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 September 30, 2015

 

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 November 10, 2015, there were 107,549,227 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		2
	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		32
Part II – OTHER INFORMATION
Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds		33
Item 6.  Exhibits		34

 

 

PART I. FINANCIAL INFORMATION

 

ITEM 1. Financial Statements

 

CARBON NATURAL GAS COMPANY

Consolidated Balance Sheets

 

		September 30,				December 31,
(in thousands)		2015				2014
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	767			$	1,132
Accounts receivable:
Revenue			1,329				2,287
Joint interest billings and other			441				1,038
Commodity derivative asset			453				1,322
Prepaid expense, deposits and other current assets			192				141
Total current assets			3,182				5,920
Property and equipment (note 4):
Oil and gas properties, full cost method of accounting:
Proved, net			30,796				30,698
Unevaluated			3,176				2,789
Other property and equipment, net			234				304
			34,206				33,791
Investments in affiliates (note 5)			1,015				1,009
Other long-term assets			417				911
Total assets		$	38,820			$	41,631
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities		$	6,147			$	7,792
Firm transportation contract obligations (note 12)			441				487
Total current liabilities			6,588				8,279
Non-current liabilities:
Asset retirement obligations (note 2)			3,063				2,968
Firm transportation contract obligations (note 12)			524				852
Notes payable (note 6)			3,300				2,100
Total non-current liabilities			6,887				5,920
Commitments (note 12)
Stockholders’ equity:
Preferred stock, $0.01 par value; authorized 1,000,000  shares, no shares issued and outstanding at September 30, 2015 and December 31, 2014			-				-
Common stock, $0.01 par value; authorized 200,000,000 shares, 107,549,227 and 106,875,447 shares issued and outstanding at September 30, 2015 and December 31, 2014, respectively			1,075				1,069
Additional paid-in capital			53,980				53,160
Accumulated deficit			(32,601	)			(29,832	)
Total Carbon stockholders’ equity			22,454				24,397
Non-controlling interests			2,891				3,035
Total stockholders’ equity			25,345				27,432
Total liabilities and stockholders’ equity		$	38,820			$	41,631

 

See accompanying notes to Consolidated Financial Statements.

 

 

CARBON NATURAL GAS COMPANY

Consolidated Statements of Operations

(Unaudited)

 

		Three Months Ended September 30,								Nine Months Ended September 30,
(in thousands except per share amounts)		2015				2014				2015				2014
Revenue:
Oil and gas		$	2,671			$	5,664			$	8,640			$	17,710
Commodity derivative gain (loss)			353				689				500				(79	)
Other income			53				82				71				254
Total revenue			3,077				6,435				9,211				17,885
Expenses:
Lease operating expenses			717				786				2,330				2,523
Transportation costs			496				450				1,251				1,341
Production and property taxes			334				481				763				1,350
General and administrative			1,830				1,698				5,496				4,617
Depreciation, depletion and amortization			611				815				1,952				2,307
Accretion of asset retirement obligations			32				29				95				87
Total expenses			4,020				4,259				11,887				12,225
Operating (loss) income			(943	)			2,176				(2,676	)			5,660
Other income and (expense):
Interest expense			(52	)			(116	)			(149	)			(362	)
Equity investment income			7				2				6				7
Other income (expense)			21				-				(15	)			-
Total (expense)			(24	)			(114	)			(158	)			(355	)
(Loss) income before income taxes			(967	)			2,062				(2,834	)			5,305
Provision for income taxes			-				-				-				-
Net (loss) income before non-controlling interests			(967	)			2,062				(2,834	)			5,305
Net (loss) income attributable to non-controlling interests			(9	)			49				(65	)			203
Net (loss) income attributable to controlling interest		$	(958	)		$	2,013			$	(2,769	)		$	5,102
Net (loss) income per common share:
Basic		$	(0.01	)		$	0.02			$	(0.03	)		$	0.05
Diluted		$	(0.01	)		$	0.02			$	(0.03	)		$	0.04
Weighted average common shares outstanding:
Basic			107,047				105,683				106,720				110,196
Diluted			107,047				110,808				106,720				115,292

 

See accompanying notes to Consolidated Financial Statements.

 

 

CARBON NATURAL GAS COMPANY

Consolidated Statement of Stockholders’ Equity

(Unaudited)

(in thousands)

 

										Additional				Non-								Total
		Common Stock								Paid-in				Controlling				Accumulated				Stockholders’
		Shares				Amount				Capital				Interests				Deficit				Equity
Balances, December 31, 2014			106,875			$	1,069			$	53,160			$	3,035			$	(29,832	)		$	27,432
Stock-based compensation			-				-				1,071				-				-				1,071
Restricted stock activity including vesting and shares exchanged for tax withholding			674				6				(251	)			-				-				(245	)
Non-controlling interests distributions, net			-				-				-				(79	)			-				(79	)
Net loss			-				-				-				(65	)			(2,769	)			(2,834	)
Balances, September 30, 2015			107,549			$	1,075			$	53,980			$	2,891			$	(32,601	)		$	25,345

 

See accompanying notes to Consolidated Financial Statements.

 

 

CARBON NATURAL GAS COMPANY

Consolidated Statements of Cash Flows

(Unaudited)

 

		Nine Months Ended
		September 30,
(in thousands)		2015				2014
Cash flows from operating activities:
Net (loss) income		$	(2,834	)		$	5,305
Items not involving cash:
Depreciation, depletion and amortization			1,952				2,307
Accretion of asset retirement obligations			95				87
Unrealized commodity derivative loss (gain)			779				(477	)
Stock-based compensation expense			1,071				1,101
Equity investment income			(6	)			(7	)
Gain on disposition of other fixed asset			(12	)			-
Net change in:
Accounts receivable			1,680				38
Prepaid expenses, deposits and other current assets			(51	)			(64	)
Accounts payable, accrued liabilities and firm transportation obligations			(1,795	)			576
							-
Net cash provided by operating activities			879				8,866
Cash flows from investing activities:
Development and acquisition of properties and equipment			(2,648	)			(8,855	)
Proceeds from sale of oil and gas properties			68				2,800
Other long-term assets			459				30
Net cash used in investing activities			(2,121	)			(6,025	)
Cash flows from financing activities:
Purchase of common stock			(244	)			(3,437	)
Proceeds from notes payable			1,800				5,200
Payments on notes payable			(600	)			(4,100	)
Distributions to non-controlling interests			(79	)			(233	)
Net cash provided by (used in) financing activities			877				(2,570	)
Net (decrease) increase in cash and cash equivalents			(365	)			271
Cash and cash equivalents, beginning of period			1,132				243
Cash and cash equivalents, end of period		$	767			$	514

  

See accompanying notes to Consolidated Financial Statements.

