 - $61.67
Oct - Dec 2017			-				-				4,500				$48.33 - $61.67

 

^{(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}

^{(c) NYMEX costless collar floor to ceiling prices.}

 

For its swap instruments, the Company receives a fixed price for the hedged commodity and pays a floating price to the counterparty. For its costless collar agreements, the Company receives the difference between the floating price and the floor price if the floating price is lower than the floor price, or the Company pays the difference between the floating price and the ceiling price if the floating price is higher than the ceiling price.

 

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

 

The following table summarizes the fair value of the derivatives recorded in the Consolidated Balance Sheets. These derivative instruments are not designated as cash flow hedging instruments for accounting purposes:

 

(in thousands)		June 30, 2016				December 31, 2015
Commodity derivative contracts:
Current assets		$	-			$	408
Non current assets			-				151
Current liabilities			306				-
Non current liabilities			102				-

 

The table below summarizes the realized and unrealized gains and losses related to the Company’s derivative instruments for the three and six months ended June 30, 2016 and 2015. These realized and unrealized gains and losses are recorded and included in commodity derivative gain or loss in the accompanying Consolidated Statements of Operations.

 

		Three Months Ended June 30,								Six Months Ended June 30,
(in thousands)		2016				2015				2016				2015
Commodity derivative contracts:
Settlement gains (losses)		$	130			$	359			$	332			$	911
Unrealized losses			(904	)			(418	)			(966	)			(764	)
Total settlement and unrealized (losses) gains, net		$	(774	)		$	(59	)		$	(634	)		$	147

 

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

 

The counterparty in all of the Company’s derivative instruments is the lender in its bank credit facility. Accordingly, the Company is not required to post collateral since the bank is secured by the Company’s oil and gas assets. The Company nets its derivative instrument fair value amounts executed with its counterparty pursuant to an ISDA master agreement, which provides for the net settlement over the term of the contract and in the event of default or termination of the contract. The following table summarizes the location and fair value amounts of all derivative instruments in the Consolidated Balance Sheet as of June 30, 2016, as well as the gross recognized derivative assets, liabilities and amounts offset in the Consolidated Balance Sheet:

 

										Net
		Gross								Recognized
		Recognized				Gross				Fair Value
		Assets/				Amounts				Assets/
Balance Sheet Classification		Liabilities				Offset				Liabilities
Commodity derivative assets:
Current assets		$	82			$	(82	)		$	-
Non-current assets			58				(58	)
Total derivative assets		$	140			$	(140	)		$	-
Commodity derivative liabilities:
Current liability		$	388			$	(82	)		$	306
Non-current liabilities			160				(58	)			102
Total derivative liabilities		$	548			$	(140	)		$	408

 

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

 

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Note 12 – Commitments

 

The Company has entered into long-term firm transportation contracts to ensure the transport for certain of its natural gas production to purchasers. Firm transportation volumes and the related demand charges for the remaining term of these contracts at June 30, 2016 are summarized in the table below.

 

Period		Dekatherms per day				Demand Charges
Jul 2016 - Apr 2018			4,450				$0.20 - $0.65
May 2018 - May 2020			2,150			$	0.20
Jun 2020 - May 2036			1,000			$	0.20

 

A liability of approximately $632,000 related to firm transportation contracts assumed in a 2011 asset acquisition, which represents the remaining commitment, is reflected on the Company’s Consolidated Balance Sheet as of June 30, 2016. 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.

 

Note 13 – Supplemental Cash Flow Disclosure

 

Supplemental cash flow disclosures for the six months ended June 30, 2016 and 2015 are presented below:

 

		Six Months Ended June 30,
(in thousands)		2016				2015
Cash paid during the period for:
Interest		$	110			$	60
Income taxes		$	-			$	325
Non-cash transactions:
Decrease in accounts payable and accrued liabilities included in oil and gas properties		$	(59	)		$	(267	)
Increase in net asset retirement obligations		$	5			$	-

 

Note 14 – Subsequent Events

 

On August 9, 2016, the Company issued 900,000 shares of restricted stock awards to certain of its employees. The restricted stock awards will vest on the three year anniversary of the grant and requires continuous employment by the grantee through that date. 

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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 2015 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 Appalachian and the Illinois Basins of 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 an office in Lexington, Kentucky from which we conduct our oil and natural gas operations.