 

 

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 – Summary of Significant Accounting Policies

 

Basis of Presentation

 

The accompanying unaudited Consolidated Financial Statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In the opinion of management, the accompanying unaudited Consolidated Financial Statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of September 30, 2015, the Company’s results of operations for the three and nine months ended September 30, 2015 and 2014 and the Company’s cash flows for the nine months ended September 30, 2015 and 2014. Operating results for the three and nine months ended September 30, 2015 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 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, 2014 filed on Form 10-K with the Securities and Exchange Commission (“SEC”).

 

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

 

Principles of Consolidation

 

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

 

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

 

In accordance with established practice in the oil and gas industry, the Company’s 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.

 

 

Note 2 – Summary of Significant Accounting Policies (continued)

 

Accounting for Oil and Gas Operations

 

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

 

Unproved properties are excluded from amortized capitalized costs until it is determined whether or not proved reserves can be assigned to such properties. The Company assesses its unproved properties for impairment at least annually. Significant unproved properties are assessed individually.

 

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

 

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

 

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

 

For the three and nine months ended September 30, 2015 and 2014, the Company did not recognize a ceiling test impairment as the Company’s full cost pool did not exceed the ceiling limitations. In December 2014, proceeds from the sale of the Company’s interests below the Clinton Formation in certain leases in Kentucky and West Virginia, referred to as the Deep Rights, were credited to the Company’s full cost pool, which decreased the Company’s net book value of its full cost pool while increasing its ceiling test cushion. Future declines in oil and natural gas prices, and increases in future operating expenses and future development costs could result in impairments of our oil and gas properties in future periods. Because the ceiling test uses the previous twelve month period average commodity price, the effects of declining prices since mid-2014 will have a negative impact on the average price used to value our reserves which will lower the ceiling test value in future quarters and may result in an impairment of our oil and gas properties. 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, would not affect cash flow, but would 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 of each investment is made

 

 

Note 2 – Summary of Significant Accounting Policies (continued)

 

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

 

Asset Retirement Obligations

 

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

 

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

 

The following table is a reconciliation of the ARO for the nine months ended September 30, 2015 and 2014:

 

		Nine Months Ended September 30,
(in thousands)		2015				2014
Balance at beginning of period		$	2,968			$	2,699
Accretion expense			95				87
Additions assumed with consolidated partnerships			-				4
Additions during period			-				131
Balance at end of period		$	3,063			$	2,921

  

Earnings Per Common Share

 

Basic earnings or loss per common share is computed by dividing the net income or loss attributable to common shareholders for the period by the weighted average number of common shares outstanding during the period. The shares of restricted common stock granted to certain officers 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).

 

 

Note 2 – Summary of Significant Accounting Policies (continued)

 

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

 

		Three Months Ended September 30,								Nine Months Ended September 30,
(in thousands except per share amounts)		2015				2014				2015				2014
Net (loss) income		$	(958	)		$	2,013			$	(2,769	)		$	5,102
Basic weighted-average common shares outstanding during the period			107,047				105,683				106,720				110,196
Add dilutive effects of stock options, warrants and
non-vested shares of restricted stock			-				5,125				-				5,096
Diluted weighted-average common shares outstanding during the period			107,047				110,808				106,720				115,292
Basic net (loss) income per common share		$	(0.01	)		$	0.02			$	(0.03	)		$	0.05
Diluted net (loss) income per common share		$	(0.01	)		$	0.02			$	(0.03	)		$	0.04

  

For the three and nine months ended September 30, 2015, the Company had a net loss and therefore, the diluted net loss per share calculation excluded the anti-dilutive effect of approximately 163,000 stock options, 250,000 warrants and approximately 5.0 million nonvested shares of restricted stock. In addition, approximately 6.3 million restricted performance units, subject to future contingencies, were excluded from the basic and diluted loss per share calculation. For the three and nine months ended September 30, 2014, the diluted income per common share calculation excludes the dilutive effect of approximately 250,000 warrants that were out-of-the-money. In addition, 4.7 million restricted performance units, subject to future contingencies, were excluded from the basic and diluted income per share calculation.

 

Note 3– Acquisitions and Dispositions

 

On December 15, 2014, Nytis LLC together with Liberty Energy LLC (the “Sellers”), completed a preliminary closing in accordance with a Purchase and Sale Agreement (the “PSA”) entered into on October 15, 2014 for the sale of a portion of Nytis LLC’s interest in rights below the base of the Clinton Formation (the “Deep Rights”) underlying certain oil and gas leases located in Kentucky and West Virginia.

 

Pursuant to the PSA, the Sellers reserved (i) a minority working interest in the Deep Rights, (ii) an overriding royalty interest in certain of the Deep Rights and (iii) all rights from the surface to the base of the Clinton formation underlying the leases. In connection with the preliminary closing of this transaction, Nytis LLC received approximately $12.4 million.

 

On June 5, 2015, the final closing was completed. In connection with the final closing of this transaction, Nytis LLC received an additional $42,000 in cash.

 

 

Note 4 – Property and Equipment

 

Net property and equipment as of September 30, 2015 and December 31, 2014 consists of the following:

 

(in thousands)		September 30, 2015				December 31, 2014
Oil and gas properties:
Proved oil and gas properties		$	97,177			$	95,233
Unproved properties not subject to depletion			3,176				2,789
Accumulated depreciation, depletion, amortization and impairment			(66,381	)			(64,535	)
Net oil and gas properties			33,972				33,487
Furniture and fixtures, computer hardware and software, and other equipment			819				1,131
Accumulated depreciation and amortization			(585	)			(827	)
Net other property and equipment			234				304
Total net property and equipment		$	34,206			$	33,791

 

As of September 30, 2015 and December 31, 2014, the Company had approximately $3.2 million and $2.8 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 three months ended September 30, 2015 and 2014, the Company capitalized general and administrative expenses applicable to development and exploration activities of approximately $133,000 and $121,000, respectively. During the nine months ended September 30, 2015 and 2014, the Company capitalized general and administrative expenses applicable to development and exploration activities of approximately $421,000 and $379,000, respectively.

 

Depletion expense related to oil and gas properties for the three months ended September 30, 2015 and 2014 was approximately $578,000, or $0.87 per Mcfe, and approximately $779,000, or $1.05 per Mcfe, respectively. For the nine months ended September 30, 2015 and 2014, depletion expense was approximately $1.8 million, or $0.94 per Mcfe, and approximately $2.2 million, or $1.00 per Mcfe, respectively.