 

At June 30, 2016 our proved developed reserves were comprised of 12% oil and 88% natural gas. Our limited current capital expenditure program is focused on the development of our oil and coalbed methane reserves. We believe that our drilling inventory and lease position, combined with our low operating expense and cost structure, provides us with a portfolio of opportunities for the development of our oil and gas properties. Our operating plan is centered on the following activities:

 

	●	Development 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; and

●

Producing property and land acquisitions which provide attractive risk adjusted rates of return and which complement our existing assets.

 

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. The following table highlights the quarterly average of NYMEX price trends for oil and natural gas prices for the last eight calendar quarters:

 

		2014								2015																2016
		Q3				Q4				Q1				Q2				Q3				Q4				Q1				Q2
Oil (Bbl)		$	97.21			$	73.12			$	48.57			$	57.96			$	46.44			$	42.17			$	33.51			$	45.60
Natural Gas (MMBtu)		$	4.07			$	4.04			$	2.99			$	2.61			$	2.74			$	2.17			$	2.06			$	1.98

 

Oil prices have fallen significantly since reaching highs of over $105.00 per barrel in June 2014 and dropped below $23.00 per barrel in February 2016. Natural gas prices have also declined from over $4.80 per Mcf in April 2014 to below $1.70 per Mcf in March 2016. Although oil and natural gas prices have recently 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 the Company’s revenues, but may also reduce the amount of oil and natural gas that can be produced economically and potentially lower our oil and natural gas reserves. 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 oil and gas properties and performs a ceiling test quarterly. Because the ceiling calculation requires a rolling 12-month average commodity price, the effect of lower prices in 2015 and 2016 caused the Company to recognize a ceiling test impairment of approximately $5.4 million in 2015 and approximately $409,000 and $4.3 million for the three and six months ended June 30, 2016, respectively.

 

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At June 30, 2016, the trailing twelve month average commodity price used in the ceiling calculations was $2.10 per Mcf of gas and $39.26 per barrel of oil. If the commodity prices had been calculated based on a twelve month simple average of commodity prices on the first day of the month for the four months ended December 31, 2015 and the first eight months of 2016, prices would have averaged $2.13 per Mcf of gas and $38.01 per barrel of oil. Based solely on these lower prices and holding all other factors constant, we would have a further ceiling test impairment of approximately $80,000. This calculation of lower commodity prices is prepared based on the presumption that all other inputs and assumptions are held constant with the exception of oil and natural gas prices. Therefore, the calculation strictly isolates the potential impact of commodity prices on our ceiling test limitation and proved reserves. 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. If commodity prices continue to decline, this will impact the ceiling test value until such time as commodity prices stabilize or improve. In addition, an extended decline in oil and 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.

 

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 by selling non-strategic properties or through issuance of additional equity or debt.

 

Operational Highlights

 

Continued weakness in commodity prices has had a significant adverse impact on our results of operations, liquidity, debt balance and the amount of cash flow available to invest in exploration and development activities.

 

At June 30, 2016, we had over 269,000 net acres of mineral leases located in the Appalachian and Illinois Basins of the United States. Approximately 51% of this acreage is held by production and of the remaining acreage, approximately 51% have lease terms of greater than five years remaining in the primary term or contractual extension periods.

 

The principal focus of our leasing, drilling and completion activities in recent years has been a Berea Sandstone Formation horizontal oil drilling program in eastern Kentucky and western West Virginia. At June 30, 2016, we had over 41,000 net mineral acres in the region. Since 2010, we have drilled 54 gross horizontal wells in the drilling 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 evaluate 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 68,000 net mineral acres in Indiana and Illinois which are prospective for the development of coalbed methane. The Company also owns an interest in natural gas gathering and 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. During 2015, the Company participated in the drilling of 25 stratigraphic wells to identify potential future horizontal locations in the Seelyville coal formation.

 

Our natural gas properties are largely held by production and contain a low risk multi-year development inventory of locations which, at the appropriate level of natural gas commodity price, will provide significant drilling and completion opportunities from multiple proven producing formations.

 

Recent Developments

 

Based on current prices and expected future prices for oil and natural gas for the remainder of 2016, we have reduced our drilling activity to conserve capital. During the six months ended June 30, 2016, our capital expenditures consisted principally of acquiring minor additional lease positions in our strategic oil play. Development of our oil properties and coalbed methane gas wells during the remainder of 2016 is contingent on our expectation of future oil and natural gas prices and access to development capital. In addition, the Company is evaluating potential producing property and land acquisition opportunities that would expand the Company’s operations and provide attractive risk adjusted rates of returns including the use of outside capital to facilitate acquisitions.

 

Pursuant to a participation agreement Nytis LLC entered into with Liberty Energy LLC (“Liberty”) in February 2014, Liberty will pay a disproportionate percentage of the costs associated with drilling and completing 20 wells on the covered leases. Following the drilling of these 20 wells, Nytis LLC and Liberty will pay their respective costs on a basis proportionate to their working interests. As of June 30, 2016, Liberty had participated in drilling six horizontal wells pursuant to this agreement.

 

On May 17, 2016, Nytis LLC, entered into an amendment to its credit facility with Bank of Oklahoma that reduced the borrowing base under the credit facility from $20.0 million to $5.5 million (of which $500,000 is reserved for future interest payments as those payments become due under the credit facility) and changed the maturity date of the credit facility from May 31, 2017 to January 2, 1017. See Notes 2 and 6 in the accompanying notes to the Consolidated Financial Statements and “Liquidity and Capital Resources” and “Bank Credit Facility” below for further details.

20

 

 

Results of Operations

 

Three Months Ended June 30, 2016 Compared to Three Months Ended June 30, 2015

 

The following discussion and analysis relates to items that have affected our results of operations for the three months ended June 30, 2016 and 2015. 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
		June 30,								Percent
(in thousands except production and per unit data)		2016				2015				Change
Revenue:
Oil sales		$	808			$	1,565				(48	%)
Natural gas sales			961				1,268				(24	%)
Commodity derivative loss			(774	)			(59	)			*
Other (loss) income			-				(33	)			*
Total revenues			995				2,741				(64	%)
Expenses:
Lease operating expenses			653				778				(16	%)
Transportation costs			385				357				8	%
Production and property taxes			124				230				(46	%)
General and administrative			1,552				1,791				(13	%)
Depreciation, depletion and amortization			436				696				(37	%)
Accretion of asset retirement obligations			35				32				9	%
Impairment of oil and gas properties			409				-				*
Total expenses			3,594				3,884				(7	%)
Operating loss		$	(2,599	)		$	(1,143	)			127	%
Other income and (expense):
Interest expense			(46	)			(53	)			(13	%)
Other			17				(11	)			*
Equity investment loss			(6	)			(2	)			*
Total other expense		$	(35	)		$	(66	)			(47	%)
Production data:
Natural gas (Mcf)			513,858				452,828				13	%
Oil (Bbl)			18,441				27,122				(32	%)
Combined (Mcfe)			624,504				615,560				1	%
Average prices before effects of hedges:
Natural gas (per Mcf)		$	1.87			$	2.80				(33	%)
Oil (per Bbl)		$	43.81			$	57.69				(24	%)
Combined (per Mcfe)		$	2.83			$	4.60				(38	%)
Average prices after effects of hedges**:
Natural gas (per Mcf)		$	0.76			$	2.76				(72	%)
Oil (per Bbl)		$	32.87			$	56.24				(42	%)
Combined (per Mcfe)		$	1.59			$	4.51				(65	%)
Average costs (per Mcfe):
Lease operating expenses		$	1.05			$	1.26				(17	%)
Transportation costs		$	0.62			$	0.58				7	%
Production and property taxes		$	0.20			$	0.38				(47	%)
Depreciation, depletion and amortization		$	0.70			$	1.13				(38	%)

 

*	Not meaningful or applicable
**	Includes settled and unrealized commodity derivative gains and losses.

 

21

 

 

Oil and natural gas revenues- Revenues from sales of oil and natural gas decreased 38% to approximately $1.8 million for the three months ended June 30, 2016 from approximately $2.8 million for the three months ended June 30, 2015. This decrease was primarily due to a 24% and 33% decrease in oil and natural gas prices, respectively. As compared with the same period in 2015, oil sales volumes decreased 32%. The decrease in oil production was primarily attributed to normal natural production declines. Natural gas production increased 13% due to shut-in gas and compressor downtime during the second quarter of 2015.

 

Commodity derivative income 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 and costless collars when our management believes that available futures prices for our oil and natural gas production are sufficient to warrant hedging to ensure predictable 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 June 30, 2016 and 2015, we had hedging losses of approximately $774,000 and $59,000, respectively.