 

Depreciation and amortization expenses related to furniture and fixtures, computer hardware and software and other equipment for the three months ended September 30, 2015 and 2014 were approximately $34,000 and $36,000, respectively, and for the nine months ended September 30, 2015 and 2014 were approximately $106,000 and $114,000, 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. During the nine month periods ended September 30, 2015 and 2014, the Company recorded equity method income of approximately $6,000 and $7,000, respectively, related to this investment.

 

 

Note 6 – Bank Credit Facility

 

Nytis LLC’s credit facility with Bank of Oklahoma has a borrowing base of $20.0 million in addition to a maximum line of credit available under hedging arrangements of $9.5 million. The credit facility matures in May 2017. 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 both to repay principal at any time and to reborrow. Subject to the agreement between the Company and the lender, the size of the credit facility may be increased up to $50.0 million. 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 designated to protect the Company against changes in interest and currency exchange rates.

 

At September 30, 2015, there were approximately $3.3 million in outstanding borrowings and approximately $16.7 million of additional borrowing capacity available under the credit facility. The Company’s effective borrowing rate at September 30, 2015 was approximately 2.8%. 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.

 

Nytis LLC is in compliance with all covenants associated with the credit agreement as of September 30, 2015.

 

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 September 30, 2015, 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 September 30, 2015, the Company had 200,000,000 shares of common stock authorized with a par value of $0.01 per share, of which 107,549,227 were issued and outstanding and 1,000,000 shares of preferred stock authorized with a par value of $0.01 per share, none of which were issued and outstanding. During the first nine months of 2015, increases in the Company’s issued and outstanding common stock reflect restricted stock, net of shares exchanged for payroll tax obligations paid by the Company, that vested during the period.

 

 

Note 8 – Stockholders’ Equity (continued)

 

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 September 30, 2015, the Company has approximately 163,000 options outstanding and exercisable, 250,000 warrants outstanding and exercisable and approximately 979,000 shares of common stock outstanding that are subject to restricted stock agreements.

 

Nytis USA Restricted Stock Plan

 

As of September 30, 2015, there were approximately 979,000 shares of unvested restricted stock granted under the Nytis USA Restricted Stock Plan (“Nytis USA Plan”). The Company accounted for these grants at their intrinsic value. From the dates of grant through March 31, 2013, the Company estimated that none of these shares would vest and accordingly, no compensation cost had been recorded through March 31, 2013.

 

In June 2013, the vesting terms of these restricted stock grants were modified so that 25% of the shares would vest on the first of January from 2014 through 2017. As such, the Company 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 September 30, 2015 and 2014 and approximately $252,000 for the nine months ended September 30, 2015 and 2014. As of September 30, 2015, there was approximately $419,000 of unrecognized compensation costs related to these restricted stock grants which the Company expects will be recognized ratably over the next 1.3 years.

 

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 22.0 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 or consultant.

 

Restricted Stock

 

During the nine months ended September 30, 2015, approximately 1.7 million shares of restricted stock were granted under the terms of the Carbon Plans in addition to approximately 4.8 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 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 September 30, 2015, approximately 2.6 million of these restricted stock grants have vested.

 

Compensation costs recognized for these restricted stock grants were approximately $201,000 and $220,000 for the three months ended September 30, 2015 and 2014, respectively, and approximately $560,000 and $591,000 for the nine months ended September 30, 2015 and 2014, respectively. As of September 30, 2015, there was approximately $1.5 million of unrecognized compensation costs related to these restricted stock grants. This cost is expected to be recognized over the next 6.3 years.

 

 

Note 8 – Stockholders’ Equity (continued)

 

Restricted Performance Units

 

As of September 30, 2015, approximately 6.4 million shares of restricted performance units have been granted under the terms of the Carbon Plans. 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 the price of the Company’s stock, net asset value per share, net production per share and Adjusted EBITDA (defined as net income (loss) before interest expense, taxes, depreciation, depletion, amortization, accretion of asset retirement obligations, ceiling test write downs of oil and gas properties and the gain or loss on sold investments or properties) per share relative to a defined peer group and 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 6.3 million of the restricted performance units are outstanding as of September 30, 2015.

 

The Company accounts for the performance units granted during 2012, 2014 and 2015 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 September 30, 2015, the Company estimated that none of the performance units granted in 2012, 2014 and 2015 would vest due to change in control and other performance provisions and accordingly, no compensation cost has been recorded. As of September 30, 2015, if change in control provisions 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, 2014 and 2015 would be approximately $3.1 million.

 

The performance units granted in 2013 contain specific vesting provisions, no change in control provisions nor any performance conditions other than stock price performance. Due to different earning requirements compared to the performance units granted in 2012, 2014 and 2015, 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 $86,000 for the three months ended September 30, 2015 and 2014, and approximately $259,000 for the nine months ended September 30, 2015 and 2014. As of September 30, 2015, there was approximately $214,000 of unrecognized compensation costs related to performance units granted in 2013. These costs are expected to be recognized over the next 9 months.

 

Note 9 – Accounts Payable and Accrued Liabilities

 

Accounts payable and accrued liabilities at September 30, 2015 and December 31, 2014 consist of the following:

 

		September 30,				December 31,
(in thousands)		2015				2014
Accounts payable		$	747			$	742
Oil and gas revenue payable to oil and gas property owners			1,022				1,296
Production taxes payable			85				132
Drilling advances received from joint venture partner			2,113				2,354
Accrued drilling costs			-				166
Accrued lease operating costs			86				74
Accrued ad valorem taxes			916				1,194
Accrued general and administrative expenses			1,007				1,247
Accrued income taxes payable			-				377
Other accrued liabilities			171				210
Total accounts payable and accrued liabilities		$	6,147			$	7,792

 

 

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 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 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.

 

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2015 and December 31, 2014 by level within the fair value hierarchy:

 

		Fair Value Measurements Using
(in thousands)		Level 1				Level 2				Level 3				Total
September 30, 2015
Assets:
Commodity derivatives		$	-			$	543			$	-			$	543
December 31, 2014
Assets:
Commodity derivatives		$	-			$	1,322			$	-			$	1,322

 

As of September 30, 2015, the Company’s commodity derivative financial instruments are comprised of six natural gas swap agreements and one gas and three oil costless collar agreements. The fair values of these agreements are determined under an income valuation technique. The valuation models require 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.

 

 

Note 10 – Fair Value Measurements (continued)

 

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 nine months ended September 30, 2015 and 2014, the Company recorded asset retirement obligations for additions of approximately nil and $135,000, respectively. See Note 2 for additional information.

 

Note 11 – Physical Delivery Contracts and Commodity Derivatives

 

The Company has historically used commodity-based derivative contracts to manage exposure to commodity prices 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 oil and natural gas physical delivery contracts to effectively provide 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. At September 30, 2015, these physical oil and gas sales contracts provide for sale prices that approximate regional market index prices.