 

Lease operating expenses- Lease operating expenses for the three months ended June 30, 2016 decreased 16% compared to the three months ended June 30, 2015. The decrease was primarily attributed to cost reduction initiatives and to lower water hauling and salt water disposal fees as a result of lower oil production. On a per Mcfe basis, lease operating expenses decreased from $1.26 per Mcfe for the three months ended June 30, 2015 to $1.05 per Mcfe for the three months ended June 30, 2016.

 

Transportation costs- Transportation costs for the three months ended June 30, 2016 increased 8% compared to the three months ended June 30, 2015. This increase is attributed to an increase in natural gas production. On a per Mcfe basis, these expenses increased from $0.58 per Mcfe for the three months ended June 30, 2015 to $0.62 per Mcfe for the three months ended June 30, 2016.

 

Production and property taxes- Production and property taxes decreased from approximately $230,000 for the three months ended June 30, 2015 to approximately $124,000 for the three months ended June 30, 2016. This decrease is primarily attributed to decreased oil and natural gas sales. Production taxes averaged approximately 4.1% and 4.3% of oil and natural gas sales for the three months ended June 30, 2016 and 2015, respectively. 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 sales one or two years in arrears depending on the location of the production.

 

Depreciation, depletion and amortization (DD&A)- DD&A decreased from approximately $696,000 for the three months ended June 30, 2015 to approximately $436,000 for the three months ended June 30, 2016 primarily due to a reduction in the Company’s depletion rate. The decrease in the depletion rate is primarily attributed to a reduction in the depletable asset base caused by impairment charges recognized in the fourth quarter of 2015 and the first quarter of 2016. On a per Mcfe basis, DD&A decreased from $1.13 per Mcfe for the three months ended June 30, 2015 to $0.70 per Mcfe for the three months ended June 30, 2016.

 

Impairment of oil and gas properties- At June 30, 2016, commodity prices used in the ceiling calculation, based on the required trailing 12-month average, were $39.26 per barrel of oil and $2.10 per Mcf of natural gas, resulting in an impairment of approximately $409,000 for the second quarter ended June 30, 2016. The Company did not record an impairment for the second quarter ended June 30, 2015. 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- General and administrative expenses decreased from approximately $1.8 million for the three months ended June 30, 2015 to approximately $1.6 million for the three months ended June 30, 2016. This decrease is primarily attributed to personnel related cost reduction measures implemented by the Company for the three months ended June 30, 2016 as a response to low commodity prices, partially offset by costs associated with potential acquisition opportunities incurred during the three months ended June 30, 2016. Non-cash stock based compensation and other general and administrative expenses for the three months ended June 30, 2016 and 2015 are summarized in the following table:

 

General and administrative expenses
(in thousands)										Increase/
		2016				2015				(Decrease)
Stock-based compensation		$	292			$	368			$	(76	)
Other general and administrative expenses			1,260				1,423				(163	)
General and administrative expense, net		$	1,552			$	1,791			$	(239	)

 

Interest expense- Interest expense decreased from approximately $53,000 for the three months ended June 30, 2015 to approximately $46,000 for the three months ended June 30, 2016. In the second quarter of 2016, the Company had lower credit facility commitment fees as a result of the Company’s lender under the credit facility reducing the Company’s borrowing base in May 2016.

 

22

 

 

Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015

 

The following discussion and analysis relates to items that have affected our results of operations for the six months ended June 30, 2016 and 2015. 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.

 

		Six Months Ended
		June  30,								Percent
(in thousands except production and per unit data)		2016				2015				Change
Revenue:
Oil sales		$	1,436			$	3,083				(53	%)
Natural gas sales			2,053				2,886				(29	%)
Commodity derivative (loss) income			(634	)			147				*
Other income			1				18				*
Total revenues			2,856				6,134				(53	%)
Expenses:
Lease operating expenses			1,242				1,613				(23	%)
Transportation costs			758				755				-
Production and property taxes			259				429				(40	%)
General and administrative			3,075				3,666				(16	%)
Depreciation, depletion and amortization			938				1,341				(30	%)
Accretion of asset retirement obligations			70				63				11	%
Impairment of oil and gas properties			4,299				-				*
Total expenses			10,641				7,867				35	%
Operating loss		$	(7,785	)		$	(1,733	)			*
Other income and (expense):
Interest expense			(103	)			(97	)			6	%
Other income (expense)			17				(36	)			*
Equity investment loss			(6	)			(1	)			*
Total other expense		$	(92	)		$	(134	)			(31	%)
Production data:
Natural gas (Mcf)			994,897				971,012				2	%
Oil (Bbl)			37,904				56,812				(33	%)
Combined (Mcfe)			1,222,321				1,311,884				(7	%)
Average prices before effects of hedges:
Natural gas (per Mcf)		$	2.06			$	2.97				(31	%)
Oil (per Bbl)		$	37.88			$	54.27				(30	%)
Combined (per Mcfe)		$	2.85			$	4.55				(37	%)
Average prices after effects of hedges**:
Natural gas (per Mcf)		$	1.57			$	3.11				(50	%)
Oil (per Bbl)		$	34.16			$	54.51				(37	%)
Combined (per Mcfe)		$	2.34			$	4.66				(50	%)
Average costs (per Mcfe):
Lease operating expenses		$	1.02			$	1.23				(17	%)
Transportation costs		$	0.62			$	0.58				7	%
Production and property taxes		$	0.21			$	0.33				(36	%)
Depreciation, depletion and amortization		$	0.77			$	1.02				(25	%)

 

*	Not meaningful or applicable
**	Includes settled and unrealized commodity derivative gains and losses.

 

23

 

 

Oil and natural gas revenues- Revenues from sales of oil and natural gas decreased 42% to approximately $3.5 million for the six months ended June 30, 2016 from approximately $6.0 million for the six months ended June 30, 2015. This decrease was primarily due to a 30% and a 31% decrease in oil and natural gas prices, respectively. Oil sales volumes for the six month period ended June 30, 2016 decreased from the same period in 2015 by approximately 33%. The decrease in oil production was primarily attributed to normal natural production declines.

 

Commodity derivative income 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 and costless collars when our management believes that available futures prices for our oil and natural gas production are sufficient to warrant hedging to ensure predictable 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 six months ended June 30, 2016 we had hedging losses of approximately $634,000 compared to hedging gains of approximately $147,000 for the six months ended June 30, 2015.

 

Lease operating expenses- Lease operating expenses for the six months ended June 30, 2016 decreased 23% compared to the first six months of 2015. The decrease was primarily attributed to cost reduction initiatives and to lower water hauling and salt water disposal fees as a result of lower oil production. On a per Mcfe basis, lease operating expenses decreased from $1.23 per Mcfe for the six months ended June 30, 2015 to $1.02 per Mcfe for the six months ended June 30, 2016.

 

Transportation costs- Transportation costs for the six months ended June 30, 2016 were essentially flat compared to the six months ended June 30, 2015 as natural gas production was slightly higher for the six months ended June 30, 2016 as compared to the same period in 2015.

 

Production and property taxes- Production and property taxes decreased from approximately $429,000 for the six months ended June 30, 2015 to approximately $259,000 for the six months ended June 30, 2016. This decrease is primarily attributed to decreased oil and natural gas sales. Production taxes averaged 4.2% and 4.4% of oil and natural gas sales for the six months ended June 30, 2016 and 2015, respectively. 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 gas sales one or two years in arrears depending on the location of the production.

 

Depreciation, depletion and amortization (DD&A)- DD&A decreased from approximately $1.3 million for the six months ended June 30, 2015 to approximately $938,000 for the six months ended June 30, 2016 primarily due to a reduction in the Company’s depletion rate. The decrease in the depletion rate is primarily attributed to a reduction in the depletable asset base caused by impairment charges recognized in the fourth quarter of 2015 and the first quarter of 2016. On a per Mcfe basis, DD&A decreased from $1.02 per Mcfe for the six months ended June 30, 2015 to $0.77 per Mcfe for the six months ended June 30, 2016.

 

Impairment of oil and gas properties- Due to low commodity prices used in the ceiling calculation based on the required trailing 12-month average at March 31, 2016 and June 30, 2016, the Company had impairment expenses of approximately $4.3 million for the six months ended June 30, 2016. The Company did not record an impairment for the six months ended June 30, 2015. 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.