 

The Company’s costless collar and swap derivative agreements as of September 30, 2015 are summarized in the table below:

 

		Natural Gas								Oil
						Weighted								Weighted
						Average								Average
Quarter		MMBtu				Price (a)(c)				Bbl				Price (b)(c)
Swaps:
Oct - Dec 2015			180,000			$	4.05				-				-
Jan - Mar 2016			60,000			$	3.66				-				-
Apr - Jun 2016			40,000			$	3.39				-				-
Jul - Sep 2016			30,000			$	3.12				-				-
Oct - Dec 2016			30,000			$	3.12				-				-
Jan - Mar 2017			30,000			$	3.27				-				-
Apr - Jun 2017			30,000			$	3.27				-				-
Jul - Sep 2017			30,000			$	3.27				-				-
Oct - Dec 2017			30,000			$	3.27				-				-
Collars:
Oct – Dec 2015			-				-				3,000			$	50.00-$57.50
Jan – Mar 2016			30,000			$	2.75-$3.40				6,000			$	50.00-$59.00
Apr – Jun 2016			30,000			$	2.75-$3.40				6,000			$	50.00-$59.00
Jul – Sep 2016			30,000			$	2.75-$3.40				4,000			$	50.00-$59.75
Oct – Dec 2016			30,000			$	2.75-$3.40				3,000			$	50.00-$60.50
Jan – Mar 2017			-				-				3,000			$	50.00-$66.00
Apr – Jun 2017			-				-				3,000			$	50.00-$66.00
Jul – Sep 2017			-				-				3,000			$	50.00-$66.00
Oct – Dec 2017			-				-				3,000			$	50.00-$66.00

 

(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 and ceiling prices.

 

 

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

 

For its swap instruments, the Company receives a fixed price for the hedged commodity and pays a floating price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

 

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

 

(in thousands)		September 30, 2015				December 31, 2014
Commodity derivative contracts:
Current assets		$	453			$	1,322
Long term-assets			90				-

 

The table below summarizes the commodity settlements and unrealized gains and losses related to the Company’s derivative instruments for the three and nine months ended September 30, 2015 and 2014. These commodity derivative settlements and unrealized gains or losses are recorded and included in commodity derivative gain or loss in the accompanying Consolidated Statements of Operations.

 

		Three Months Ended September 30,								Nine Months Ended      September 30,
(in thousands)		2015				2014				2015				2014
Commodity derivative contracts:
Settlement gains (losses )		$	368			$	(54	)		$	1,279			$	(556	)
Unrealized (losses) gains			(15	)			743				(779	)			477
Total settlement and unrealized gains(losses), net		$	353			$	689			$	500			$	(79	)

  

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

 

 

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

 

The counterparty in all of the Company’s derivative instruments is the lender in the Company’s 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 September 30, 2015, as well as the gross recognized derivative assets, liabilities and amounts offset in the Consolidated Balance Sheet:

 

										Net
		Gross								Recognized
		Recognized				Gross				Fair Value
Balance Sheet Classification		Assets/				Amounts				Assets/
(in thousands)		Liabilities				Offset				Liabilities
Commodity derivative assets:
Current derivative assets		$	491			$	(38	)		$	453
Other long-term assets			138				(48	)			90
Total derivative assets		$	629			$	(86	)		$	543
Commodity derivative liabilities:
Current derivative liabilities			38				(38	)			-
Non-current derivative liabilities			48				(48	)			-
Total derivative liabilities		$	86			$	(86	)		$	-

  

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

 

Note 12 – Commitments

 

The Company has entered into long-term firm transportation contracts to ensure the transport for certain of its gas production to purchasers. Firm transportation volumes and the related demand charges for the remaining term of these contracts at September 30, 2015 are summarized in the table below.

 

Period		Dekatherms per day				Demand Charges
Oct 2015			5,950			$	0.20 - $0.65
Nov 2015 - 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 $965,000 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 September 30, 2015. 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 nine months ended September 30, 2015 and 2014 are presented below:

 

		Nine Months Ended September 30,
(in thousands)		2015				2014
Cash paid during the period for:
Interest payments		$	121			$	328
Income taxes		$	325			$	-
Non-cash transactions:
Increase in net asset retirement obligations		$	-			$	135
Decrease in accounts payable and accrued liabilities included in oil  and gas properties		$	(225	)		$	(277	)
Decrease in accounts receivables due from partners assumed in acquisition of partnership interests		$	-			$	2

 

Note 14 – Adopted and Recently Issued Accounting Pronoucements

 

In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”). The objective of ASU 2015-03 is to simplify the presentation of debt issuance costs in financial statements by presenting such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. In August 2015, the FASB issued Accounting Standards Update No. 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements (“ASU 2015-15”). This ASU amends ASU 2015-03 which had not addressed the balance sheet presentation of debt issuance costs incurred in connection with line-of-credit arrangements. Under ASU 2015-15, a Company may defer debt issuance costs associated with line-of-credit arrangements and present such costs as an asset, subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings. ASU 2015-03 and ASU 2015-15 are effective for fiscal years, and interim periods, within those fiscal years, beginning after December 15, 2015 and should be applied retrospectively. Early adoption is permitted. The adoption of these standards will not have an impact on the Company’s Consolidated Financial Statements, other than balance sheet reclassifications.

 

In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The objective of ASU 2014-09 is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. ASU 2014-09 was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, however in August 2015, the FASB issued Accounting Standards Update No. 2015-14, Revenue from Contracts with Customer: Deferral of the Effective Date (“ASU 2015-14”), which deferred the effective date of ASU 2014-09 for one year. ASU 2015-14 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. The standards permit retrospective application using either of the following methodologies: (i) restatement of each prior reporting period presented or (ii) recognition of a cumulative effect adjustment as of the date of initial application. The Company is currently evaluating the impact of adopting ASU 2014-09 and ASU 2015-14, including the transition method to be applied, however the standards are not expected to have a significant effect on its Consolidated Financial Statements.

 

 

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 2014 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 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 September 30, 2015, our proved developed reserves were comprised of 10% oil and 90% natural gas. Our 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 natural gas properties. Our growth plan is centered on the following activities:

 

	●	Development of the Company’s oil and coalbed methane reserves;
	●	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.

 

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. Oil and gas prices historically have been volatile and may fluctuate widely in the future. Our financial results are sensitive to fluctuations in oil and natural gas prices. The following table highlights the quarterly average of NYMEX price trends for oil and natural gas prices for the last eight calendar quarters:

 

		2013				2014																2015
		Q4				Q1				Q2				Q3				Q4				Q1				Q2				Q3
Oil (Bbl)		$	97.50			$	98.62			$	102.98			$	97.21			$	73.12			$	48.57			$	57.96			$	46.44
Natural Gas (MMBtu)		$	3.60			$	4.93			$	4.68			$	4.07			$	4.04			$	2.99			$	2.61			$	2.74

 

Average oil prices received by the Company for the three and nine months ended September 30, 2015 have fallen 49% and 46%, respectively, as compared to the three and nine months ended September 30, 2014. Average natural gas prices received by the Company for the three and nine months ended September 30, 2015 are 34% and 40% lower, respectively, compared to the three and nine months ended September 30, 2014. Lower oil and natural gas prices may decrease the Company’s revenues and may also reduce the value of its oil and natural gas reserves. The Company’s estimated proved reserves may decrease as the economic life of the underlying producing wells may be shortened as a result of lower oil and natural gas prices. 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 compared to 2014 will be lower ceiling values each quarter. For the three and nine months ended September 30, 2015, the Company did not recognize a ceiling test impairment as the Company’s full cost pool did not exceed the ceiling limitation. The Company’s “ceiling test cushion” has decreased substantially during the first nine months of 2015 and is expected to decrease further, potentially resulting in impairment charges during 2015 or until prices stabilize or improve over the twelve month period.

 

 

At September 30, 2015, commodity prices used in the ceiling calculations, based on the required trailing twelve month average, were $3.12 per Mcf of gas and $53.79 per barrel of oil and resulted in a ceiling test cushion of approximately $1.4 million. If the commodity prices had been calculated based on a twelve month simple average of the commodity prices on the first day of the month for the ten months ended October 2015 and the prices for October 2015 were used for the remaining two months in the twelve month average, prices would have averaged $2.72 per Mcf of gas and $44.95 per barrel of oil. Based solely on these lower prices and holding all other factors constant, we would have had a ceiling test impairment of approximately $5.9 million. 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, this 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. An extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, cash flows and liquidity. Lower oil and natural gas prices may also reduce the amount of borrowing base under our bank credit facility, which is determined at the discretion of our lender.

 

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. Any future acquisitions may be financed with available borrowings under our credit facility, sales of properties or the issuance of additional equity or debt.

 

Operational Highlights

 

At September 30, 2015, we had over 272,000 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 23% 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 is directed at a Berea Sandstone Formation horizontal oil drilling program in eastern Kentucky and western West Virginia. At September 30, 2015, we have over 43,000 net mineral acres in the development area. Since 2010, we have drilled 54 gross horizontal wells in the Berea formation. During the program, we have enhanced our well performance, improved well drilling and completion performance, including reduced drilling days, increased horizontal lateral length, decreased cost per frac stage and reduced days from spud to first production. In addition, we have established an infrastructure of oil and natural gas gathering and salt water handling and disposal facilities which will benefit the economics of future drilling. We continue to acquire leases and producing properties in the areas 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 67,000 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. Recently, a stratigraphic drilling program has been conducted 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 for oil and natural gas, we have reduced our drilling activity to manage and optimize the utilization of our capital resources. During the nine months ended September 30, 2015, our capital expenditures consisted principally of completing wells that were in-progress at the end of 2014 and the expansion of our gathering facilities to provide greater flexibility in moving our natural gas production to markets with the most favorable price. Based on management’s current assessment of commodity prices and drilling costs and subject to permitting, the Company may drill a coalbed methane gas well in the Illinois Basin during the remainder of 2015. The Company is evaluating potential producing property, land and corporate acquisition opportunities that could expand the Company’s operations and provide attractive risk adjusted rates of returns.

 

During December 2014, Nytis LLC together with Liberty Energy LLC (“Liberty”) (the “Sellers”), completed a preliminary closing in accordance with a Purchase and Sale Agreement (the “PSA”) entered into during October 2014 for the sale of a portion of Nytis LLC’s interest in rights below the base of the Clinton Formation (the “Deep Rights”) underlying certain oil and gas leases located in Kentucky and West Virginia.

 

Pursuant to the PSA, the Sellers reserved (i) a minority working interest in the Deep Rights, (ii) an overriding royalty interest in certain of the Deep Rights and (iii) all rights from the surface to the base of the Clinton formation underlying the leases. In connection with the preliminary closing of this transaction, Nytis LLC received approximately $12.4 million.

 

On June 5, 2015, the final closing was completed. In connection with the final closing of this transaction, Nytis LLC received an additional $42,000 in cash.

 

In February 2014, Nytis LLC entered into a participation agreement with Liberty that allowed Liberty to participate with Nytis LLC in the drilling and completion of wells on certain of Nytis LLC’s leases located in Kentucky. Pursuant to the participation agreement, Liberty paid Nytis LLC approximately $2.8 million for a forty percent (40%) working interest in the covered leases and additional leases acquired post-closing. In accordance with the agreement, Liberty agreed to pay a disproportionate percentage of the costs associated with drilling and completing 20 wells on the covered leases.

 

The participation agreement also provided for the reservation by Nytis LLC of an overriding royalty interest with respect to covered leases that include an agreed upon minimum net revenue interest.

 

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 September 30, 2015, Liberty had participated in drilling of six horizontal wells pursuant to this agreement.

 

In August 2015, a Kentucky court ruled that, absent provisions in a lease, a lessee may not deduct severance taxes prior to paying royalties on natural gas production. The Company is currently evaluating the impact of this ruling and in the interim has established a reserve for potential additional production taxes on certain of its wells in Kentucky.

 

 

Results of Operations

 

Three Months Ended September 30, 2015 Compared to Three Months Ended September 30, 2014

 