 

24

 

 

General and administrative expenses- General and administrative expenses decreased from approximately $3.7 million for the six months ended June 30, 2015 to approximately $3.1 million for the six months ended June 30, 2016. This decrease in general and administrative expenses is primarily attributed to personnel related cost reduction measures implemented by the Company for the six months ended June 30, 2016 as a response to low commodity prices, partially offset by costs associated with potential acquisition opportunities incurred during the six months ended June 30, 2016. Non-cash stock based compensation and other general and administrative expenses for the six months ended June 30, 2016 and 2015 are summarized in the following table:

 

General and administrative expenses
(in thousands)										Increase
		2016				2015				(Decrease)
Stock-based compensation		$	663			$	699			$	(36	)
Other general and administrative expenses			2,412				2,967				(555	)
General and administrative expense, net		$	3,075			$	3,666			$	(591	)

 

Interest expense- Interest expense increased from approximately $97,000 for the six months ended June 30, 2015 to approximately $103,000 for the six months ended June 30, 2016. This increase is primarily attributed to higher average debt balances in the six month period of 2016 as compared to the same period in 2015, partially offset by lower credit facility commitment fees as a result of the Company’s lender under the credit facility reducing the Company’s borrowing base in May 2016.

 

Liquidity and Capital Resources

 

Our exploration, development, and acquisition activities require us to make operating and capital expenditures. Historically, we have used cash flow from operations and our bank credit facility as our primary sources of liquidity, and, on occasion, we have engaged in asset monetization transactions.

 

Changes in the market prices for oil and natural gas directly impact our level of cash flow generated from operations. We employ a commodity hedging strategy in an attempt to moderate the effects of wide fluctuations in commodity prices on our cash flow. As of June 30, 2016, we have outstanding natural gas hedges of 290,000 MMBtu for the remainder of 2016 at an average price of $2.76 per MMBtu, 850,000 MMBtu for 2017 at an average price of $2.84 per MMBtu and 100,000 MMBtu for 2018 at an average price of $3.00 per MMBtu. In addition, as of June 30, 2016, we have outstanding natural gas costless collars of 60,000 MMBtu with weighted average floor and ceiling prices of $2.75 and $3.40, respectively, for the remainder of 2016 and outstanding oil costless collars of 10,000 barrels with weighted average floor and ceiling prices of $48.50 and $57.95, respectively, for the remainder of 2016 and 18,000 barrels with weighted average floor and ceiling prices of $48.33 and $61.67, respectively, for 2017. This level of hedging will provide a measure of certainty of the cash flow that we will receive for a portion of our production in 2016, 2017 and 2018. 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. As of June 30, 2016, our derivative counterparty, or its affiliates, was party to our credit facility.

 

The other primary source of liquidity historically has been our credit facility (described below). On May 17, 2016, Nytis LLC entered into an amendment to its credit facility with Bank of Oklahoma that reduced the borrowing base under the credit facility from $20.0 million to $5.5 million (of which $500,000 is reserved for future interest payments as those payments become due under the credit facility) and changed the maturity date of the credit facility from May 31, 2017 to January 2, 2017. As a result of the reduction in the borrowing base (and associated borrowing base capacity) and continuation of low commodity prices, the Company is not in compliance with the financial covenants under the credit facility as of June 30, 2016 (nor does it expect to be throughout the remainder of the year) and Bank of Oklahoma has curtailed the advancement of funds under the credit facility. Due to non-compliance with financial covenants, Bank of Oklahoma has the right to call a default under the credit facility. On June 30, 2016, Nytis LLC had $4.0 million in outstanding borrowings under the credit facility. The credit facility is secured by substantially all of our assets and matures in January 2017. See—“Bank Credit Facility” below for further details. On June 30, 2016, Nytis LLC had approximately $300,000 of available cash on hand. The Company has and will continue its cost reduction initiatives especially in regard to its general and administrative and lease operating expenses in an effort to conserve cash and meet its financial obligations.

 

With the change in the maturity date of the credit facility from May 31, 2017 to January 2, 2017, outstanding borrowings under the credit facility are classified as current on the Company’s Consolidated Balance Sheet resulting in negative working capital of approximately $8.5 million as of June 30, 2016.

 

25

 

 

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.