The following discussion and analysis relates to items that have affected our results of operations for the three months ended September 30, 2015 and 2014. 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
		September 30,								Percent
(in thousands except production and per unit data)		2015				2014				Change
Revenue:
Oil and natural gas revenues		$	2,671			$	5,664				(53	%)
Commodity derivative gain			353				689				(49	%)
Other income			53				82				(35	%)
Total revenues			3,077				6,435				(52	%)
Expenses:
Lease operating expenses			717				786				(9	%)
Transportation costs			496				450				10	%
Production and property taxes			334				481				(31	%)
General and administrative			1,830				1,698				8	%
Depreciation, depletion and amortization			611				815				(25	%)
Accretion of asset retirement obligations			32				29				10	%
Total expenses			4,020				4,259				(6	%)
Operating (loss) income		$	(943	)		$	2,176				(143	%)
Other income and (expense):
Interest expense			(52	)			(116	)			(55	%)
Equity investment income			7				2				250	%
Other income			21				-				*
Total other expense		$	(24	)		$	(114	)			(79	%)
Production data:
Natural gas (Mcf)			526,085				539,369				(2	%)
Oil (Bbl)			22,631				33,863				(33	%)
Combined (Mcfe)			661,871				742,547				(11	%)
Average prices before effects of hedges:
Natural gas (per Mcf)		$	2.98			$	4.49				(34	%)
Oil (per Bbl)		$	48.78			$	95.72				(49	%)
Combined (per Mcfe)		$	4.04			$	7.63				(47	%)
Average prices after effects of hedges**:
Natural gas (per Mcf)		$	3.33			$	5.18				(36	%)
Oil (per Bbl)		$	56.20			$	105.06				(47	%)
Combined (per Mcfe)		$	4.57			$	8.56				(47	%)
Average costs (per Mcfe):
Lease operating expenses		$	1.08			$	1.06				2	%
Transportation costs		$	0.75			$	0.61				23	%
Production and property taxes		$	0.50			$	0.65				(23	%)
Depreciation, depletion and amortization		$	0.92			$	1.10				(16	%)

 

* Not meaningful or applicable

** Includes realized and unrealized commodity derivative gains and losses.

 

 

Oil and natural gas revenues- Revenues from sales of oil and natural gas decreased 53% to approximately $2.7 million for the three months ended September 30, 2015 from approximately $5.7 million for the three months ended September 30, 2014. This decrease was primarily due to a 49% and 34% decrease in oil and natural gas prices, respectively. Oil and natural gas sales volumes for the three months ended September 30, 2015 decreased 33% and 2%, respectively as compared to the same period in 2014. The declines in production are primarily attributed to normal natural production declines and less production during the period due to the lack of drilling activity compared to the same period in 2014.

 

Commodity derivative revenue- 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 realized 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 September 30, 2015 and 2014, we had hedging gains of approximately $353,000 and $689,000, respectively.

 

Lease operating expenses- Lease operating expenses for the three months ended September 30, 2015 decreased 9% compared to the three months ended September 30, 2014. The decrease in lease operating expenses for the three months ended September 30, 2015 as compared to the same period in 2014 was primarily attributed to lower water hauling and salt water disposal fees as a result of lower initial oil production, partially offset by increased well maintenance and workover costs incurred to maintain and/or improve production. On a per Mcfe basis, lease operating expenses increased from $1.06 per Mcfe for the three months ended September 30, 2014 to $1.08 per Mcfe for the three months ended September 30, 2015 due to lower production relative to fixed costs.

 

Transportation costs- Transportation costs for the three months ended September 30, 2015 increased 10% compared to the three months ended September 30, 2014. During the third quarter in 2015, the Company incurred additional transportation and gathering costs to move its gas to markets with more favorable pricing, thereby increasing the net price received by the Company for certain of its gas production, and to avoid pipeline and/or gathering system interruptions.

 

Production and property taxes- Production and property taxes decreased from approximately $481,000 for the three months ended September 30, 2014 to approximately $334,000 for the three months ended September 30, 2015. This decrease is primarily attributed to a 53% decrease in oil and natural gas sales revenues. The decrease was partially offset by a reserve established by the Company for potential additional production taxes on certain of its wells in Kentucky due to a recent court ruling.

 

For the three months ended September 30, 2015 and 2014, the Company’s production taxes averaged approximately 4.0% and 4.4% of oil and gas revenues, 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 revenues one or two years in arrears depending on the location of the production.

 

Depreciation, depletion and amortization (DD&A)- DD&A decreased from approximately $815,000 for the three months ended September 30, 2014 to approximately $611,000 for the three months ended September 30, 2015 primarily due to a decrease in oil and gas production. On a per Mcfe basis, these expenses decreased from $1.10 per Mcfe for the three months ended September 30, 2014 to $0.92 per Mcfe for the three months ended September 30, 2015.

 

 

General and administrative expenses- General and administrative expenses for the three months ended September 30, 2015 increased 8% over the same period in 2014. The increase in general and administrative expenses is primarily attributed to personnel related costs, costs associated with potential acquisition opportunities and lower drilling overhead reimbursements as a result of substantially less drilling activity in 2015 as compared to 2014.

 

										(Decrease)
		2015				2014				Increase
(in thousands)
Stock-based compensation		$	371			$	390			$	(19	)
Other general and administrative expenses			1,459				1,308				151
General and administrative expense, net		$	1,830			$	1,698			$	132

 

Interest expense- Interest expense decreased from approximately $116,000 for the three months ended September 30, 2014 to approximately $52,000 for the three months ended September 30, 2015 primarily due to lower outstanding debt balances. In December 2014, the Company reduced its outstanding debt by approximately $12.3 million with proceeds from the sale of its deep rights in certain leases in Kentucky and West Virginia.

 

 

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014

 

The following discussion and analysis relates to items that have affected our results of operations for the nine months ended September 30, 2015 and 2014. 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.

 

		Nine Months Ended
		September 30,								Percent
(in thousands except production and per unit data)		2015				2014				Change
Revenue:
Oil and natural gas revenues		$	8,640			$	17,710				(51	%)
Commodity derivative gain (loss)			500				(79	)			*
Other income			71				254				(72	%)
Total revenues			9,211				17,885				(48	%)
Expenses:
Lease operating expenses			2,330				2,523				(8	%)
Transportation costs			1,251				1,341				(7	%)
Production and property taxes			763				1,350				(43	%)
General and administrative			5,496				4,617				19	%
Depreciation, depletion and amortization			1,952				2,307				(15	%)
Accretion of asset retirement obligations			95				87				9	%
Total expenses			11,887				12,225				(3	%)
Operating (loss) income		$	(2,676	)		$	5,660				(147	%)
Other income and (expense):
Interest expense			(149	)			(362	)			(59	%)
Equity investment income			6				7				(14	%)
Other expense			(15	)			-				*
Total other expense		$	(158	)		$	(355	)			(54	%)
Production data:
Natural gas (Mcf)			1,497,097				1,605,907				(7	%)
Oil (Bbl)			79,443				99,772				(20	%)
Combined (Mcfe)			1,973,755				2,204,539				(10	%)
Average prices before effects of hedges:
Natural gas (per Mcf)		$	2.97			$	4.96				(40	%)
Oil (per Bbl)		$	52.70			$	97.64				(46	%)
Combined (per Mcfe)		$	4.38			$	8.03				(45	%)
Average prices after effects of hedges**:
Natural gas (per Mcf)		$	3.19			$	4.93				(35	%)
Oil (per Bbl)		$	54.99			$	97.42				(44	%)
Combined (per Mcfe)		$	4.63			$	8.00				(42	%)
Average costs (per Mcfe):
Lease operating expenses		$	1.18			$	1.14				4	%
Transportation costs		$	0.63			$	0.61				3	%
Production and property taxes		$	0.39			$	0.61				(36	%)
Depreciation, depletion and amortization		$	0.99			$	1.05				(6	%)

 

* Not meaningful or applicable

** Includes realized and unrealized commodity derivative gains and losses.

 

Oil and natural gas revenues- Revenues from sales of oil and natural gas decreased 51% to approximately $8.6 million for the nine months ended September 30, 2015 from approximately $17.7 million for the nine months ended September 30, 2014. This decrease was primarily due to a 46% and a 40% decrease in oil and natural gas prices, respectively. Oil and natural gas sales volumes for the nine month period ended September 30, 2015 decreased from the same period in 2014 by approximately 20% and 7%, respectively. The declines in production are primarily attributed to normal natural production declines and less production during the period due to the lack of drilling activity compared to the same period in 2014.

 

 

Commodity derivative revenue- 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 realized gains or losses on the derivative instruments, are currently recognized in our results of operations. The unrealized gains and losses represent the changes in the fair value of these contracts as oil and natural gas futures prices fluctuate relative to the fixed price we will receive from these contracts. For the nine months ended September 30, 2015 we had hedging gains of approximately $500,000 compared to hedging losses of approximately $79,000 for the nine months ended September 30, 2014.

 

Lease operating expenses- Lease operating expenses for the nine months ended September 30, 2015 decreased 8% compared to the first nine months of 2014. The decrease was primarily attributed to lower water hauling and salt water disposal fees as a result of lower initial oil production, partially offset by increased well maintenance and workover costs incurred to maintain and/or improve production. On a per Mcfe basis, lease operating expenses increased from $1.14 per Mcfe for the nine months ended September 30, 2014 to $1.18 per Mcfe for the nine months ended September 30, 2015 due to lower production relative to fixed costs.

 

Transportation costs- Transportation costs for the nine months ended September 30, 2015 decreased 7% compared to the nine months ended September 30, 2014 primarily due to a 7% decrease in natural gas production.

 

Production and property taxes- Production and property taxes decreased from approximately $1.4 million for the nine months ended September 30, 2014 to approximately $763,000 for the nine months ended September 30, 2015. This decrease is primarily attributed to a 51% decrease in oil and natural gas sales revenues. The decrease was partially offset by a reserve established by the Company for potential additional production taxes on certain of its wells in Kentucky due to a recent court ruling.

 

The Company’s production taxes average approximately 4.4% of oil and gas revenues. Ad valorem tax rates, which can fluctuate by year, are determined by individual counties where the Company has production and are assessed on the Company’s oil and gas revenues one or two years in arrears depending on the location of the production.

 

Depreciation, depletion and amortization (DD&A)- DD&A decreased from approximately $2.3 million for the nine months ended September 30, 2014 to approximately $2.0 million for the nine months ended September 30, 2015 primarily due to decreased oil and natural gas production. On a per Mcfe basis, these expenses decreased from $1.05 per Mcfe to $0.99 per Mcfe for the nine months ended September 30, 2015 and 2014.

 

General and administrative expenses- General and administrative expenses for the nine months ended September 30, 2015 increased $879,000 or 19%, from the nine months ended September 30, 2014. The increase in general and administrative expenses is primarily attributed to personnel related costs, costs associated with potential acquisition opportunities and lower drilling overhead reimbursements as a result of substantially less drilling activity in 2015 as compared to 2014.

 

										(Decrease)
		2015				2014				Increase
(in thousands)
Stock-based compensation		$	1,071			$	1,101			$	(30	)
Other general and administrative expenses			4,425				3,516				909
General and administrative expense, net		$	5,496			$	4,617			$	879

 

 

Interest expense- Interest expense decreased from approximately $362,000 for the nine months ended September 30, 2014 to approximately $149,000 for the nine months ended September 30, 2015 primarily due to lower outstanding debt balances. In December 2014, the Company reduced its outstanding debt by approximately $12.3 million with proceeds from the sale of its deep rights in certain leases in Kentucky and West Virginia.

 

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, as market conditions have permitted, 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 September 30, 2015, we have outstanding natural gas swaps of 180,000 MMBtu for the remainder of 2015 at an average price of $4.05 per MMBtu, 160,000 MMBtu for 2016 at a weighted average price of $3.39 per MMBtu and 120,000 MMBtu for 2017 at a weighted average price of $3.27 per MMBtu. In addition, as of September 30, 2015, we have outstanding natural gas costless collars of 120,000 MMBtu with weighted average floor and ceiling prices of $2.75 and $3.40 per MMBtu, respectively, for 2016 and outstanding oil costless collars of 3,000 barrels with weighted average floor and ceiling prices of $50.00 and $57.50 per barrel, respectively, for the remainder of 2015, 19,000 barrels with floor and ceiling prices of $50.00 and $59.39 per barrel, respectively, for 2016 and 12,000 barrels with floor and ceiling prices of $50.00 and $66.00 per barrel, 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 2015, 2016 and 2017. 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 September 30, 2015, our derivative counterparty, or its affiliates, was party to our credit facility.

 

The other primary source of liquidity is our credit facility (described below), which had an aggregate borrowing base of $20.0 million of which approximately $16.7 million was available as of September 30, 2015. This facility is used to fund operations, capital programs and acquisitions and to refinance debt, as needed and if available. The credit facility is secured by substantially all of our assets and matures in May 2017. See—“Bank Credit Facility” below for further details. We had $3.3 million drawn on our credit facility as of September 30, 2015.

 

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.

 

We believe we are well positioned for the current economic environment due to our low level of debt relative to our cash flow, access to undrawn debt capacity, our large inventory of drilling locations and acreage position, minimal capital expenditure obligations and our status as a low cost operator. We expect that our future cash flows provided by operating activities will be adversely affected by continued low commodity prices, however, we believe that future cash flows provided by operating activities and the $16.7 million of additional borrowing capacity available under our credit facility as of September 30, 2015, will be sufficient to fund our normal recurring operating needs, anticipated capital expenditures (other than the potential acquisition of additional oil and natural gas properties), and our contractual obligations. However, if our revenue and cash flow decrease in the future as a result of deterioration in domestic and global economic conditions or the continuation of the recent significant decline in oil and natural prices, we may elect to reduce our planned capital expenditures. We believe that our financial flexibility to adjust our spending levels will provide us with sufficient liquidity to meet our financial obligations should economic conditions deteriorate. See “Risk Factors, “in our Annual Report filed on Form 10-K with the SEC for a discussion of the risks and uncertainties that affect our business and financial and operating results.