 

Based on our current outlook of commodity prices and our estimated production for 2016 together with cost reduction measures implemented in the first six months of 2016, we expect to fund our future activities primarily with cash flow from operations, sales of properties or the issuance of additional equity or debt. Such transactions, if any, will depend on general economic conditions, the 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 into 2016. We believe our advantages in this current economic environment include our inventory of drilling locations and acreage position, minimal capital expenditure obligations and status as a low cost operator. We expect that our net cash provided by operating activities will 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. As a result, our drilling activity will be limited throughout the remainder of 2016 unless we sell properties, or issue additional equity or debt. 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

 

On May 17, 2016, Nytis LLC entered into an amendment to its credit facility with Bank of Oklahoma that reduced the borrowing base under the credit facility from $20.0 million to $5.5 million (of which $500,000 is reserved for future interest payments as those payments become due under the credit facility) and changed the maturity date of the credit facility from May 31, 2017 to January 2, 2017. In addition, the amendment to the credit facility provided waivers from Bank of Oklahoma regarding Nytis LLC’s consistent past practice of advancing funding for general and administrative expenses of Carbon and ratified and affirmed the respective obligations for both Bank of Oklahoma and Nytis LLC under the credit facility.

 

A further lowering of the borrowing base could require us to repay indebtedness in excess of the borrowing base in order to cover the deficiency.

 

The facility has variable interest rates based upon the ratio of outstanding debt to the borrowing base. Interest rates are based on either an Alternate Base Rate or LIBOR. The portion of the loan based on an “Alternate Base Rate” is determined by the rate per annum equal to 1.5% plus the greatest of the following: (a) the Federal Funds Rate for such day plus one-half of one percentage point, (b) the Prime Rate for such day or (c) LIBOR for a one-month LIBOR Interest Period plus one percentage point. The portion based on LIBOR is determined by the rate per annum equal to LIBOR plus between 2.5% and 3.25% for each LIBOR tranche. The Company’s effective borrowing rate at June 30, 2016 was approximately 3.8%.

 

The credit facility includes terms that place limitations on certain types of activities, including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, dividends, mergers, and acquisitions, and requires satisfaction of a current ratio (the ratio of current assets (including borrowing base capacity) to current liabilities) of 1.0 to 1.0 and a maximum funded debt ratio (the ratio of the outstanding balance of all interest bearing indebtedness to the sum of EBITDAX (net income plus interest expense, income taxes, depreciation, depletion, amortization, exploration and impairment expenses and other non-cash charges)) of 4.25 to 1.0, for the most recently completed fiscal quarter times four. If we were to fail to perform our obligations under these covenants or other covenants and obligations, it could cause an event of default and the credit facility could be terminated and amounts outstanding could be declared immediately due and payable by the lenders, subject to notice and, in certain cases, cure periods. Such events of default include non-payment, breach of warranty, non-performance of financial covenants, default on other indebtedness, certain adverse judgments, change of control, and a failure of the liens securing the credit facility. In addition, bankruptcy and insolvency events with respect to Nytis LLC or certain of its subsidiaries will result in an automatic acceleration of the indebtedness under the credit facility.

 

In addition, the credit facility includes a hedging component that provides a line of credit under commodity swap, exchange, collar, cap and fixed price agreements and agreements designated to protect the Company against changes in interest and currency exchange rates. The maximum amount of credit on this line is $9.5 million.

 

As a result of the reduction in the borrowing base (and associated borrowing base capacity) and the continuation of low commodity prices, the Company was not in compliance on June 30, 2016 and continues to not be in compliance with the financial covenants under the credit facility (nor does it expect to be throughout the remainder of the year) and Bank of Oklahoma has curtailed the advancement of funds under the credit facility. Due to non-compliance with financial covenants, Bank of Oklahoma has the right to call a default under the credit facility. In the event a default is called, the credit facility could be terminated and amounts outstanding could be declared immediately due and payable by Bank of Oklahoma, subject to notice and, in certain cases, cure periods.

 

26

 

 

Historical Cash Flow

 

Net cash provided by or used in operating, investing and financing activities for the six months ended June 30, 2016 and 2015 were as follows:

 

		Six Months Ended
		June 30,
(in thousands)		2016				2015
Net cash (used in) provided by operating activities		$	(635	)		$	649
Net cash provided by (used in) investing activities		$	99			$	(1,847	)
Net cash provided by financing activities		$	497			$	641

 

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. Net cash provided by or used in operating activities decreased approximately $1.3 million for the six months ended June 30, 2016 as compared to the six months ended June 30, 2015, primarily due to a 30% and 31% decrease in oil and natural gas prices, respectively, and a 33% decrease in oil production.