 

 

Bank Credit Facility

 

Nytis LLC has a bank credit facility which consists of a $50.0 million credit facility (the “Credit Facility”) with Bank of Oklahoma. The Credit Facility will mature in May 2017 and is guaranteed by Nytis USA and Carbon. Our availability under the Credit Facility is governed by a borrowing base (the “Borrowing Base”), which at September 30, 2015 was $20.0 million. The determination of the Borrowing Base is made by the lender in its sole discretion, on a semi-annual basis, taking into consideration the estimated value of our oil and natural gas properties in accordance with the lender’s customary practices for oil and natural gas loans. The available borrowing amount under the Credit Facility could increase or decrease based on such redetermination. The next redetermination of the Borrowing Base is expected to occur in the latter part of November 2015. In addition to the semi-annual redeterminations, Nytis LLC and the lender each have discretion at any time, but not more often than once during a calendar year, to have the Borrowing Base redetermined.

 

A 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 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, 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)) 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.

 

Of the $50.0 million total nominal amount under the Credit Facility, Bank of Oklahoma holds 100% of the total commitments. As of September 30, 2015 there was approximately $3.3 million in borrowings under the Credit Facility. The Company’s effective borrowing rate at September 30, 2015 was approximately 2.8%.

 

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.

 

Historical Cash Flow

 

Net cash provided by or (used in) operating, investing and financing activities for the nine months ended September 30, 2015 and 2014 were as follows:

 

		Nine Months Ended
		September 30,
(in thousands)		2015				2014
Net cash provided by operating activities		$	879			$	8,866
Net cash used in investing activities		$	(2,121	)		$	(6,025	)
Net cash provided by (used in) financing activities		$	877			$	(2,570	)

 

 

Net cash provided by operating activities is primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and changes in working capital. Operating cash flows were approximately $8.0 million lower for the nine months ended September 30, 2015 as compared to the nine months ended September 30, 2014. This was primarily due to lower oil and natural gas revenues of approximately $9.1 million primarily attributed to lower oil and natural gas prices of 46% and 40%, respectively, and lower oil and natural gas production of 20% and 7%, respectively.

 

Net cash 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 used in investing activities was approximately $3.9 million lower for the nine months ended September 30, 2015 as compared to the nine months ended September 30, 2014. This was primarily due to a decrease of approximately $6.2 million in capital expenditures during the nine months of 2015 compared to the same period in 2014 due to the Company scaling down its drilling and development program of its oil properties as a result of the decline in oil prices, partially offset by net proceeds of approximately $2.8 million received in the nine months of 2014 from the sale of oil and gas properties.

 

The increase in financing cash flows of approximately $3.4 million for the nine months ended September 30, 2015 as compared to the nine months ended September 30, 2014 was primarily due to a purchase of approximately 8.2 million shares of the Company’s common stock for approximately $3.4 million in 2014.

 

Capital Expenditures

 

Capital expenditures incurred for the nine months ended September 30, 2015 and 2014 are summarized in the following table:

 

		Nine Months Ended September 30,
(in thousands)		2015				2014
Acquisition of oil and gas properties:
Unevaluated properties		$	291			$	1,502
Proved producing properties			-				99
Drilling and development			1,746				7,077
Other			611				177
Total capital expenditures		$	2,648			$	8,855

 

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 manage our capital expenditures by keeping our exploration and development capital spending near our cash flows. 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 the decline in oil and natural gas prices during the first nine months of 2015, the Company scaled back its drilling program to manage and optimize its utilization of capital expenditures.

 

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 September 30, 2015, the off-balance sheet arrangements and transactions that we have entered into include (i) operating lease agreements and (ii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as natural gas transportation commitments and (iii) oil and 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 (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 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 Nytis LLC’s credit facility.

 

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

 

 

The following table represents a reconciliation of our net income or loss, the most directly comparable GAAP measure to EBITDA and Adjusted EBITDA for the three and nine months ended September 30, 2015 and 2014.

 

		Three Months Ended
		September 30,
(in thousands)		2015				2014
Net (loss) income		$	(967	)		$	2,062
Adjustments:
Interest expense			52				116
Depreciation, depletion and amortization			611				815
EBITDA			(304	)			2,993
Adjusted EBITDA
EBITDA			(304	)			2,993
Adjustments:
Non-cash stock-based compensation			371				390
Accretion of asset retirement obligations			32				29
Adjusted EBITDA		$	99			$	3,412

 

		Nine Months Ended
		September 30,
(in thousands)		2015				2014
Net (loss) income		$	(2,834	)		$	5,305
Adjustments:
Interest expense			149				362
Depreciation, depletion and amortization			1,952				2,307
EBITDA			(733	)			7,974
Adjusted EBITDA
EBITDA			(733	)			7,974
Adjustments:
Non-cash stock-based compensation			1,071				1,101
Accretion of asset retirement obligations			95				87
Adjusted EBITDA		$	433			$	9,162

 

Forward Looking Statements

 

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

 

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

 

●

estimates of our oil and natural gas reserves;

 

●

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

 

●

our future financial condition and results of operations;

 

 

●

our future revenues, cash flows, and expenses;

 

●

our access to capital and our anticipated liquidity;

 

●

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

 

●

our outlook on oil and natural gas prices;

 

●

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

 

●

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

 

●

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

 

●

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

 

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 September 30, 2015. 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 September 30, 2015 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 September 30, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

PART II. OTHER INFORMATION

 

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

 

All sales of unregistered equity securities that occurred during the period covered by this report, and through September 30, 2015, have been previously reported on a current report on Form 8-K or in a quarterly report on Form 10-Q.

 

 

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 for Carbon Natural Gas Company incorporated by reference to exhibit 3(ii) to Form 10-Q for Carbon Natural Gas Company filed on August 3, 2015.
31.1*		Certification of Chief Executive Officer Pursuant to Rule 13a-15(e) / Rule 15d-15(e).
31.2*		Certification of Chief Financial Officer Pursuant to Rule 13a-14(a) / Rule 15(e)/15d-15(e).
32.1†		Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002.
32.2†		Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002.
101*		Interactive data files pursuant to Rule 405 of Regulation S-T.

 

*

Filed herewith

†

Not considered to be "filed" for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.

 

 

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

 

 

	CARBON NATURAL GAS COMPANY
	(Registrant)
Date: November 16, 2015	By:	/s/ Patrick R. McDonald
		PATRICK R. MCDONALD
		Chief Executive Officer
Date: November 16, 2015	By:	/s/ Kevin D. Struzeski
		KEVIN D. STRUZESKI
		Chief Financial Officer

 

 

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