 

Net cash provided by or used in 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 from investing activities increased approximately $1.9 million for the six months ended June 30, 2016 as compared to the six months ended June 30, 2015. Due to low oil and natural gas prices, the Company continued to scale down its drilling and development program during the first six months of 2016, resulting in an approximate $2.1 million decrease of capital expenditures during the first six months of 2016 as compared to the same period in 2015.

 

The decrease in financing cash flows of approximately $144,000 for the six months ended June 30, 2016 as compared to the six months ended June 30, 2015 was primarily due to a reduction in the Company’s borrowings from its credit facility.

 

Capital Expenditures

 

Capital expenditures incurred for the six months ended June 30, 2016 and 2015 are summarized in the following table:

 

		Six Months Ended June 30,
(in thousands)		2016				2015
Unevaluated property acquisitions		$	91			$	232
Drilling and development			101				1,600
Other			41				511
Total capital expenditures		$	233			$	2,343

 

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

 

Due to the higher rate of return on invested capital on oil wells versus natural gas wells, the Company’s capital expenditure program has, since 2012, focused principally on the development of its oil prospects. In addition, we managed our capital expenditures by keeping our exploration and development capital spending near our cash flows. We have been able to expand our oil drilling program by entering into two separate drilling programs with Liberty, the latter of which was entered into in 2014. Other factors impacting the level of our capital expenditures include oil and natural gas prices, the volatility in these prices, the cost and availability of oil field services, general economic and market conditions, and weather disruptions. Due to low commodity prices, the Company, since 2015, has curtailed its drilling programs and has focused on expanding its gathering facilities, thereby providing greater flexibility in moving certain of the Company’s natural gas to markets with more favorable pricing.

 

27

 

 

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 June 30, 2016, the off-balance sheet arrangements and transactions that we have entered into include (i) operating lease agreements and (ii) contractual obligations, such as natural gas transportation contracts, for which the ultimate settlement amounts are not fixed and determinable, 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.

 

Reconciliation of Non-GAAP Measures

 

EBITDA and Adjusted EBITDA

 

“EBITDA” and “Adjusted EBITDA” are non-GAAP financial measures. We define EBITDA as net income or 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 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 flows 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 and 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 our 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.

 

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The following table represents a reconciliation of our net earnings or losses, the most directly comparable GAAP measure to EBITDA and Adjusted EBITDA for the three and six months ended June 30, 2016 and 2015.

 

		Three Months Ended
		June 30,
(in thousands)		2016				2015
Net loss		$	(2,634	)		$	(1,209	)
Adjustments:
Interest expense			46				53
Depreciation, depletion and amortization			436				696
EBITDA			(2,152	)			(460	)
Adjusted EBITDA
EBITDA			(2,152	)			(460	)
Adjustments:
Non-cash stock-based compensation			292				368
Impairment of oil and gas properties			409				-
Accretion of asset retirement obligations			35				32
Adjusted EBITDA		$	(1,416	)		$	(60	)

 

		Six Months Ended
		June 30,
(in thousands)		2016				2015
Net loss		$	(7,877	)		$	(1,867	)
Adjustments:
Interest expense			103				97
Depreciation, depletion and amortization			938				1,341
EBITDA			(6,836	)			(429	)
Adjusted EBITDA
EBITDA			(6,836	)			(429	)
Adjustments:
Non-cash stock-based compensation			663				699
Impairment of oil and gas properties			4,299				-
Accretion of asset retirement obligations			70				63
Adjusted EBITDA		$	(1,804	)		$	333

 

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;

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	●	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.

 

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 June 30, 2016. 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 June 30, 2016 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 June 30, 2016 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

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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 June 30, 2016 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 August 9 2016 pursuant to the Carbon Plans, the Company granted 900,000 restricted shares to certain of its employees. To the extent these stock grants constitute 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(ii)		Amended and Restated Bylaws incorporated by reference to exhibit 3(i) to Form 8-K
		filed on May 5, 2015.
10.1*		Fifth Amendment of Amended and Restated Credit Agreement, Limited Waiver and Borrowing Base Redetermination, by and between Nytis Exploration Company LLC and Bank of Oklahoma, National Association, dated May 31, 2010 as amended on May 17, 2016.
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

 

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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: August 15, 2016	By:	/s/ Patrick R. McDonald
		PATRICK R. MCDONALD,
		Chief Executive Officer
Date: August 15, 2016	By:	/s/ Kevin D. Struzeski
		KEVIN D. STRUZESKI
		Chief Financial Officer

 

 

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